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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


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

For The Quarterly Period Ended March 31, 2011

Commission
File Number
  Exact name of registrant as specified in its charter   IRS Employer
Identification No.
1-12869   CONSTELLATION ENERGY GROUP, INC.   52-1964611

100 CONSTELLATION WAY,                BALTIMORE, MARYLAND                21202
                                         (Address of principal executive offices)                        (Zip Code)

410-470-2800
(Registrant's telephone number, including area code)

1-1910

 

BALTIMORE GAS AND ELECTRIC COMPANY

 

52-0280210

2 CENTER PLAZA, 110 WEST FAYETTE STREET,                BALTIMORE, MARYLAND                21202
                                                         (Address of principal executive offices)                                              (Zip Code)

410-234-5000
(Registrant's telephone number, including area code)

MARYLAND
(State of Incorporation of both registrants)

NOT APPLICABLE
(Former name, former address and former fiscal year, if changed since last report)

         Indicate by check mark whether the registrants (1) have 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, and (2) have been subject to such filing requirements for the past 90 days. Yes ý        No o

         Indicate by check mark whether Constellation Energy Group, Inc. 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý        No o

         Indicate by check mark whether Baltimore Gas and Electric Company 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o        No o

         Indicate by check mark whether Constellation Energy Group, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
(Check one):

Large accelerated filer ý   Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller
reporting company)
  Smaller reporting company o

         Indicate by check mark whether Baltimore Gas and Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
(Check one):

Large accelerated filer o   Accelerated filer o   Non-accelerated filer ý
(Do not check if a smaller
reporting company)
  Smaller reporting company o

         Indicate by check mark whether Constellation Energy Group, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o        No ý

         Indicate by check mark whether Baltimore Gas and Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o        No ý

Common Stock, without par value 200,702,529 shares outstanding
of Constellation Energy Group, Inc. on April 29, 2011.

         Baltimore Gas and Electric Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form in the reduced disclosure format.




Table of Contents


TABLE OF CONTENTS

 
  Page

Part I—Financial Information

  1
 

Item 1—Financial Statements

  1
           

Constellation Energy Group, Inc. and Subsidiaries

   
           

Consolidated Statements of Income

  1
           

Consolidated Statements of Comprehensive Income

  1
           

Consolidated Balance Sheets

  2
           

Consolidated Statements of Cash Flows

  4
           

Baltimore Gas and Electric Company and Subsidiaries

   
           

Consolidated Statements of Income

  5
           

Consolidated Balance Sheets

  6
           

Consolidated Statements of Cash Flows

  8
           

Notes to Consolidated Financial Statements

  9
 

Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations

  32
           

Introduction and Overview

  32
           

Business Environment

  32
           

Events of 2011

  33
           

Results of Operations

  34
           

Financial Condition

  44
           

Capital Resources

  46
 

Item 3—Quantitative and Qualitative Disclosures About Market Risk

  52
 

Items 4—Controls and Procedures

  52

Part II—Other Information

  53
 

Item 1—Legal Proceedings

  53
 

Item 2—Issuer Purchases of Equity Securities

  53
 

Item 5—Other Information

  54
 

Item 6—Exhibits

  55
 

Signature

  56


i


Table of Contents


PART I—FINANCIAL INFORMATION

Item 1—Financial Statements

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

 
  Three Months Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions, except
per share amounts)

 

Revenues

             
 

Nonregulated revenues

  $ 2,613.9   $ 2,518.2  
 

Regulated electric revenues

    650.1     751.3  
 

Regulated gas revenues

    306.2     317.1  
   
 

Total revenues

    3,570.2     3,586.6  

Expenses

             
 

Fuel and purchased energy expenses

    2,478.2     2,362.1  
 

Fuel and purchased energy expenses from affiliate

    194.8     198.5  
 

Operating expenses

    438.2     396.4  
 

Depreciation, depletion, accretion, and amortization

    154.1     131.9  
 

Taxes other than income taxes

    77.7     66.8  
   
 

Total expenses

    3,343.0     3,155.7  

Equity Investment Losses

    (9.6 )   (20.7 )

Net Gain on Divestitures

        4.9  
   

Income from Operations

    217.6     415.1  

Other Expense

    (19.0 )   (22.3 )

Fixed Charges

             
 

Interest expense

    71.3     121.5  
 

Interest capitalized and allowance for borrowed funds used during construction

    (2.2 )   (15.6 )
   
 

Total fixed charges

    69.1     105.9  
   

Income from Continuing Operations Before Income Taxes

    129.5     286.9  

Income Tax Expense

    50.1     95.6  
   

Net Income

    79.4     191.3  

Less: Net Income (Loss) Attributable to Noncontrolling Interests and BGE Preference Stock Dividends

    9.0     (0.2 )
   

Net Income Attributable to Common Stock

  $ 70.4   $ 191.5  
   

Average Shares of Common Stock Outstanding—Basic

    199.4     200.3  

Average Shares of Common Stock Outstanding—Diluted

    200.7     201.9  
   

Earnings Per Common Share—Basic

  $ 0.35   $ 0.96  
   

Earnings Per Common Share—Diluted

  $ 0.35   $ 0.95  
   

Dividends Declared Per Common Share

  $ 0.24   $ 0.24  
   

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

 
  Three Months Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Net Income

  $ 79.4   $ 191.3  
 

Other comprehensive income (OCI)

             
   

Hedging instruments:

             
     

Reclassification of net loss on hedging instruments from OCI to net income, net of taxes

    58.1     108.5  
     

Net unrealized gain (loss) on hedging instruments, net of taxes

    5.4     (232.9 )
   

Available-for-sale securities:

             
     

Reclassification of net gain on sales of securities from OCI to net income, net of taxes

        (0.1 )
     

Net unrealized gain on securities, net of taxes

        0.2  
   

Defined benefit obligations:

             
     

Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes

    7.9     5.9  
   

Net unrealized gain on foreign currency, net of taxes

    1.5     1.7  
   

Other comprehensive income—equity investment in CENG, net of taxes

    12.8     9.9  
   

Other comprehensive loss—other equity method investees, net of taxes

        (0.2 )
   
 

Comprehensive income

    165.1     84.3  
   

Less: Comprehensive income (loss) attributable to noncontrolling interests, net of taxes

    9.0     (0.2 )
   

Comprehensive Income Attributable to Common Stock

  $ 156.1   $ 84.5  
   

See Notes to Consolidated Financial Statements.


1


Table of Contents

CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

 
  March 31,
2011*
  December 31,
2010
 
   
 
  (In millions)
 

Assets

             
 

Current Assets

             
   

Cash and cash equivalents

  $ 1,157.5   $ 2,028.5  
   

Accounts receivable (net of allowance for uncollectibles of $79.5 and $85.0, respectively)

    1,813.1     2,059.2  
   

Accounts receivable—consolidated variable interest entities (net of allowance for uncollectibles of $90.3 and $87.9, respectively)

    295.8     308.9  
   

Income taxes receivable

    33.5     152.7  
   

Fuel stocks

    355.9     361.1  
   

Materials and supplies

    128.7     104.3  
   

Derivative assets

    350.0     534.4  
   

Unamortized energy contract assets (includes $311.0 and $400.9, respectively, related to CENG)

    431.4     544.7  
   

Restricted cash

    2.3     52.0  
   

Restricted cash—consolidated variable interest entities

    75.1     52.3  
   

Other

    209.2     254.5  
   
   

Total current assets

    4,852.5     6,452.6  
   

Investments and Other Noncurrent Assets

             
   

Investment in CENG

    2,996.5     2,991.1  
   

Other investments

    194.4     189.9  
   

Regulatory assets (net)

    377.6     374.1  
   

Goodwill

    79.9     77.0  
   

Derivative assets

    234.3     258.9  
   

Unamortized energy contract assets

    83.1     109.8  
   

Other

    261.0     286.3  
   
   

Total investments and other noncurrent assets

    4,226.8     4,287.1  
   

Property, Plant and Equipment

             
   

Property, plant and equipment

    14,877.8     13,588.9  
   

Accumulated depreciation

    (4,413.5 )   (4,310.1 )
   
   

Net property, plant and equipment

    10,464.3     9,278.8  
   
 

Total Assets

 
$

19,543.6
 
$

20,018.5
 
   

* Unaudited
See Notes to Consolidated Financial Statements.


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CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

 
  March 31,
2011*
  December 31,
2010
 
   
 
  (In millions)
 

Liabilities and Equity

             
 

Current Liabilities

             
   

Short-term borrowings

  $ 34.1   $ 32.4  
   

Current portion of long-term debt

    22.0     245.6  
   

Current portion of long-term debt—consolidated variable interest entities

    59.7     59.7  
   

Accounts payable

    859.6     1,072.6  
   

Accounts payable—consolidated variable interest entities

    179.9     189.8  
   

Derivative liabilities

    492.8     622.3  
   

Unamortized energy contract liabilities

    132.9     130.5  
   

Deferred income taxes

    21.4     56.5  
   

Accrued taxes

    80.6     71.0  
   

Accrued expenses

    271.8     358.1  
   

Other

    543.3     438.7  
   
   

Total current liabilities

    2,698.1     3,277.2  
   
 

Deferred Credits and Other Noncurrent Liabilities

             
   

Deferred income taxes

    2,602.2     2,489.8  
   

Asset retirement obligations

    33.0     32.3  
   

Derivative liabilities

    299.7     353.0  
   

Unamortized energy contract liabilities

    384.2     411.1  
   

Defined benefit obligations

    583.3     574.7  
   

Deferred investment tax credits

    26.5     27.6  
   

Other

    232.7     296.0  
   
   

Total deferred credits and other noncurrent liabilities

    4,161.6     4,184.5  
   
 

Long-term Debt, Net of Current Portion

   
4,047.5
   
4,054.2
 
 

Long-term Debt, Net of Current Portion—consolidated variable interest entities

    394.6     394.6  
 

Equity

             
   

Common shareholders' equity:

             
     

Common stock

    3,251.1     3,231.7  
     

Retained earnings

    5,293.8     5,270.8  
     

Accumulated other comprehensive loss

    (587.6 )   (673.3 )
   
   

Total common shareholders' equity

    7,957.3     7,829.2  
   

BGE preference stock not subject to mandatory redemption

    190.0     190.0  
   

Noncontrolling interests

    94.5     88.8  
   
   

Total equity

    8,241.8     8,108.0  
   
 

Commitments, Guarantees, and Contingencies (see Notes)

             
 

Total Liabilities and Equity

 
$

19,543.6
 
$

20,018.5
 
   

* Unaudited
See Notes to Consolidated Financial Statements.


3


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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

Three Months Ended March 31,
  2011
  2010
 
   
 
  (In millions)
 

Cash Flows From Operating Activities

             
 

Net income

  $ 79.4   $ 191.3  
 

Adjustments to reconcile to net cash provided by (used in) operating activities

             
   

Depreciation, depletion, accretion, and amortization

    154.1     131.9  
   

Amortization of energy contracts and derivatives designated as hedges

    111.4     17.4  
   

All other amortization

    8.1     6.0  
   

Deferred income taxes

    19.2     (2.4 )
   

Investment tax credit adjustments

    (1.1 )   (1.1 )
   

Deferred fuel costs

    16.9     23.9  
   

Deferred storm costs

    (15.5 )    
   

Defined benefit obligation expense

    19.0     20.6  
   

Defined benefit obligation payments

    (7.9 )   (15.5 )
   

Gain on divestitures

        (4.9 )
   

Equity in earnings of affiliates less than dividends received

    12.0     31.3  
   

Derivative contracts classified as financing activities

    7.6     39.1  
   

Changes in:

             
     

Accounts receivable, excluding margin

    147.8     87.0  
     

Derivative assets and liabilities, excluding collateral

    210.0     (75.9 )
     

Net collateral and margin

    18.4     (109.1 )
     

Materials, supplies, and fuel stocks

    10.5     38.2  
     

Other current assets

    171.2     35.3  
     

Accounts payable

    (273.5 )   (33.0 )
     

Liability for unrecognized tax benefits

    2.3     (15.5 )
     

Accrued taxes and other current liabilities

    (1.8 )   (931.0 )
   

Other

    (0.8 )   3.0  
   
 

Net cash provided by (used in) operating activities

    687.3     (563.4 )
   

Cash Flows From Investing Activities

             
 

Investments in property, plant and equipment

    (231.8 )   (190.9 )
 

Asset and business acquisitions, net of cash acquired

    (1,084.0 )    
 

Proceeds from sales of investments and other assets

        24.8  
 

Proceeds from investment tax credits and grants related to renewable energy investments

    15.2      
 

Contract and portfolio acquisitions

    (3.7 )   (3.4 )
 

Decrease (Increase) in restricted funds

    28.1     (66.1 )
 

Other

    (2.1 )   1.5  
   
 

Net cash used in investing activities

    (1,278.3 )   (234.1 )
   

Cash Flows From Financing Activities

             
 

Net issuance (repayment) of short-term borrowings

    1.7     (24.9 )
 

Proceeds from issuance of common stock

    5.7     11.0  
 

Repayment of long-term debt

    (228.5 )   (600.7 )
 

Debt and credit facility costs

    (3.1 )   (4.0 )
 

Common stock dividends paid

    (45.8 )   (46.3 )
 

BGE preference stock dividends paid

    (3.3 )   (3.3 )
 

Derivative contracts classified as financing activities

    (7.6 )   (39.1 )
 

Other

    0.9     2.6  
   
 

Net cash used in financing activities

    (280.0 )   (704.7 )
   

Net Decrease in Cash and Cash Equivalents

    (871.0 )   (1,502.2 )

Cash and Cash Equivalents at Beginning of Period

    2,028.5     3,440.0  
   

Cash and Cash Equivalents at End of Period

  $ 1,157.5   $ 1,937.8  
   

See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.


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Table of Contents

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

 
  Three Months Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Revenues

             
 

Electric revenues

  $ 650.2   $ 751.3  
 

Gas revenues

    307.3     318.0  
   
 

Total revenues

    957.5     1,069.3  

Expenses

             
 

Operating expenses

             
   

Electricity purchased for resale

    297.2     349.6  
   

Electricity purchased for resale from affiliate

    56.7     124.0  
   

Gas purchased for resale

    171.1     194.5  
   

Operations and maintenance

    120.6     120.5  
   

Operations and maintenance from affiliate

    32.4     28.5  
 

Depreciation and amortization

    76.3     67.7  
 

Taxes other than income taxes

    49.8     47.6  
   
 

Total expenses

    804.1     932.4  
   

Income from Operations

    153.4     136.9  

Other Income

    6.1     6.5  

Fixed Charges

             
 

Interest expense

    33.5     34.4  
 

Allowance for borrowed funds used during construction

    (1.7 )   (1.3 )
   
 

Total fixed charges

    31.8     33.1  
   

Income Before Income Taxes

    127.7     110.3  

Income Taxes

    46.6     45.9  
   

Net Income

    81.1     64.4  

Preference Stock Dividends

    3.3     3.3  
   

Net Income Attributable to Common Stock

  $ 77.8   $ 61.1  
   

See Notes to Consolidated Financial Statements.


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Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

 
  March 31,
2011*
  December 31,
2010
 
   
 
  (In millions)
 

Assets

             
 

Current Assets

             
   

Cash and cash equivalents

  $ 150.4   $ 50.0  
   

Accounts receivable (net of allowance for uncollectibles of $33.2 and $34.9, respectively)

    385.7     351.4  
   

Accounts receivable, unbilled (net of allowance for uncollectibles of $1.0 and $1.0, respectively)

    198.9     268.8  
   

Accounts receivable, affiliated companies

    1.9     1.1  
   

Income taxes receivable, net

        55.9  
   

Fuel stocks

    18.3     66.5  
   

Materials and supplies

    38.1     31.2  
   

Prepaid taxes other than income taxes

    25.5     51.7  
   

Regulatory assets (net)

    59.7     78.7  
   

Restricted cash—consolidated variable interest entity

    52.1     29.5  
   

Other

    9.9     9.5  
   
   

Total current assets

    940.5     994.3  
   
 

Investments and Other Assets

             
   

Regulatory assets (net)

    377.6     374.1  
   

Receivable, affiliated company

    485.2     494.3  
   

Other

    48.4     52.2  
   
   

Total investments and other assets

    911.2     920.6  
   
 

Utility Plant

             
   

Plant in service

             
     

Electric

    5,191.8     5,127.9  
     

Gas

    1,339.3     1,323.0  
     

Common

    511.5     507.8  
   
     

Total plant in service

    7,042.6     6,958.7  
   

Accumulated depreciation

    (2,477.3 )   (2,449.3 )
   
   

Net plant in service

    4,565.3     4,509.4  
   

Construction work in progress

    267.3     232.9  
   

Plant held for future use

    10.1     10.1  
   
   

Net utility plant

    4,842.7     4,752.4  
   
 

Total Assets

 
$

6,694.4
 
$

6,667.3
 
   

* Unaudited
See Notes to Consolidated Financial Statements.


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Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

 
  March 31,
2011*
  December 31,
2010
 
   
 
  (In millions)
 

Liabilities and Equity

             
 

Current Liabilities

             
   

Current portion of long-term debt

  $ 22.0   $ 22.0  
   

Current portion of long-term debt—consolidated variable interest entity

    59.7     59.7  
   

Accounts payable

    195.7     252.9  
   

Accounts payable, affiliated companies

    79.9     84.9  
   

Customer deposits

    77.7     78.9  
   

Deferred income taxes

    21.5     30.1  
   

Accrued taxes

    77.1     19.0  
   

Liability for uncertain tax positions

    60.7     62.8  
   

Accrued expenses and other

    102.9     99.7  
   
   

Total current liabilities

    697.2     710.0  
   
 

Deferred Credits and Other Liabilities

             
   

Deferred income taxes

    1,399.5     1,354.9  
   

Payable, affiliated company

    255.0     250.8  
   

Deferred investment tax credits

    8.2     8.4  
   

Other

    18.6     20.1  
   
   

Total deferred credits and other liabilities

    1,681.3     1,634.2  
   
 

Long-term Debt

             
   

Rate stabilization bonds—consolidated variable interest entity

    454.4     454.4  
   

Other long-term debt

    1,431.5     1,431.5  
   

6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities

    257.7     257.7  
   

Unamortized discount and premium

    (2.0 )   (2.0 )
   

Current portion of long-term debt

    (22.0 )   (22.0 )
   

Current portion of long-term debt—consolidated variable interest entity

    (59.7 )   (59.7 )
   
   

Total long-term debt

    2,059.9     2,059.9  
   
 

Equity

             
   

Common shareholder's equity

    2,066.0     2,073.2  
   

Preference stock not subject to mandatory redemption

    190.0     190.0  
   
   

Total equity

    2,256.0     2,263.2  
   
 

Commitments, Guarantees, and Contingencies (see Notes)

             
 

Total Liabilities and Equity

 
$

6,694.4
 
$

6,667.3
 
   

* Unaudited
See Notes to Consolidated Financial Statements.


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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

Three Months Ended March 31,
  2011
  2010
 
   
 
  (In millions)
 

Cash Flows From Operating Activities

             
 

Net income

  $ 81.1   $ 64.4  
 

Adjustments to reconcile to net cash provided by operating activities

             
   

Depreciation and amortization

    76.3     67.7  
   

Other amortization

    1.8     (0.3 )
   

Deferred income taxes

    29.3     45.6  
   

Investment tax credit adjustments

    (0.3 )   (0.3 )
   

Deferred fuel costs

    16.9     23.9  
   

Deferred storm costs

    (15.5 )    
   

Defined benefit plan expenses

    11.0     8.2  
   

Allowance for equity funds used during construction

    (3.5 )   (2.5 )
   

Changes in

             
     

Accounts receivable

    35.6     0.1  
     

Accounts receivable, affiliated companies

    (0.8 )   13.7  
     

Materials, supplies, and fuel stocks

    41.3     40.6  
     

Income tax receivable, net

    55.9      
     

Other current assets

    30.6     31.0  
     

Accounts payable

    (57.2 )   (34.5 )
     

Accounts payable, affiliated companies

    (5.0 )   (18.0 )
     

Other current liabilities

    60.5     (64.3 )
     

Long-term receivables and payables, affiliated companies

    2.3     (1.2 )
     

Regulatory assets, net

    (2.7 )   (20.5 )
   

Other

    (7.4 )   (32.0 )
   
 

Net cash provided by operating activities

    350.2     121.6  
   

Cash Flows From Investing Activities

             
 

Utility construction expenditures (excluding equity portion of allowance for funds used during construction)

    (136.2 )   (87.2 )
 

Change in cash pool at parent

        314.7  
 

Proceeds from sales of investments and other assets

        20.9  
 

Increase in restricted funds

    (22.6 )   (23.8 )
   
 

Net cash (used in) provided by investing activities

    (158.8 )   224.6  
   

Cash Flows From Financing Activities

             
 

Repayment of short-term borrowings

        (46.0 )
 

Credit facility costs

    (2.7 )    
 

Preference stock dividends paid

    (3.3 )   (3.3 )
 

Distribution to parent

    (85.0 )    
   
 

Net cash used in financing activities

    (91.0 )   (49.3 )
   

Net Increase in Cash and Cash Equivalents

    100.4     296.9  

Cash and Cash Equivalents at Beginning of Period

    50.0     13.6  
   

Cash and Cash Equivalents at End of Period

  $ 150.4   $ 310.5  
   

See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Basis of Presentation

This Quarterly Report on Form 10-Q is a combined report of Constellation Energy Group, Inc. (Constellation Energy) and Baltimore Gas and Electric Company (BGE). References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE.

        Various factors can have a significant impact on our results for interim periods. This means that the results for this quarter are not necessarily indicative of future quarters or full year results given the seasonality of our business.

        Our interim financial statements on the previous pages reflect all adjustments that management believes are necessary for the fair statement of the results of operations for the interim periods presented. These adjustments are of a normal recurring nature.

Reclassifications

We made the following reclassifications:

Pending Merger with Exelon Corporation

On April 28, 2011, Constellation Energy entered into an Agreement and Plan of Merger with Exelon Corporation (Exelon). At closing, each issued and outstanding share of common stock of Constellation Energy will be cancelled and converted into the right to receive 0.93 shares of common stock of Exelon, and Constellation Energy will become a wholly owned subsidiary of Exelon.

        The merger agreement contains certain termination rights for both Constellation Energy and Exelon. Under specified circumstances Constellation Energy may be required to pay Exelon a termination fee of $200 million and Exelon may be required to pay Constellation Energy a termination fee of $800 million.

        In connection with the proposed merger, Exelon and Constellation Energy announced several commitments, each of which is contingent upon completion of the merger, that they intend to include in their filing for approval of the merger with the Maryland Public Service Commission (Maryland PSC). The estimated value of the commitments, including a proposed rate rebate of $100 per residential BGE customer, is approximately $250 million.

        The merger agreement has been approved by both companies' boards of directors, but completion of the merger is contingent upon, among other things, the approval of the transaction by stockholders of both companies and receipt of required regulatory approvals, including the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Maryland PSC and several other state and federal regulatory bodies. The parties are working to complete the merger early in 2012.

Variable Interest Entities

As of March 31, 2011, we consolidate three variable interest entities (VIEs) for which we are the primary beneficiary, and we have significant interests in six other VIEs for which we do not have controlling financial interests. We discuss our VIEs in more detail in Note 4 of our 2010 Annual Report on Form 10-K.

Consolidated Variable Interest Entities

Our, and BGE's, consolidated VIEs consist of:

        We discuss how we determine whether we are the primary beneficiary of VIEs in more detail in Note 4 of our 2010 Annual Report on Form 10-K.

        For each of our consolidated VIEs:


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        We include the consolidated VIEs in our consolidated financial statements at March 31, 2011 and December 31, 2010 as follows:

 
  March 31,
2011

  December 31,
2010

 
   
 
  (In millions)
 

Current assets

  $ 497.8   $ 516.6  

Noncurrent assets

    53.4     57.7  
   

Total Assets

  $ 551.2   $ 574.3  
   

Current liabilities

  $ 323.8   $ 345.5  

Noncurrent liabilities

    396.8     399.0  
   

Total Liabilities

  $ 720.6   $ 744.5  
   

Unconsolidated Variable Interest Entities

As of March 31, 2011 and December 31, 2010, we had significant interests in six VIEs for which we were not the primary beneficiary. We have not provided any material financial or other support to these entities during the quarter ended March 31, 2011 and we do not intend to provide any additional financial or other support to these entities in the future.

        The following tables present summary information about these entities:

As of March 31, 2011
  Power
Contract
Monetization
VIEs

  All
Other
VIEs

  Total
 
   
 
  (In millions)
 

Total assets

  $ 491.2   $ 307.2   $ 798.4  

Total liabilities

    380.9     129.2     510.1  

Our ownership interest

        50.3     50.3  

Other ownership interests

    110.3     127.7     238.0  

Our maximum exposure to loss:

                   
 

Letters of credit

    23.2         23.2  
 

Carrying amount of our investment—Other investments

        42.9     42.9  
 

Debt and payment guarantees

        5.0     5.0  

 

As of December 31, 2010
  Power
Contract
Monetization
VIEs

  All
Other
VIEs

  Total
 
   
 
  (In millions)
 

Total assets

  $ 492.9   $ 288.3   $ 781.2  

Total liabilities

    382.6     113.2     495.8  

Our ownership interest

        48.7     48.7  

Other ownership interests

    110.3     126.4     236.7  

Our maximum exposure to loss:

                   
 

Letters of credit

    24.9         24.9  
 

Carrying amount of our investment—Other investments

        41.4     41.4  
 

Debt and payment guarantees

        5.0     5.0  

        We assess the risk of a loss equal to our maximum exposure to be remote. In addition, there are no agreements with, or commitments by, third parties that would affect the fair value or risk of our variable interests in these VIEs.

Earnings Per Share

Basic earnings per common share (EPS) is computed by dividing net income attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

        Our dilutive common stock equivalent shares consist of stock options and other stock-based compensation awards. The following table presents stock options that were not dilutive and were excluded from the computation of diluted EPS in each period, as well as the dilutive common stock equivalent shares:

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Non-dilutive stock options

    5.7     4.9  

Dilutive common stock equivalent shares

    1.3     1.6  

Acquisition

Boston Generating

In January 2011, we acquired Boston Generating's 2,950 MW fleet of generating plants for cash of $1.1 billion. The fleet acquired includes the following four natural gas power


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plants and one fuel oil plant located in the Boston, Massachusetts area:

        We recorded the acquisition as follows:

At January 3, 2011
   
 
   
 
  (In millions)
 

Current assets

  $ 92.2  

Land

    29.2  

Property, plant and equipment

    1,061.4  

Noncurrent assets

    0.5  
   

Total assets acquired

    1,183.3  
   

Current liabilities

    (77.5 )

Noncurrent liabilities

    (21.8 )
   

Total liabilities

    (99.3 )
   

Net assets acquired

  $ 1,084.0  
   

        The preliminary net assets acquired are based on estimates.

        We have included the results of operations from these plants in our consolidated financial statements as part of our Generation business segment since the date of acquisition.

        The proforma impact of this acquisition would not have been material to our results of operations for the quarters ended March 31, 2011 and 2010 and to our financial condition as of March 31, 2011 and December 31, 2010.

Investment in Constellation Energy Nuclear Group, LLC (CENG)

We own a 50.01% interest in CENG, a nuclear generation and operation business. Our total equity in earnings of our investment in CENG is as follows:

Quarter ended March 31,
  2011
  2010
 
   
 
  (In millions)
 

CENG

  $ 12.7   $ 23.4  

Amortization of basis difference in CENG

    (29.3 )   (42.6 )
   

Total equity investment earnings (losses)—CENG1

  $ (16.6 ) $ (19.2 )
   

1 For the quarters ended March 31, 2011 and 2010, total equity investment earnings (losses) in CENG include $0.5 million and $1.2 million, respectively, of expense related to the portion of cost of certain share-based awards that we fund on behalf of EDF Group and affiliates (EDF).

        The basis difference is the difference between the carrying amount of our investment in CENG and our share of the underlying equity in CENG, because the underlying assets of CENG were retained at their historical carrying value. See Note 2 to our 2010 Annual Report on Form 10-K for a more detailed discussion.

        Summarized income statement information for CENG for the quarters ended March 31, 2011 and 2010 is as follows:

Quarter ended March 31,
  2011
  2010
 
   
 
  (In millions)
 

Revenues

  $ 358.6   $ 360.9  

Expenses

    341.4     323.3  

Income from operations

    17.2     37.6  

Net income

    26.3     49.1  

Regulatory Assets (net)

In March 2011, the Maryland PSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010. As part of the March 2011 comprehensive rate order, BGE was authorized to defer $18.9 million of costs as regulatory assets. These costs will be recovered over a 5-year period beginning December 2010 and relate to the deferral of:


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        The regulatory assets for the storm costs and the workforce reduction costs will earn a regulated rate of return.

Information by Operating Segment

Our reportable operating segments are Generation, NewEnergy, Regulated Electric, and Regulated Gas. We discuss our reportable operating segments in detail in Note 3 of our 2010 Annual Report on Form 10-K.

        These reportable segments are strategic businesses based principally upon regulations, products, and services that require different technologies and marketing strategies. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices. A summary of information by operating segment is shown in the table below.

 
  Reportable Segments    
   
   
 
 
  Holding
Company
and Other

   
   
 
 
  Generation
  NewEnergy
  Regulated
Electric

  Regulated
Gas

  Eliminations
  Consolidated
 
   
 
  (In millions)
 

Quarter ended March 31,

                                           

2011

                                           

Unaffiliated revenues

  $ 259.5   $ 2,354.9   $ 650.1   $ 306.2   $ (0.5 ) $   $ 3,570.2  

Intersegment revenues

    408.1     57.2     0.1     1.1         (466.5 )    
   

Total revenues

    667.6     2,412.1     650.2     307.3     (0.5 )   (466.5 )   3,570.2  

Net income (loss)

    12.8     (11.4 )   39.7     41.4     (3.1 )       79.4  

Net income (loss) attributable to common stock

    12.8     (17.1 )   37.2     40.6     (3.1 )       70.4  

2010

                                           

Unaffiliated revenues

  $ 291.2   $ 2,227.0   $ 751.3   $ 317.1   $   $   $ 3,586.6  

Intersegment revenues

    288.7     123.9         0.9         (413.5 )    
   

Total revenues

    579.9     2,350.9     751.3     318.0         (413.5 )   3,586.6  

Net income (loss)

    27.1     104.1     27.2     37.2     (4.3 )       191.3  

Net income (loss) attributable to common stock

    27.1     107.6     24.6     36.5     (4.3 )       191.5  

Our Generation business operating results for the quarter ended March 31, 2011 include the following after-tax charges:

Our NewEnergy business operating results for the quarter ended March 31, 2011 include the amortization of credit facility amendment fees in connection with the2009 EDF transaction of $1.5 million after-tax.


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Pension and Postretirement Benefits

We show the components of net periodic pension benefit cost in the following table:

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Components of net periodic pension benefit cost

             

Service cost

  $ 11.4   $ 9.5  

Interest cost

    22.6     21.7  

Expected return on plan assets

    (30.0 )   (26.7 )

Recognized net actuarial loss

    12.2     8.1  

Amortization of prior service cost

    1.0     1.0  

Amount capitalized as construction cost

    (2.9 )   (1.9 )
   

Net periodic pension benefit cost1

  $ 14.3   $ 11.7  
   

1 BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $9.1 million in 2011 and $6.3 million in 2010.

        We show the components of net periodic postretirement benefit cost in the following table:

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Components of net periodic postretirement benefit cost

             

Service cost

  $ 0.7   $ 0.7  

Interest cost

    4.2     4.7  

Amortization of transition obligation

    0.5     0.5  

Recognized net actuarial loss

    0.6     0.3  

Amortization of prior service cost

    (0.6 )   (0.7 )

Amount capitalized as construction cost

    (1.4 )   (1.3 )
   

Net periodic postretirement benefit cost1

  $ 4.0   $ 4.2  
   

1 BGE's portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was $4.6 million in 2011 and $4.8 million in 2010.

        Our non-qualified pension plans and our postretirement benefit programs are not funded; however, we have trust assets securing certain executive pension benefits. We estimate that we will incur approximately $6.0 million in pension benefit payments for our non-qualified pension plans and approximately $23.8 million for retiree health and life insurance costs in 2011.

Financing Activities

Credit Facilities and Short-term Borrowings

We discuss the purposes for and the types of instruments used for entering into credit facilities and short-term borrowings in Note 8 of our 2010 Annual Report on Form 10-K.

Constellation Energy

Constellation Energy had bank lines of credit under committed credit facilities totaling $4.2 billion at March 31, 2011 for short-term financial needs, primarily for our NewEnergy business, as follows:

Type of
Credit Facility

  Amount
(In billions)

  Expiration
Date

  Capacity
Type

 

Syndicated Revolver

  $ 2.50   October 2013   Letters of credit and cash

Commodity-linked

    0.50   August 2014   Letter of credit and cash

Bilateral

    0.55   September 2014   Letters of credit

Bilateral

    0.25   December 2014   Letters of credit and cash

Bilateral

    0.25   June 2014   Letters of credit and cash

Bilateral

    0.15   September 2013   Letters of credit
             
 

Total

  $ 4.20        
             

        At March 31, 2011, we had approximately $1.5 billion in letters of credit issued including $0.2 billion in letters of credit issued under the commodity-linked credit facility and no commercial paper outstanding under these facilities. This facility's capacity increases as natural gas price levels decrease compared to a reference price that is adjusted periodically. As of March 31, 2011, this facility's capacity was $0.2 billion.

        At March 31, 2011, Constellation Energy had $34.1 million of short-term notes outstanding with a weighted average effective interest rate of 6.56%.

BGE

As of March 31, 2011, BGE has a $600.0 million revolving credit facility expiring in March 2015. BGE can borrow directly from the banks, use the facility to allow commercial paper to be issued, if available, or issue letters of credit. At March 31, 2011, BGE had no commercial paper or direct borrowings outstanding. There were immaterial letters of credit outstanding at March 31, 2011.

Debt

In January 2011, we redeemed $213.5 million of our 7.00% Notes, which represented the remaining outstanding 7.00% Notes due April 1, 2012. We redeemed these notes with part of the proceeds from the issuance of the


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$550 million 5.15% Notes issued in December 2010, terminated certain interest rate swaps and recognized a pre-tax loss of approximately $5 million on this transaction. We discuss the termination of the interest rate swaps in our Derivative Instruments note.

Net Available Liquidity

The following table provides a summary of our, and BGE's, net available liquidity at March 31, 2011:

At March 31, 2011
  Constellation
Energy
(excluding BGE)

  BGE
 
   
 
  (In billions)
 

Credit facilities1

  $ 3.7   $ 0.6  

Less: Letters of credit issued1

    (1.3 )    

Less: Cash drawn on credit facilities

         
   

Undrawn facilities

    2.4     0.6  

Less: Commercial paper outstanding

         
   

Net available facilities

    2.4     0.6  

Add: Cash and cash equivalents2

    1.0     0.1  
   

Net available liquidity

  $ 3.4   $ 0.7  
   

1 Excludes $0.5 billion commodity-linked credit facility due to its contingent nature and $0.2 billion in letters of credit posted against it.

2 BGE's cash balance at March 31, 2011 was $150.4 million.

Credit Facility Compliance and Covenants

The credit facilities of Constellation Energy and BGE contain a material adverse change representation but draws on the facilities are not conditioned upon Constellation Energy and BGE making this representation at the time of the draw. However, to the extent a material adverse change has occurred and prevents Constellation Energy or BGE from making other representations that are required at the time of the draw, the draw would be prohibited.

        Certain credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At March 31, 2011, the debt to capitalization ratio as defined in the credit agreements was 35%.

        The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At March 31, 2011, the debt to capitalization ratio for BGE as defined in this credit agreement was 43%.

        Decreases in Constellation Energy's or BGE's credit ratings would not trigger an early payment on any of our, or BGE's, credit facilities. However, the impact of a credit ratings downgrade on our financial ratios associated with our credit facility covenants would depend on our financial condition at the time of such a downgrade and on the source of funds used to satisfy the incremental collateral obligation resulting from a credit ratings downgrade. For example, if we were to use existing cash balances to fund the cash portion of any additional collateral obligations resulting from a credit ratings downgrade, we would not expect a material impact on our financial ratios. However, if we were to issue long-term debt or use our credit facilities to fund any additional collateral obligations, our financial ratios could be materially affected. Failure by Constellation Energy, or BGE, to comply with these covenants could result in the acceleration of the maturity of the borrowings outstanding and preclude us from issuing letters of credit under these facilities.

Income Taxes

We compute the income tax expense for each quarter based on the estimated annual effective tax rate for the year. The effective tax rate was 38.7% for the quarter ended March 31, 2011 compared to 33.3% for the same period of 2010. The higher effective tax rate for 2011 is primarily due to lower deductions for qualified production activities and reductions of federal uncertain tax positions compared to the same period of 2010 and increased state income taxes, resulting from increased business activity in unitary states and an increase in the Illinois corporate tax rate.

        The BGE effective tax rate was 36.5% for the quarter ended March 31, 2011 compared to 41.6% for the same period of 2010. The lower effective tax rate for 2011 is primarily due to the partial reversal during the quarter ended March 31, 2011 of the unfavorable tax adjustment recorded in the quarter ended March 31, 2010 to reflect the impact on our regulated electric business of the healthcare reform legislation that eliminated the tax exempt status of prescription drug subsidies received under Medicare Part D. The partial reversal in 2011 resulted from the Maryland PSC's authorization for BGE to create an electric regulatory asset for this tax law change and amortize the balance over a five-year period as provided in its March 2011 comprehensive order in BGE's most recent base rate case.


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Unrecognized Tax Benefits

The following table summarizes the change in unrecognized tax benefits during 2011 and our total unrecognized tax benefits at March 31, 2011:

At March 31, 2011
   
 
   
 
  (In millions)
 

Total unrecognized tax benefits, January 1, 2011

  $ 239.8  

Increases in tax positions related to the current year

    0.6  

Increases in tax positions related to prior years

    3.9  

Reductions in tax positions related to prior years

    (5.6 )
   

Total unrecognized tax benefits, March 31, 20111

  $ 238.7  
   

1 BGE's portion of our total unrecognized tax benefits at March 31, 2011 was $69.6 million.

        If the total amount of unrecognized tax benefits of $238.7 million were ultimately realized, our income tax expense would decrease by approximately $169.1 million. The $169.1 million includes state tax refund claims of $55.9 million that have been disallowed by tax authorities and are subject to appeals.

        It is reasonably possible that unrecognized tax benefits could decrease within the next year by approximately $70 million as a result of an expected settlement with the IRS regarding BGE's change of accounting method for tax purposes with respect to certain transmission and distribution expenditures. This decrease is not expected to have a material impact on BGE's financial condition or results of operation.

        Interest and penalties recorded in our Consolidated Statements of Income as tax expense relating to liabilities for unrecognized tax benefits were as follows:

 
  For the Quarter
Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Interest and penalties recorded as tax expense

  $ 2.8   $ 3.4  
   

BGE's portion of interest and penalties was immaterial for both periods presented.

        Accrued interest and penalties recognized in our Consolidated Balance Sheets were $19.6 million, of which BGE's portion was $4.3 million, at March 31, 2011, and $16.8 million, of which BGE's portion was $3.8 million, at December 31, 2010.

Taxes Other Than Income Taxes

Taxes other than income taxes primarily include property and gross receipts taxes along with franchise taxes and other non-income taxes, surcharges, and fees.

        BGE and our NewEnergy operations collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer and others are imposed on BGE and our NewEnergy business. Where these taxes, such as sales taxes, are imposed on the customer, we account for these taxes on a net basis with no impact to our Consolidated Statements of Income. However, where these taxes, such as gross receipts taxes or other surcharges or fees, are imposed on BGE or our NewEnergy business, we account for these taxes on a gross basis. Accordingly, we recognize revenues for these taxes collected from customers along with an offsetting tax expense, which are both included in our and BGE's Consolidated Statements of Income. The taxes, surcharges, or fees that are included in revenues were as follows:

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Constellation Energy (including BGE)

  $ 34.7   $ 31.0  

BGE

    23.0     21.9  
   

Guarantees

Our guarantees do not represent incremental Constellation Energy obligations; rather they primarily represent parental guarantees of subsidiary obligations. The following table summarizes the maximum exposure by guarantor based on the stated limit of our outstanding guarantees:

At March 31, 2011
  Stated Limit
 
   
 
  (In billions)
 

Constellation Energy guarantees

  $ 9.3  

BGE guarantees

    0.3  
   

Total guarantees

  $ 9.6  
   

        At March 31, 2011, Constellation Energy had a total of $9.6 billion in guarantees outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described below.


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Commitments and Contingencies

We have made substantial commitments in connection with our Generation, NewEnergy, regulated electric and gas, and other nonregulated businesses. These commitments relate to:

        Our Generation and NewEnergy businesses enter into various contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between 2011 and 2030. In addition, our NewEnergy business enters into contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts expire in various years between 2011 and 2015.

        Our Generation and NewEnergy businesses also have committed to service agreements and other purchase commitments for our plants.

        Our regulated electric business enters into various contracts for the procurement of electricity. These contracts expire between 2011 and 2013 and represent BGE's estimated requirements to serve residential and small commercial customers as follows:

Contract Duration
  Percentage of
Estimated
Requirements

 
   

From April 1, 2011 to September 2011

    100 %

From October 2011 to May 2012

    75  

From June 2012 to September 2012

    50  

From October 2012 to May 2013

    25  
   

        The cost of power under these contracts is recoverable under the Provider of Last Resort agreement reached with the Maryland PSC.

        Our regulated gas business enters into various contracts for the procurement, transportation, and storage of gas. Our regulated gas business has gas procurement contracts that expire in 2011 and transportation and storage contracts that expire between 2012 and 2027. The cost of gas under these contracts is recoverable under BGE's gas cost adjustment clause discussed in Note 1 of our 2010 Annual Report on Form 10-K.

        We have also committed to service agreements and other obligations related to our information technology systems.

        At March 31, 2011, the total amount of commitments was $7.5 billion. These commitments are primarily related to our Generation and NewEnergy businesses.

Long-Term Power Sales Contracts

We enter into long-term power sales contracts in connection with our load-serving activities. We also enter into long-term power sales contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2031 and provide for the sale of energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with power plants we own extend for terms into 2016 and provide for the sale of all or a portion of the actual output of certain of our power plants. Substantially all long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

Contingencies

Litigation

In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below.

Merger with Exelon

In late April and early May 2011, shortly after Constellation Energy and Exelon announced their agreement to merge the two companies, six shareholder


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class action lawsuits were filed in the Circuit Court for Baltimore City in Maryland. Each class action suit was filed on behalf of a proposed class of the shareholders of Constellation Energy against Constellation Energy, members of Constellation Energy's board of directors, and Exelon. The shareholder class actions generally allege that the individual directors breached their fiduciary duties by entering into the proposed merger because they failed to maximize the value that the shareholders would receive from the merger, and failed to disclose adequately all material information relating to the proposed merger. The class actions also allege that Constellation Energy and Exelon aided and abetted the individual directors' breaches of their fiduciary duties. The lawsuits challenge the proposed merger, seek to enjoin a shareholder vote on the proposed merger until all material information is provided relating to the proposed merger, and ask for rescission of the proposed merger and any related transactions that have been completed as of the date that the court grants any relief. The class action lawsuits also seek certification as class actions, compensatory damages, costs and disbursements related to the action, including attorneys' and experts' fees, and rescission damages. Plaintiffs in three of the six lawsuits subsequently filed motions to consolidate their lawsuits. Given that these lawsuits were recently filed, that the court has not certified any class and the plaintiffs have not quantified their potential damage claims, we are unable at this time to provide an estimate of the range of possible loss relating to these proceedings or to determine the ultimate outcome of these lawsuits or their possible effect on our, or BGE's, financial results or their possible effect on the pending merger with Exelon.

Securities Class Action

Three federal securities class action lawsuits were filed in the United States District Courts for the Southern District of New York and the District of Maryland between September 2008 and November 2008. The cases were filed on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures (Debentures), of Constellation Energy between January 30, 2008 and September 16, 2008, and who acquired Debentures in an offering completed in June 2008. The securities class actions generally allege that Constellation Energy, a number of its present or former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation Energy's June 27, 2008 offering of Debentures. The securities class actions also allege that Constellation Energy issued false or misleading statements or was aware of material undisclosed information which contradicted public statements including in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions seek, among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.

        The Southern District of New York granted the defendants' motion to transfer the two securities class actions filed in Maryland to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On June 18, 2009, the court appointed a lead plaintiff, who filed a consolidated amended complaint on September 17, 2009. On November 17, 2009, the defendants moved to dismiss the consolidated amended complaint in its entirety. On August 13, 2010, the District Court of Maryland issued a ruling on the motion to dismiss, holding that the plaintiffs failed to state a claim with respect to the claims of the common shareholders under the Securities Act of 1934 and restricting the suit to those persons who purchased Debentures in the June 2008 offering. Given that the discovery phase has just begun, that the court has not certified any class and the plaintiffs have not quantified their potential damage claims relating to the June 2008 offering, we are unable at this time to provide an estimate of the range of possible loss relating to these proceedings or to determine the ultimate outcome of the securities class actions or their possible effect on our, or BGE's financial results.

Mercury

Since September 2002, BGE, Constellation Energy, and several other defendants have been involved in numerous actions filed in the Circuit Court for Baltimore City, Maryland alleging mercury poisoning from several sources, including coal plants formerly owned by BGE. The plants are now owned by a subsidiary of Constellation Energy. In addition to BGE and Constellation Energy, approximately 11 other defendants, consisting of pharmaceutical companies, manufacturers of vaccines, and manufacturers of Thimerosal have been sued. Approximately 70 cases, involving claims related to approximately 132 children, have been filed to date, with each claimant seeking $20 million in compensatory damages, plus punitive damages, from us.

        The claims against BGE and Constellation Energy have been dismissed in all of the cases either with prejudice based on rulings by the Court or without prejudice based on voluntary dismissals by the plaintiffs' counsel. Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE and Constellation Energy once the cases are finally


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concluded as to all defendants. We believe that we have meritorious defenses and intend to defend any appeals vigorously. We are unable to provide an estimate of the range of possible loss relating to these cases given that only limited discovery occurred in these cases prior to the dismissals being granted and, as a result, we cannot predict the outcome of these cases, or their possible effect on our, or BGE's, financial results.

Asbestos

Since 1993, BGE and certain Constellation Energy subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE and Constellation Energy knew of and exposed individuals to an asbestos hazard. In addition to BGE and Constellation Energy, numerous other parties are defendants in these cases.

        Approximately 485 individuals who were never employees of BGE or Constellation Energy have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third party claims brought by other defendants may also be filed against BGE and Constellation Energy in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or Constellation Energy and a small minority of these cases have been resolved for amounts that were not material to our financial results.

        Discovery begins in these cases once they are placed on the trial docket. At present, only a small number of our pending cases have reached the trial docket. Given the limited discovery, BGE and Constellation Energy do not know the specific facts that we believe are necessary for us to provide an estimate of the possible loss relating to these claims. The specific facts we do not know include:

        Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions.

Environmental Matters

Solid and Hazardous Waste

In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, which is its list of sites targeted for clean-up and enforcement, and sent a general notice letter to BGE and 19 other parties identifying them as potentially responsible parties at the site. In March 2004, we and other potentially responsible parties formed the 68th Street Coalition and entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the EPA and 19 of the potentially responsible parties, including BGE, with respect to investigation of the site became effective. The settlement requires the potentially responsible parties, over the course of several years, to identify contamination at the site and recommend clean-up options. BGE is indemnified by a wholly owned subsidiary of Constellation Energy for most of the costs related to this settlement and clean-up of the site. The potentially responsible parties completed their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the EPA are still subject to EPA review, we believe that the range of estimated clean-up costs to be allocated among all of the potentially responsible parties will be between approximately $45 million and $64 million depending on the clean-up option selected by the EPA. The EPA is expected to make a final selection of one of the alternatives by the end of 2011. As the alternative to be selected by the EPA and the allocation of the clean-up costs among the potentially responsible parties is not yet known, we cannot provide an estimate of the range of our possible loss.

Air Quality

In January 2009, the EPA issued a notice of violation (NOV) to a subsidiary of Constellation Energy, as well as to the other owners and the operator of the Keystone coal-fired power plant in Shelocta, Pennsylvania. We hold a 20.99% interest in the Keystone plant. The NOV alleges that the plant performed various capital projects beginning in 1984 without complying with the new source review permitting requirements of the Clean Air Act. The EPA also contends that the alleged failure to comply with those requirements are continuing violations under the plant's air permits. The EPA could seek civil penalties under the Clean Air Act for the alleged violations.

        The owners and operator of the Keystone plant have investigated the allegations and had a meeting with the EPA where they provided the EPA with both legal and factual documentation to support their position that no violations have occurred. Since that time, the EPA has not requested any further meeting or otherwise acted on the allegations. We believe there are meritorious defenses to the allegations contained in the NOV. Because there are significant facts in dispute and this matter is only in the NOV stage, at this


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time we cannot estimate the range of possible loss or predict whether a proceeding will be commenced.

Water Quality

In October 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment relating to groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by our coal-fired plants. The consent decree requires the payment of a $1.0 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. We recorded a liability in our Consolidated Balance Sheets of approximately $10.6 million, which includes the $1 million penalty and our estimate of probable costs to remediate contamination, replace drinking water supplies, monitor groundwater conditions, and otherwise comply with the consent decree. We have paid approximately $6.8 million of these costs as of March 31, 2011, resulting in a remaining liability at March 31, 2011 of $3.8 million. We estimate that it is reasonably possible that we could incur additional costs of up to approximately $10 million more than the liability that we accrued.

        In April 2007, PennEnvironment and the Sierra Club brought a Clean Water Act citizen suit against the operator of the Conemaugh power plant in Pennsylvania, seeking civil penalties and injunctive relief for alleged violations of Conemaugh's water permit. Throughout the relevant time period, the operator of the Conemaugh plant has been working closely with the Pennsylvania Department of Environmental Protection (PADEP) to ensure that the facility operates in an environmentally sound manner, and does not cause any adverse environmental impacts. Pursuant to a consent order between PADEP and the operator, a variety of studies have been conducted and treatment facilities have been designed and have been built or are pending construction, all in order to comply with the limits set out in Conemaugh's water permit.

        On March 21, 2011, the court entered a partial summary judgment in the plaintiffs' favor, declaring as a matter of law that discharges from the Conemaugh plant had violated the water permit. The case is set for a non-jury trial starting on June 1, 2011, at which the court will determine what, if any, civil penalties and injunctive relief might be appropriate. If the plaintiffs are ultimately successful, we, through our subsidiary that owns 10.56% of Conemaugh, could incur additional costs associated with civil penalties and the implementation of additional discharge reductions, in proportion to our share of ownership.

Insurance

We discuss our non-nuclear insurance programs in Note 12 of our 2010 Annual Report on Form 10-K.

Derivative Instruments

Risks, Objectives, and Strategies

Substantially all of our risk management activities involving derivatives occur in our competitive businesses. In carrying out our competitive business activities, we purchase and sell power, fuel, and other energy-related commodities in competitive markets. These activities expose us to significant risks, including market risk from price volatility for energy commodities and the credit risks of counterparties with which we enter into contracts.

        To lower our exposure to the risk of unfavorable fluctuations in commodity prices, interest rates, and foreign currency rates, we routinely enter into derivative contracts, such as fixed price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges, for hedging purposes. We also enter into derivative contracts for trading purposes.

        We discuss the nature of our business and associated risks in connection with our objectives and strategies for using derivatives for both risk management and non-risk management activities in Note 13 of our 2010 Annual Report on Form 10-K.

Accounting for Derivative Instruments

We recognize all qualifying derivative instruments on the balance sheet at fair value as either assets or liabilities.

Accounting Designation

We must evaluate new and existing transactions and agreements to determine whether they meet the definition of a derivative, for which there are several possible accounting treatments. The permissible accounting treatments include:

        Mark-to-market is required as the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria, both at the time of designation and on an ongoing basis.

        We discuss our accounting policies for derivatives and hedging activities and their impacts on our financial statements in Note 1 to our 2010 Annual Report on Form 10-K.


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        In the sections below, we describe the significant activity in 2011 by accounting treatment.

NPNS

We continue to elect NPNS accounting for certain contracts that provide for the purchase or sale of a physical commodity that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business.

Cash Flow Hedging

Commodity Cash Flow Hedges

We have designated fixed-price forward contracts as cash-flow hedges of forecasted purchases and sales of energy, fuel, and other related commodities for the years 2011 through 2016. We had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive loss" of $284.3 million at March 31, 2011 and $388.0 million at December 31, 2010.

        We expect to reclassify $186.6 million of net pre-tax losses on cash-flow hedges from "Accumulated other comprehensive loss" into earnings during the next twelve months based on market prices at March 31, 2011. However, the actual amount reclassified into earnings could vary from the amounts recorded at March 31, 2011, due to future changes in market prices.

        When we determine that a forecasted transaction originally designated as a hedged item has become probable of not occurring, we immediately reclassify net unrealized gains or losses associated with those hedges from "Accumulated other comprehensive loss" to earnings. We recognized in earnings the following pre-tax amounts on such contracts:

 
  Quarter ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Pre-tax losses

  $   $ (1.4 )
   

Interest Rate Swaps Designated as Cash Flow Hedges

Accumulated other comprehensive loss includes net unrealized pre-tax gains on interest rate cash-flow hedges of prior debt issuances totaling $8.8 million at March 31, 2011 and $10.1 million at December 31, 2010. We expect to reclassify $0.1 million of pre-tax net gains on these cash-flow hedges from "Accumulated other comprehensive loss" into "Interest expense" during the next twelve months. We had no hedge ineffectiveness on these swaps.

Fair Value Hedging

We elect fair value hedge accounting for a limited portion of our derivative contracts including certain interest rate swaps. The objectives for electing fair value hedge accounting in these situations are to manage our exposure and to optimize the mix of our fixed and floating-rate debt.

Interest Rate Swaps Designated as Fair Value Hedges

At December 31, 2010, we had interest rate swaps qualifying as fair value hedges relating to $400 million of our fixed-rate debt maturing in 2012 and 2015. The fair value of these hedges was an unrealized gain of $35.7 million at December 31, 2010.

        In January 2011, we terminated $200 million of these interest rate swaps as a result of retiring all of our fixed-rate debt maturing in 2012 and received $13.8 million in cash.

        During February 2011, we entered into interest rate swaps qualifying as fair value hedges related to $350 million of our fixed rate debt maturing in 2015, and converted this notional amount of debt to floating rate.

        As a result of this activity, at March 31, 2011, we have interest rate swaps qualifying as fair value hedges relating to $550 million of our fixed-rate debt maturing in 2015, and converted this notional amount of debt to floating-rate. The fair value of these hedges was an unrealized gain of $24.6 million at March 31, 2011.

        We recorded the fair value of these hedges as an increase in our "Derivative assets" and an increase in our "Long-term debt."

Hedge Ineffectiveness

For all categories of commodity contract derivative instruments designated in hedging relationships, we recorded in earnings the following pre-tax gains (losses) related to hedge ineffectiveness:

 
  Quarter ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Cash-flow hedges

  $ (16.9 ) $ 13.3  

Fair value hedges

    0.1      
   

Total

  $ (16.8 ) $ 13.3  
   

Mark-to-Market

During February 2011, we entered into interest rate swaps related to $150 million of our fixed rate debt maturing in 2020, and converted this notional amount of debt to floating rate. However, these interest rate swaps do not qualify as fair value hedges and will be marked to market through earnings.


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Quantitative Information About Derivatives and Hedging Activities

Balance Sheet Tables

We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis, including cash collateral, whenever we have a legally enforceable master netting agreement with a counterparty to a derivative contract. We use master netting agreements whenever possible to manage and substantially reduce our potential counterparty credit risk. The net presentation in our Consolidated Balance Sheets reflects our actual credit exposure after giving effect to the beneficial effects of these agreements and cash collateral, and our credit risk is reduced further by other forms of collateral.

        The following tables provide information about the risks we manage using derivatives. These tables only include derivatives and do not reflect the price risks we are hedging that arise from physical assets or nonderivative accrual contracts within our Generation and NewEnergy businesses.

        We present this information by disaggregating our net derivative assets and liabilities into gross components on a contract-by-contract basis before giving effect to the risk-reducing benefits of master netting arrangements and collateral. As a result, we must present each individual contract as an "asset value" if it is in the money or a "liability value" if it is out of the money, regardless of whether the individual contracts offset market or credit risks of other contracts in full or in part. Therefore, the gross amounts in these tables do not reflect our actual economic or credit risk associated with derivatives. This gross presentation is intended only to show separately the various derivative contract types we use, such as commodities, interest rate, and foreign exchange.

        The contracts in the tables below are segregated between derivatives designated for hedge accounting and those not designated for hedge accounting. Derivatives not designated in hedging relationships include our NewEnergy retail operations, economic hedges of accrual activities, and risk management and trading activities. We use the end of period accounting designation to determine the classification for each derivative position.

As of March 31, 2011
  Derivatives
Designated as Hedging
Instruments for
Accounting Purposes

  Derivatives Not
Designated As Hedging
Instruments for
Accounting Purposes

  All Derivatives
Combined

 
   
Contract type
  Asset
Values3

  Liability
Values4

  Asset
Values3

  Liability
Values4

  Asset
Values3

  Liability
Values4

 
   
 
  (In millions)
 
 

Power contracts

  $ 1,216.9   $ (1,220.7 ) $ 5,729.6   $ (6,219.0 ) $ 6,946.5   $ (7,439.7 )
 

Gas contracts

    1,622.8     (1,560.9 )   2,894.7     (2,701.3 )   4,517.5     (4,262.2 )
 

Coal contracts

    81.3     (49.7 )   233.9     (221.4 )   315.2     (271.1 )
 

Other commodity contracts1

            318.2     (317.4 )   318.2     (317.4 )
 

Interest rate contracts

    25.1         32.8     (33.5 )   57.9     (33.5 )
 

Foreign exchange contracts

            14.7     (11.8 )   14.7     (11.8 )
   

Total gross fair values

  $ 2,946.1   $ (2,831.3 ) $ 9,223.9   $ (9,504.4 ) $ 12,170.0   $ (12,335.7 )
                   
 

Netting arrangements5

                            (11,543.2 )   11,543.2  
 

Cash collateral

                            (40.3 )    
                               

Net fair values

                          $ 586.5   $ (792.5 )
                               

Net fair value by balance sheet line item:

                                     

Accounts receivable2

                          $ 2.2        

Derivative assets—current

                            350.0        

Derivative assets—noncurrent

                            234.3        

Derivative liabilities—current

                                  (492.8 )

Derivative liabilities—noncurrent

                                  (299.7 )
                               

Total Derivatives

                          $ 586.5   $ (792.5 )
   

1 Other commodity contracts include oil, freight, emission allowances, and weather contracts.

2 Represents the unrealized fair value of exchange traded derivatives, exclusive of cash margin posted.

3 Represents in-the-money contracts without regard to potentially offsetting out-of-the-money contracts under master netting agreements.

4 Represents out-of-the-money contracts without regard to potentially offsetting in-the-money contracts under master netting agreements.

5 Represents the effect of legally enforceable master netting agreements.


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As of December 31, 2010
  Derivatives
Designated as Hedging
Instruments for
Accounting Purposes

  Derivatives Not
Designated As Hedging
Instruments for
Accounting Purposes

  All Derivatives
Combined

 
   
Contract type
  Asset
Values3

  Liability
Values4

  Asset
Values3

  Liability
Values4

  Asset
Values3

  Liability
Values4

 
   
 
  (In millions)
 
 

Power contracts

  $ 1,167.9   $ (1,362.8 ) $ 6,795.0   $ (7,166.5 ) $ 7,962.9   $ (8,529.3 )
 

Gas contracts

    1,902.3     (1,832.8 )   3,390.1     (3,155.3 )   5,292.4     (4,988.1 )
 

Coal contracts

    97.0     (48.6 )   266.0     (259.7 )   363.0     (308.3 )
 

Other commodity contracts1

            61.4     (61.6 )   61.4     (61.6 )
 

Interest rate contracts

    35.7         34.4     (35.7 )   70.1     (35.7 )
 

Foreign exchange contracts

            11.0     (8.4 )   11.0     (8.4 )
   

Total gross fair values

  $ 3,202.9   $ (3,244.2 ) $ 10,557.9   $ (10,687.2 ) $ 13,760.8   $ (13,931.4 )
                   
 

Netting arrangements5

                            (12,955.5 )   12,955.5  
 

Cash collateral

                            (28.4 )   0.6  
                               

Net fair values

                          $ 776.9   $ (975.3 )
                               

Net fair value by balance sheet line item:

                                     

Accounts receivable2

                          $ (16.4 )      

Derivative assets—current

                            534.4        

Derivative assets—noncurrent

                            258.9        

Derivative liabilities—current

                                  (622.3 )

Derivative liabilities—noncurrent

                                  (353.0 )
                               

Total Derivatives

                          $ 776.9   $ (975.3 )
   

1 Other commodity contracts include oil, freight, emission allowances, and weather contracts.

2 Represents the unrealized fair value of exchange traded derivatives, exclusive of cash margin posted.

3 Represents in-the-money contracts without regard to potentially offsetting out-of-the-money contracts under master netting agreements.

4 Represents out-of-the-money contracts without regard to potentially offsetting in-the-money contracts under master netting agreements.

5 Represents the effect of legally enforceable master netting agreements.

Gain and (Loss) Tables

The tables below summarize derivative gains and losses segregated into the following categories:

        The tables only include this information for derivatives and do not reflect the related gains or losses that arise from generation and generation-related assets, nonderivative accrual contracts, or NPNS contracts within our Generation and NewEnergy businesses, other than fair value hedges, for which we separately show the gain or loss on the hedged asset or liability. As a result, these tables only reflect the impact of derivatives themselves and therefore do not necessarily include all of the income statement impacts of the transactions for which derivatives are used to manage risk. For a more complete discussion of how derivatives affect our financial performance, see our accounting policy for Revenues, Fuel and Purchased Energy Expenses, and Derivatives and Hedging Activities in Note 1 of our 2010 Annual Report on Form 10-K.


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        The following tables present gains and losses on derivatives designated as cash flow hedges.

Cash Flow Hedges
   
   
   
  Quarter Ended March 31,
 
   
 
  Gain (Loss)
Recorded in AOCI
   
  Gain (Loss)
Reclassified from
AOCI into
Earnings
  Ineffectiveness
Gain (Loss)
Recorded in
Earnings
 
Contract type:
  2011
  2010
  Statement of Income (Loss) Line Item
  2011
  2010
  2011
  2010
 
   
 
  (In millions)
 

Hedges of forecasted sales:

              Nonregulated revenues                          
 

Power contracts

  $ (23.4 ) $ 202.5       $ (18.4 ) $ (59.2 ) $ 1.2   $ 21.8  
 

Gas contracts

    11.1     (34.9 )       22.2     20.2     2.2     (1.1 )
 

Coal contracts

                             
 

Other commodity contracts1

                    (0.7 )        

Foreign exchange contracts

                             
   

Total gains (losses)

  $ (12.3 ) $ 167.6   Total included in nonregulated revenues   $ 3.8   $ (39.7 ) $ 3.4   $ 20.7  
   

Hedges of forecasted purchases:

              Fuel and purchased energy expense                          
 

Power contracts

  $ 17.5   $ (455.5 )     $ (98.7 ) $ (203.1 ) $ (12.3 ) $ (9.3 )
 

Gas contracts

    (1.9 )   (73.6 )       (7.3 )   78.0     (7.7 )    
 

Coal contracts

    5.5     (10.8 )       7.3     (12.5 )   (0.3 )   1.7  
 

Other commodity contracts2

        (0.2 )           (0.3 )       0.2  

Foreign exchange contracts

                             
   

Total losses

  $ 21.1   $ (540.1 ) Total included in fuel and purchased energy expense   $ (98.7 ) $ (137.9 ) $ (20.3 ) $ (7.4 )
   

Hedges of interest rates:

              Interest expense                          
 

Interest rate contracts

                1.1     3.9          
   

Total gains

  $   $   Total included in interest expense   $ 1.1   $ 3.9   $   $  
   

Grand total (losses) gains

  $ 8.8   $ (372.5 )     $ (93.8 ) $ (173.7 ) $ (16.9 ) $ 13.3  
   

1 Other commodity sale contracts include oil and freight contracts.

2 Other commodity purchase contracts include freight and emission allowances.

        The following table presents gains and losses on derivatives designated as fair value hedges and, separately, the gains and losses on the hedged item.

Fair Value Hedges
   
  Quarter Ended March 31,
 
   
 
   
  Amount of
Gain (Loss)
Recognized in
Income on
Derivative

  Amount of
Gain (Loss)
Recognized in
Income on
Hedged Item

 
 
   
     
Contract type:
  Statement of Income (Loss) Line Item
  2011
  2010
  2011
  2010
 
   
 
   
  (In millions)
 

Commodity contracts:

                             
 

Gas contracts

  Nonregulated revenues   $   $   $   $  

Interest rate contracts

  Interest expense     2.0     13.2     (1.5 )   (11.1 )
   

Total gains (losses)

      $ 2.0   $ 13.2   $ (1.5 ) $ (11.1 )
   


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        The following table presents gains and losses on mark-to-market derivatives.

Mark-to-Market Derivatives
   
  Quarter Ended March 31,
 
   
 
   
  Amount of Gain
(Loss) Recorded
in Income

 
 
   
     
Contract type:
  Statement of Income (Loss) Line Item
  2011
  2010
 
   
 
   
  (In millions)
 

Commodity contracts:

                 
 

Power contracts

  Nonregulated revenues   $ 23.3   $ (64.9 )
 

Gas contracts

  Nonregulated revenues     11.3     25.7  
 

Coal contracts

  Nonregulated revenues     (8.6 )   0.1  
 

Other commodity contracts1

  Nonregulated revenues     (16.6 )   4.9  
 

Coal contracts

  Fuel and purchased energy expense          

Interest rate contracts

  Nonregulated revenues     (0.7 )   (1.1 )

Foreign exchange contracts

  Nonregulated revenues     (12.1 )   (0.9 )
   

Total gains (losses)

      $ (3.4 ) $ (36.2 )
   

1 Other commodity contracts include oil, freight, uranium, weather, and emission allowances.

Volume of Derivative Activity

The volume of our derivatives activity is directly related to the fundamental nature and scope of our business and the risks we manage. We own or control electric generating facilities, which exposes us to both power and fuel price risk; we serve electric and gas wholesale and retail customers within our NewEnergy business, which exposes us to electricity and natural gas price risk; and we provide risk management services and engage in trading activities, which can expose us to a variety of commodity price risks. In order to manage the risks associated with these activities, we are required to be an active participant in the energy markets, and we routinely employ derivative instruments to conduct our business.

        Derivative instruments provide an efficient and effective way to conduct our business and to manage the associated risks. As such, we use derivatives in the following ways:

        The following tables present information designed to provide insight into the overall volume of our derivatives usage. However, the volumes presented in these tables should only be used as an indication of the extent of our derivatives usage and the risks they are intended to manage and are subject to a number of limitations as follows:


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Table of Contents

        The following tables present the volume of our derivative activities as of March 31, 2011 and December 31, 2010 shown by contractual settlement year.

Quantities1 Under Derivative Contracts
   
   
   
  As of March 31, 2011
 
   
Contract Type (Unit)
  2011
  2012
  2013
  2014
  2015
  Thereafter
  Total
 
   
 
  (In millions)
 

Power (MWH)

    20.8     3.5     0.6     1.7     2.5     0.6     29.7  

Gas (mmBTU)

    153.2     97.3     75.5     54.9     19.5     0.9     401.3  

Coal (Tons)

    3.6     1.7     0.9                 6.2  

Oil (BBL)

    0.2     0.2     0.2                 0.6  

Emission Allowances (Tons)

    1.0                         1.0  

Renewable Energy Credits (Number of credits)

    0.4     0.2     0.3     0.3     0.3     0.4     1.9  

Interest Rate Contracts

  $ 498.7   $ 550.7   $ 700.0   $ 775.0   $ 1,215.0   $ 30.0   $ 3,769.4  

Foreign Exchange Rate Contracts

  $ 43.3   $ 14.8   $ 16.7   $ 16.8   $ 15.5   $   $ 107.1  
   

 

Quantities1 Under Derivative Contracts
   
   
   
  As of December 31, 2010
 
   
Contract Type (Unit)
  2011
  2012
  2013
  2014
  2015
  Thereafter
  Total
 
   
 
  (In millions)
 

Power (MWH)

    21.2         3.8     4.2     2.3     0.2     31.7  

Gas (mmBTU)

    175.3     90.1     80.2     64.7     24.1         434.4  

Coal (Tons)

    4.4     2.5     0.1                 7.0  

Oil (BBL)

    0.2     0.1     0.1                 0.4  

Emission Allowances (Tons)

    1.5                         1.5  

Renewable Energy Credits (Number of credits)

    0.4     0.3     0.3     0.3     0.3     0.7     2.3  

Interest Rate Contracts

  $ 639.4   $ 490.7   $ 941.8   $ 405.0   $ 460.0   $ 175.0   $ 3,111.9  

Foreign Exchange Rate Contracts

  $ 48.7   $ 8.7   $ 16.8   $ 16.8   $ 15.5   $   $ 106.5  
   

1 Amounts in the tables are only intended to provide an indication of the level of derivatives activity and should not be interpreted as a measure of any derivative position or overall economic exposure to market risk. Quantities are expressed as "delta equivalents" on an absolute value basis by contract type by year. Additionally, quantities relate only to derivatives and do not include potentially offsetting quantities associated with physical assets and nonderivative accrual contracts.


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Credit-Risk Related Contingent Features

Certain of our derivative instruments contain provisions that would require additional collateral upon a credit-related event such as an adequate assurance provision or a credit rating decrease in the senior unsecured debt of Constellation Energy. The amount of collateral we could be required to post would be determined by the fair value of contracts containing such provisions that represent a net liability, after offset for the fair value of any asset contracts with the same counterparty under master netting agreements and any other collateral already posted. This collateral amount is a component of, and is not in addition to, the total collateral we could be required to post for all contracts upon a credit rating decrease.

        The following tables present information related to credit-risk related contingent features of our derivatives at March 31, 2011 and December 31, 2010.

Credit-Risk Related Contingent Feature
  As of March 31, 2011
 
   
Gross Fair Value
of Derivative
Contracts Containing
This Feature1

  Offsetting Fair Value
of In-the-Money
Contracts Under Master
Netting Agreements2

  Net Fair Value
of Derivative
Contracts Containing
This Feature3

  Amount of
Posted
Collateral4

  Contingent
Collateral
Obligation5

 
   
(In billions)
 
$ 3.9   $ (3.2 ) $ 0.7   $ 0.5   $ 0.1  
   

 

Credit-Risk Related Contingent Feature
  As of December 31, 2010
 
   
Gross Fair Value
of Derivative
Contracts Containing
This Feature1

  Offsetting Fair Value
of In-the-Money
Contracts Under Master
Netting Agreements2

  Net Fair Value
of Derivative
Contracts Containing
This Feature3

  Amount of
Posted
Collateral4

  Contingent
Collateral
Obligation5

 
   
(In billions)
 
$ 4.6   $ (3.7 ) $ 0.9   $ 0.7   $ 0.1  
   

1 Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features that are not fully collateralized by posted cash collateral on an individual, contract-by-contract basis ignoring the effects of master netting agreements.

2 Amount represents the offsetting fair value of in-the-money derivative contracts under legally-enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which we potentially could be required to post collateral.

3 Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

4 Amount includes cash collateral posted of $million and letters of credit of $526.9 million at March 31, 2011 and cash collateral posted of $0.6 million and letters of credit of $656.9 million at December 31, 2010.

5 Amounts represent the additional collateral that we could be required to post with counterparties, including both cash collateral and letters of credit, in the event of a credit downgrade to below investment grade after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

Concentrations of Derivative-Related Credit Risk

We discuss our concentrations of credit risk, including derivative-related positions, in Note 1 to our 2010 Annual Report on Form 10-K. As of March 31, 2011, two counterparties, a large power cooperative and CENG, comprise total exposure concentrations of 23%.


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Table of Contents

Fair Value Measurements

Recurring Measurements

Our assets and liabilities measured at fair value on a recurring basis consist of the following (immaterial for BGE assets):

 
  As of
March 31, 2011

  As of
December 31, 2010

 
 
  Assets
  Liabilities
  Assets
  Liabilities
 
   

Cash equivalents

  $ 502.7   $   $ 1,545.4   $  

Equity securities

    43.3         43.7      

Derivative instruments:

                         
 

Classified as derivative assets and liabilities:

                         
   

Current

    350.0     (492.8 )   534.4     (622.3 )
   

Noncurrent

    234.3     (299.7 )   258.9     (353.0 )
   
   

Total classified as derivative assets and liabilities

    584.3     (792.5 )   793.3     (975.3 )
 

Classified as accounts receivable1

    2.2         (16.4 )    
   
 

Total derivative instruments

    586.5     (792.5 )   776.9     (975.3 )
   

Total recurring fair value measurements

  $ 1,132.5   $ (792.5 ) $ 2,366.0   $ (975.3 )
   

1 Represents the unrealized fair value of exchange traded derivatives, exclusive of cash margin posted.

        Cash equivalents represent money market funds included in "Cash and cash equivalents" in the Consolidated Balance Sheets. Equity securities primarily represent mutual fund investments included in "Other assets" in the Consolidated Balance Sheets. Derivative instruments represent unrealized amounts related to all derivatives. We classify exchange-listed derivatives as part of "Accounts Receivable" in our Consolidated Balance Sheets. We classify the remainder of our derivatives as "Derivative assets" or "Derivative liabilities" in our Consolidated Balance Sheets.

        The table below sets forth by level within the fair value hierarchy the gross components of the Company's assets and liabilities that were measured at fair value on a recurring basis as of March 31, 2011 and December 31, 2010. We disaggregate our net derivative assets and liabilities by separating each individual derivative contract that is in-the-money from each contract that is out-of-the-money regardless of master netting agreements and collateral. As a result, the gross "asset" and "liability" amounts in each of the three fair value levels far exceed our actual economic exposure to commodity price risk and credit risk. The objective of this table is to provide information about how each individual derivative contract is valued within the fair value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts or whether it has been collateralized. Therefore, these gross balances are intended solely to provide information on sources of inputs to fair value and proportions of fair value involving objective versus subjective valuations and do not represent either our actual credit exposure or net economic exposure.


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At March 31, 2011
  Level 1
  Level 2
  Level 3
  Netting and
Cash Collateral1

  Total Net
Fair Value

 
   
 
  (In millions)
 

Cash equivalents

  $ 502.7   $   $   $   $ 502.7  

Equity securities

    43.3                 43.3  

Derivative assets:

                               
 

Power contracts

        6,081.4     865.1              
 

Gas contracts

    90.7     4,086.2     340.5              
 

Coal contracts

        307.9     7.3              
 

Other commodity contracts

    68.2     74.9     175.1              
 

Interest rate contracts

    31.2     26.7                  
 

Foreign exchange contracts

        14.7                  
   
 

Total derivative assets

    190.1     10,591.8     1,388.0     (11,583.4 )   586.5  
   

Derivative liabilities:

                               
 

Power contracts

        (6,303.2 )   (1,136.7 )            
 

Gas contracts

    (86.8 )   (3,932.0 )   (243.3 )            
 

Coal contracts

        (270.7 )   (0.4 )            
 

Other commodity contracts

    (65.6 )   (71.2 )   (180.4 )            
 

Interest rate contracts

    (33.5 )                    
 

Foreign exchange contracts

        (11.8 )                
   

Total derivative liabilities

    (185.9 )   (10,588.9 )   (1,560.8 )   11,543.1     (792.5 )
   
 

Net derivative position

    4.2     2.9     (172.8 )   (40.3 )   (206.0 )
   

Total

  $ 550.2   $ 2.9   $ (172.8 ) $ (40.3 ) $ 340.0  
   

1 We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master netting agreement exists between us and the counterparty to a derivative contract. At March 31, 2011, we included $40.3 million of cash collateral held and $million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table. At December 31, 2010, we included $28.4 million of cash collateral held and $0.6 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table.


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At December 31, 2010
  Level 1
  Level 2
  Level 3
  Netting and
Cash Collateral1

  Total Net
Fair Value

 
   
 
  (In millions)
 

Cash equivalents

  $ 1,545.4   $   $   $   $ 1,545.4  

Equity securities

    43.7                 43.7  

Derivative assets:

                               
 

Power contracts

        7,509.6     453.3              
 

Gas contracts

    63.9     5,113.3     115.2              
 

Coal contracts

        355.6     7.4              
 

Other commodity contracts

    6.6     54.8                  
 

Interest rate contracts

    33.1     37.0                  
 

Foreign exchange contracts

        11.0                  
   
 

Total derivative assets

    103.6     13,081.3     575.9     (12,983.9 )   776.9  
   

Derivative liabilities:

                               
 

Power contracts

        (7,758.2 )   (771.1 )            
 

Gas contracts

    (72.7 )   (4,910.3 )   (5.1 )            
 

Coal contracts

        (307.4 )   (0.9 )            
 

Other commodity contracts

    (7.1 )   (54.5 )                
 

Interest rate contracts

    (35.7 )                    
 

Foreign exchange contracts

        (8.4 )                
   

Total derivative liabilities

    (115.5 )   (13,038.8 )   (777.1 )   12,956.1     (975.3 )
   
 

Net derivative position

    (11.9 )   42.5     (201.2 )   (27.8 )   (198.4 )
   

Total

  $ 1,577.2   $ 42.5   $ (201.2 ) $ (27.8 ) $ 1,390.7  
   

1 We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master netting agreement exists between us and the counterparty to a derivative contract. At March 31, 2011, we included $40.3 million of cash collateral held and $million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table. At December 31, 2010, we included $28.4 million of cash collateral held and $0.6 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table.

        We discuss our valuation techniques and inputs used to develop those measurements in greater detail in Note 13 of our 2010 Annual Report of Form 10-K. There have not been significant changes to our valuation techniques nor to their inputs during 2011.

        During the first quarter of 2011, there were no significant transfers of derivatives between Level 1 and Level 2 of the fair value hierarchy.


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        During the quarters ended March 31, 2011 and 2010, our Level 3 fair value measurements, predominantly power contracts, changed as follows:

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Balance at beginning of period

  $ (201.2 ) $ (291.5 )

Realized and unrealized (losses) gains:

             
 

Recorded in income

    (60.4 )   (136.8 )
 

Recorded in other comprehensive income

    10.3     76.4  

Purchases

           

Sales

           

Issuances

    4.7        

Settlements

           
           
 

Net purchases, sales, issuances, and settlements1

    4.7     9.3  

Transfers into Level 32

    111.6     115.1  

Transfers out of Level 32

    (37.8 )   (87.7 )
   

Balance at end of year

  $ (172.8 ) $ (315.2 )
   

Change in unrealized gains recorded in income relating to derivatives still held at end of period

  $ (73.5 ) $ (108.8 )
   

1 Effective January 1, 2011, we are required to present separately purchases, sales, issuances, and settlements.

2 For purposes of this reconciliation, we assumed transfers into and out of Level 3 occurred on the last day of the quarter. All transfers are predominantly the result of changes in the observability of the forward commodity price curves.

        We have defined the categories of purchases, sales, issuances, and settlements to include the inflow or outflow of value as follows:

        During the first quarter of 2011, our only activity was an issuance related to a premium paid for option contracts.

        We discuss the financial statement classification for realized and unrealized gains and losses related to cash-flow hedges for our various hedging relationships in Note 1 to our 2010 Annual Report on Form 10-K.

Fair Value of Financial Instruments

We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table:

At March 31, 2011
  Carrying
Amount

  Fair
Value

 
   
 
  (In millions)
 

Investments and other assets—Constellation Energy

  $ 194.4   $ 194.4  

Fixed-rate long-term debt:

             
 

Constellation Energy (including BGE)

    3,865.2     4,123.8  
 

BGE

    2,143.6     2,288.0  

Variable-rate long-term debt:

             
 

Constellation Energy (including BGE)

    662.4     662.4  
 

BGE

         

        We discuss our valuation techniques and assumptions for estimating the fair value of financial instruments in Note 13 of our 2010 Annual Report on Form 10-K. There have been no changes in these techniques and assumptions during the first quarter of 2011.

Related Party Transactions

Constellation Energy

CENG

We have a unit contingent power purchase agreement (PPA) with CENG under which we will purchase between 85-90% of the output of CENG's nuclear plants that is not sold to third parties under pre-existing PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, we will purchase 50.01% of the output of CENG's nuclear plants, and EDF will purchase 49.99% of that output.

        In addition to the PPA, we have a power services agency agreement (PSA) and an administrative service agreement (ASA) with CENG. The PSA is a five-year agreement under which we will provide scheduling, asset management and billing services to CENG and recognize average annual revenue of approximately $16 million. The ASA expires in 2017 and under the agreement we provide certain administrative services to CENG including back office, human resources and information technology. The ASA includes both a consumption-based pricing structure as well as a fixed-price structure which are subject to change in future years based on the level of service needed. The fixed price fee for 2011 is approximately $48 million and will increase annually due to inflation. The charges under


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this agreement are intended to represent the actual cost of the services provided to CENG by us.

        The impact of transactions under these agreements is summarized below:

Agreement
  Increase
(Decrease)
in Earnings
for the
Quarter Ended
March 31,
2011

  Increase
(Decrease)
in Earnings
for the
Quarter Ended
March 31,
2010

  Income
Statement
Classification

  Accounts
Receivable/
(Accounts
Payable) at
March 31,
2011

 
   
(In millions)
 

PPA

  $ (194.8 ) $ (198.5 ) Fuel and purchased
energy expenses
  $ (28.7 )

PSA

    4.0     4.0   Nonregulated
revenues
     

ASA

    12.0     16.5   Operating expenses     4.0  

BGE—Income Statement

BGE is obligated to provide market-based standard offer service to all of its electric customers for varying periods. Bidding to supply BGE's market-based standard offer service to electric customers will occur from time to time through a competitive bidding process approved by the Maryland PSC.

        Our NewEnergy business will supply a portion of BGE's market-based standard offer service obligation to electric customers through September 30, 2013.

        The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was $56.7 million for the quarter ended March 31, 2011 compared to $124.0 million for the same period in 2010.

        In addition, Constellation Energy charges BGE for the costs of certain corporate functions. Certain costs, both capital and expense, are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. We believe this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were approximately $47.5 million for the quarter ended March 31, 2011 compared to $36.2 million for the quarter ended March 31, 2010. Other nonregulated affiliates of BGE also charge BGE for the costs of certain services provided.

BGE—Balance Sheet

BGE's Consolidated Balance Sheets include intercompany amounts related to BGE's purchases to meet its standard offer service obligation, BGE's charges to Constellation Energy and its nonregulated affiliates for certain services it provides them, Constellation Energy and its nonregulated affiliates' charges to BGE, and the participation of BGE's employees in the Constellation Energy defined benefit plans.


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Table of Contents

Item 2.

Management's Discussion and Analysis of Financial Condition and Results of Operations


Introduction and Overview

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries and joint ventures organized around three business segments: a generation business (Generation), a customer supply business (NewEnergy), and Baltimore Gas and Electric Company (BGE).

        This Quarterly Report on Form 10-Q is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE. We discuss our business and strategy in more detail in Item 1—Business section of our 2010 Annual Report on Form 10-K and we discuss the risks affecting our business in Item 1A. Risk Factors section of our 2010 Annual Report on Form 10-K.

        Our 2010 Annual Report on Form 10-K includes a detailed discussion of various items impacting our business, our results of operations, and our financial condition. These include:

        Critical accounting policies are the accounting policies that are most important to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective, or complex judgment. Our critical accounting policies include derivative accounting and the evaluation of assets for impairment and other than temporary decline in value.

        In this discussion and analysis, we explain the general financial condition and the results of operations for Constellation Energy and BGE including:

        As you read this discussion and analysis, refer to our Consolidated Statements of Income on page 1, which present the results of our operations for the quarters ended March 31, 2011 and 2010. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income.

        We have organized our discussion and analysis as follows:


Business Environment

Various factors affect our financial results. We discuss these various factors in the Forward Looking Statements section on page 54 and in Item 1A. Risk Factors section of our 2010 Annual Report on Form 10-K. We discuss our market risks in the Risk Management section beginning on page 48.

        The volatility of the financial, credit and global energy markets impacts our liquidity and collateral requirements as well as our credit risk. We discuss our liquidity and collateral requirements in the Financial Condition section and our customer (counterparty) credit and other risks in more detail in the Risk Management section.

        In this section, we discuss in more detail events which have impacted our business during 2011.


Regulation—Maryland

Base Rates

In March 2011, the Maryland PSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010. We discuss certain details of the comprehensive order in the Notes to Consolidated Financial Statements beginning on page 11.


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Potential Reliability and Quality of Service Standards

During its 2011 legislative session, the Maryland General Assembly passed legislation:

        The Governor is expected to sign this legislation into law and the Maryland PSC has instituted a rulemaking proceeding to begin drafting the required service quality and reliability regulations. We cannot at this time predict the final outcome of this rulemaking or the studies required under the legislation or how such outcome may affect our, or BGE's, financial results.


Events of 2011

Pending Merger with Exelon Corporation

On April 28, 2011, we entered into an Agreement and Plan of Merger with Exelon Corporation (Exelon). At closing, each issued and outstanding share of common stock of Constellation Energy will be cancelled and converted into the right to receive 0.93 shares of common stock of Exelon, and Constellation Energy will become a wholly owned subsidiary of Exelon. We discuss this transaction in more detail on page 9 in Notes to Consolidated Financial Statements.

Acquisition

Boston Generating

In January 2011, we completed the acquisition of Boston Generating's 2,950 MW fleet of generating plants for approximately $1.1 billion. We discuss this transaction in more detail beginning on page 10 in Notes to Consolidated Financial Statements.


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Table of Contents


Results of Operations for the Quarter Ended March 31, 2011 Compared with the Same Period of 2010

In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our operating segments. Significant changes in other (expense) income, fixed charges, and income taxes are discussed, as necessary, in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section on page 43.


Overview

Results

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions, after-tax)
 

Generation

  $ 12.8   $ 27.1  

NewEnergy

    (11.4 )   104.1  

Regulated electric

    39.7     27.2  

Regulated gas

    41.4     37.2  

Other nonregulated

    (3.1 )   (4.3 )
   

Net Income

  $ 79.4   $ 191.3  
   

Net Income attributable to common stock

  $ 70.4   $ 191.5  
   

Change from prior year

  $ (121.1 )      
   

        Our total net income attributable to common stock decreased $121.1 million, or $0.60 per share, during the quarter ended March 31, 2011 compared to the same period in 2010, primarily due to the following:

 
  2011 vs. 2010
 
   
 
  (In millions, after-tax)
 

Generation gross margin

  $ (13 )

Increases in Generation non-gross margin expenses related to:

       
 

Acquisition of Boston Generating fleet of generating assets in January 2011

    (21 )
 

Acquisition of two combined cycle generating facilities in Texas in 2010

    (7 )

NewEnergy gross margin

    (99 )

NewEnergy hedge ineffectiveness

    (19 )

Regulated businesses

    17  

Other nonregulated businesses

    1  

Total change in Other Items included in Operations per table below

    38  

All other changes

    (18 )
   

Total Change

  $ (121 )
   

Other Items Included in Operations (after-tax):

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions, after-tax)
 

Impact of power purchase agreement with CENG1

  $ (27.0 ) $ (25.7 )

Amortization of basis difference in CENG

    (17.6 )   (25.7 )

Transaction fees for Boston Generating acquisition

    (10.0 )    

Loss on early retirement of 2012 Notes

        (30.9 )

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits

        (8.8 )

Credit facility amendment fees

    (1.5 )   (2.9 )
   

Total Other Items

  $ (56.1 ) $ (94.0 )
   

Change from prior year

  $ 37.9        
   

1 The net impact to the Company of the power purchase agreement with CENG was $44.9 million and $42.1 million pre-tax for the quarters ended March 31, 2011 and 2010, respectively. This amount represents the amortization of our $0.8 billion "Unamortized energy contract asset" less our 50.01% equity in CENG's amortization of its $0.8 billion "Unamortized energy contract liability."

        In the following sections, we discuss our net income by business segment in greater detail.


Generation Business

Background

We define our Generation business in Note 3 to our 2010 Annual Report on Form 10-K.

        We have presented the results of this business reflecting that we have hedged 100% of generation output and fuel for generation. This is based on executing hedges at prevailing market prices with the NewEnergy business. Taking into account previously executed hedges at the end of each fiscal year, we ensure that the Generation business is fully hedged by the NewEnergy business for the next year. Therefore, all commodity price risk is managed by and presented in the results of our NewEnergy business as discussed below. Generally, changes in the results of our Generation business during the period are due to changes in the availability of the generating assets.


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Results

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Revenues

  $ 667.6   $ 579.9  

Fuel and purchased energy expenses

    (414.4 )   (326.6 )
   

Gross margin

    253.2     253.3  

Operating expenses

    (117.2 )   (94.6 )

Depreciation, depletion, accretion, and amortization

    (48.7 )   (28.5 )

Taxes other than income taxes

    (11.9 )   (5.4 )

Gain on divestitures

        2.9  

Equity investment (losses) earnings:

             
 

CENG

    (16.6 )   (19.2 )
 

UNE

        (6.1 )
 

Other

    7.0     4.6  
   

Income from Operations

  $ 65.8   $ 107.0  
   

Net Income

  $ 12.8   $ 27.1  
   

Net Income attributable to common stock

  $ 12.8   $ 27.1  
   

Other Items Included in Operations (after-tax):

             
 

Impact of power purchase agreement with CENG1

  $ (27.0 ) $ (25.7 )
 

Amortization of basis difference in CENG

    (17.6 )   (25.7 )
 

Transaction fees for Boston Generating acquisition

    (10.0 )    
 

Loss on early retirement of 2012 Notes

        (30.9 )
 

Credit facility amendment fees

        (1.9 )
 

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits

        (0.8 )
   

Total Other Items

  $ (54.6 ) $ (85.0 )
   

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 12 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

1 The net impact to the Company of the power purchase agreement with CENG was $44.9 million and $42.1 million pre-tax for the quarters ended March 31, 2011 and 2010, respectively. This amount represents the amortization of our $0.8 billion "Unamortized energy contract asset" less our 50.01% equity in CENG's amortization of its $0.8 billion "Unamortized energy contract liability."

Revenues

Our Generation revenues increased $87.7 million in the first quarter of 2011 compared to 2010, primarily due to the following:

 
  2011 vs. 2010
 
   
 
  (In millions)
 

Increase in volume of output, primarily due to the acquisition of the Boston Generating fleet of generating assets in January 2011

  $ 200  

Decrease in contracted power prices

    (166 )

Increase in volume of output due to reduced impact of outages at our fossil plants

    56  

All other

    (2 )
   

Total increase in Generation revenues

  $ 88  
   

Fuel and Purchased Energy Expenses

Our Generation fuel and purchased energy expenses increased $87.8 million in the first quarter of 2011 compared to 2010, primarily due to the following:

 
  2011 vs. 2010
 
   
 
  (In millions)
 

Increase in volume of fuel consumed due to acquisition of Boston Generating fleet of generating assets in January 2011

  $ 54  

Increase due to reduced impact of outages at our fossil plants

    28  

Increase in coal fuel prices

    17  

All other

    (11 )
   

Total increase in Generation fuel and purchased energy expenses

  $ 88  
   

Operating Expenses

Our Generation business operating expenses increased $22.6 million for the quarter ended March 31, 2011 as compared to the same period for 2010 primarily due to the costs associated with the acquisition of the Boston Generating fleet of generating assets in January 2011.

Depreciation, Depletion, Accretion, and Amortization Expense

Our Generation business incurred higher depreciation, depletion, accretion, and amortization expenses of $20.2 million during the quarter ended March 31, 2011 compared to the same period of 2010 primarily due to an increase of $8.0 million in depreciation on the Boston Generating facilities acquired in January 2011, $4.4 million related to the June 2010 commencement of operations of our Hillabee Energy Center, and $3.0 million related to the May 2010 acquisition of the two Texas combined cycle generation facilities.


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Table of Contents

Taxes Other Than Income Taxes

Taxes other than income taxes increased $6.5 million during the quarter ended March 31, 2011 compared to the same period of 2010 primarily due to an increase in property taxes related to generating facilities acquired in Texas in 2010 and Massachusetts in 2011.

Equity Investment Losses

During the quarter ended March 31, 2011 our equity investment losses decreased $11.1 million compared to the same period of 2010 primarily due to the absence of $6.1 million of losses on our investment in UNE, which we sold in the fourth quarter of 2010, $2.6 million in lower losses on our investment in CENG, and $2.4 million in higher earnings on investments in power projects.


NewEnergy Business

Background

We define our NewEnergy business in Note 3 to our 2010 Annual Report on Form 10-K.

        Our NewEnergy business focuses on delivery of physical, customer-oriented energy products and services to energy producers and consumers, manages the risk and optimizes the value of our owned and contracted generation assets and NewEnergy activities, and uses our portfolio management and trading capabilities both to manage risk and to deploy limited risk capital. Our NewEnergy business actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions.

        We discuss our revenue recognition policies in the Critical Accounting Policies section and Note 1 of our 2010 Annual Report on Form 10-K.

Results

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Revenues

  $ 2,412.1   $ 2,350.9  

Fuel and purchased energy expenses

    (2,199.7 )   (1,979.4 )
   

Gross margin

    212.4     371.5  

Operating expenses

    (179.8 )   (168.5 )

Depreciation, depletion, accretion, and amortization

    (18.4 )   (21.8 )

Taxes other than income taxes

    (15.3 )   (12.9 )

Gain on divestitures

        2.0  
   

(Loss) income from Operations

  $ (1.1 ) $ 170.3  
   

Net (Loss) Income

  $ (11.4 ) $ 104.1  
   

Net (Loss) Income attributable to common stock

  $ (17.1 ) $ 107.6  
   

Other Items Included in Operations (after-tax):

             
 

Credit facility amendment fees

  $ (1.5 ) $ (1.0 )
 

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits

        (0.1 )
   

Total Other Items

  $ (1.5 ) $ (1.1 )
   

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 12 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.


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Table of Contents

Revenues

Our NewEnergy revenues increased $61.2 million in the first quarter of 2011 compared to 2010, primarily due to the following:

 
  2011 vs.
2010

 
   
 
  (In millions)
 

Wholesale load sales

  $ 75  

Change in hedge ineffectiveness

    (17 )

Increase in wholesale and retail mark-to-market revenues due to changes in gas and power prices

    33  

Decrease in volume and contract prices related to our domestic coal operation

    (18 )

All other

    (12 )
   

Total increase in NewEnergy revenues

  $ 61  
   

Fuel and Purchased Energy Expenses

Our NewEnergy fuel and purchased energy expenses increased $220.3 million in the first quarter of 2011 compared to 2010, primarily due to the following:

 
  2011 vs.
2010

 
   
 
  (In millions)
 

Wholesale power purchases

  $ 114  

Change in hedge ineffectiveness

    13  

Realization of fuel and purchased energy related to the assignment of international coal contracts

    73  

All other

    20  
   

Total increase in NewEnergy fuel and purchased energy expenses

  $ 220  
   

        The decrease in wholesale power gross margin reflects a less favorable price environment, primarily driven by the sudden, extreme drops in temperature, coupled with high winds, experienced in the Texas region during the first quarter of 2011. This weather event caused generation to go off-line and forced generators and load serving entities, like us, to purchase replacement power at significantly increased spot prices.

Mark-to-Market

Mark-to-market results include net gains and losses from origination, risk management, certain physical energy delivery activities, and trading activities for which we use the mark-to-market method of accounting. We discuss these activities and the mark-to-market method of accounting in more detail in the Critical Accounting Policies section of our 2010 Annual Report on Form 10-K.

        The nature of our operations and the use of mark-to-market accounting for certain activities create fluctuations in mark-to-market earnings. We cannot predict these fluctuations, but the impact on our earnings could be material. We discuss our market risk in more detail in the Risk Management section beginning on page 48. The primary factors that cause fluctuations in our mark-to-market results are:

        Risk management and trading—mark-to-market represents both realized and unrealized gains and losses from changes in the value of our portfolio, including the effects of changes in valuation adjustments. In addition to our fundamental risk management and trading activities, we also use non-trading derivative contracts subject to mark-to-market accounting to manage our exposure to changes in market prices, while in general the underlying physical transactions related to these activities are accounted for on an accrual basis.

        We discuss the changes in mark-to-market results below. We show the relationship between our mark-to-market results and the change in our net mark-to-market energy asset later in this section.

        Mark-to-market results were as follows:

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Unrealized mark-to-market results

             
 

Origination gains

  $   $  
 

Risk management and trading—mark-to-market

             
   

Unrealized changes in fair value

    (3.4 )   (36.2 )
   

Changes in valuation techniques

         
   

Reclassification of settled contracts to realized

    (77.0 )   (190.1 )
   
 

Total risk management and trading—mark-to-market

    (80.4 )   (226.3 )
   

Total unrealized mark-to-market1

    (80.4 )   (226.3 )

Realized mark-to-market

    77.0     190.1  
   

Total mark-to-market results2

  $ (3.4 ) $ (36.2 )
   

1 Total unrealized mark-to-market is the sum of origination gains and total risk management and trading—mark-to-market.

2 Includes gains (losses) on hedge ineffectiveness for fair value hedges recorded in gross margin.


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Table of Contents

        Total mark-to-market results increased $32.8 million during the quarter ended March 31, 2011 compared to the same period of 2010 due to unrealized changes in fair value primarily due to $64.7 million of higher results on open positions in our power and transmission risk management activities within the Texas region as well as the absence of losses in the PJM, West, New York, and MISO regions due to a more favorable price environment.

        These increases were partially offset by the following:

Derivative Assets and Liabilities

Derivative assets and liabilities, excluding exchange-traded derivatives classified as accounts receivable, consisted of the following:

 
  March 31,
2011

  December 31,
2010

 
   
 
  (In millions)
 

Current Assets

  $ 350.0   $ 534.4  

Noncurrent Assets

    234.3     258.9  
   

Total Assets

    584.3     793.3  
   

Current Liabilities

    492.8     622.3  

Noncurrent Liabilities

    299.7     353.0  
   

Total Liabilities

    792.5     975.3  
   

Net Derivative Position

  $ (208.2 ) $ (182.0 )
   

Composition of net derivative exposure:

             

Hedges

  $ (400.3 ) $ (504.5 )

Mark-to-market

    232.4     350.3  

Net cash collateral included in derivative balances

    (40.3 )   (27.8 )
   

Net Derivative Position

  $ (208.2 ) $ (182.0 )
   

Derivative balances above include noncurrent assets related to our Generation business of $25.1 million and $35.7 million at March 31, 2011 and December 31, 2010, respectively. Derivative balances related to our Generation business consist of interest rate contracts accounted for as fair value hedges. We discuss our derivative assets and liabilities in further detail in the Notes to Consolidated Financial Statements.

        The decrease of $104.2 million in our net derivative liability subject to hedge accounting since December 31, 2010 was due to $129.7 million of realization of out-of-the-money cash-flow hedges at the time the forecasted transaction occurred, partially offset by $25.5 million of increases on our net out-of-the-money cash-flow hedge positions primarily related to increases in power, natural gas, and coal prices during 2011.

        The following are the primary sources of the change in our net derivative asset subject to mark-to-market accounting during the quarter ended March 31, 2011:

   
 
  (In millions)
 

Fair value beginning of period

        $ 350.3  

Changes in fair value recorded in earnings

             
 

Origination gains

  $        
 

Unrealized changes in fair value

    (3.4 )      
 

Changes in valuation techniques

           
 

Reclassification of settled contracts to realized

    (77.0 )      
             

Total changes in fair value

          (80.4 )

Changes in value of exchange-listed futures and options

          (88.9 )

Net change in premiums on options

          (6.4 )

Contracts acquired

          (1.5 )

Dedesignated contracts and other changes in fair value

          59.3  
   

Fair value at end of period

        $ 232.4  
   

        We describe the types of changes in our net derivative asset subject to mark-to-market accounting that affected earnings in Item 7. Management's Discussion and Analysis in our 2010 Annual Report on Form 10-K.


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Table of Contents

        The settlement terms of the portion of our net derivative asset subject to mark-to-market accounting and sources of fair value based on the fair value hierarchy are as follows as of March 31, 2011:

 
  Settlement Term    
 
 
  2011
  2012
  2013
  2014
  2015
  2016
  Thereafter
  Fair Value
 
   
 
  (In millions)
 

Level 1

  $ (7.8 ) $   $   $   $   $   $   $ (7.8 )

Level 2

    340.4     254.8     14.7     9.1     4.6     0.5     (0.4 )   623.7  

Level 3

    (78.5 )   (279.4 )   (22.4 )   4.1     2.0     3.1     (12.4 )   (383.5 )
   

Total net derivative asset (liability) subject to mark-to-market accounting

  $ 254.1   $ (24.6 ) $ (7.7 ) $ 13.2   $ 6.6   $ 3.6   $ (12.8 ) $ 232.4  
   

Operating Expenses

Our NewEnergy business operating expenses increased $11.3 million during the quarter ended March 31, 2011 as compared to the same period of 2010 primarily due to growth in this business segment.


Regulated Electric Business

Our regulated electric business is discussed in detail in Item 1. Business—Electric Business section of our 2010 Annual Report on Form 10-K.

Results

 
  Quarter Ended
March 31,

 
 
  2011
  2010
 
   
 
  (In millions)
 

Revenues

  $ 650.2 &