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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 September 30, 2008

Commission File Number   Exact name of registrant as specified in its charter   IRS Employer Identification No.
1-12869   CONSTELLATION ENERGY GROUP, INC.   52-1964611
1-1910   BALTIMORE GAS AND ELECTRIC COMPANY   52-0280210

MARYLAND
(State of Incorporation of both registrants)

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

410-470-2800

(Registrants' telephone number, including area code)

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. 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 178,415,808 shares outstanding
of Constellation Energy Group, Inc. on October 31, 2008.

         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

 
  Page

Part I—Financial Information

   
 

Item 1—Financial Statements

   
           

Constellation Energy Group, Inc. and Subsidiaries

   
           

Consolidated Statements of Income (Loss)

  3
           

Consolidated Statements of Comprehensive Income (Loss)

  3
           

Consolidated Balance Sheets

  4
           

Consolidated Statements of Cash Flows

  6
           

Baltimore Gas and Electric Company and Subsidiaries

   
           

Consolidated Statements of Income (Loss)

  7
           

Consolidated Balance Sheets

  8
           

Consolidated Statements of Cash Flows

  10
           

Notes to Consolidated Financial Statements

  11
 

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

   
           

Introduction and Overview

  36
           

Strategy

  36
           

Business Environment

  37
           

Events of 2008

  37
           

Results of Operations

  40
           

Financial Condition

  58
           

Capital Resources

  63
 

Item 3—Quantitative and Qualitative Disclosures About Market Risk

  67
 

Items 4 and 4(T)—Controls and Procedures

  67

Part II—Other Information

  68
 

Item 1—Legal Proceedings

  68
 

Item 1A—Risk Factors

  68
 

Item 2—Unregistered Sales of Equity Securities and Use of Proceeds; Issuer Purchases of Equity Securities

  73
 

Item 4—Submission of Matters to Vote of Security Holders

  73
 

Item 5—Other Information

  74
 

Item 6—Exhibits

  76
 

Signature

  78

2



PART 1—FINANCIAL INFORMATION

Item 1—Financial Statements


CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions, except per share amounts)

 

Revenues

                         
 

Nonregulated revenues

  $ 4,351.0   $ 4,965.4   $ 12,187.2   $ 13,332.1  
 

Regulated electric revenues

    822.3     778.2     1,980.3     1,837.3  
 

Regulated gas revenues

    150.3     112.8     724.4     674.4  
   
 

Total revenues

    5,323.6     5,856.4     14,891.9     15,843.8  

Expenses

                         
 

Fuel and purchased energy expenses

    4,318.0     4,549.7     11,620.5     12,451.6  
 

Operating expenses

    482.9     653.6     1,784.5     1,802.7  
 

Impairments and other costs

    477.1         477.1     20.2  
 

Merger and strategic alternatives costs

    39.2         39.2      
 

Workforce reduction costs

    2.2         2.2     2.3  
 

Depreciation, depletion, and amortization

    134.3     138.3     424.5     413.5  
 

Accretion of asset retirement obligations

    17.2     16.0     50.8     51.9  
 

Taxes other than income taxes

    81.1     73.7     227.0     219.7  
   
 

Total expenses

    5,552.0     5,431.3     14,625.8     14,961.9  

Gains on Sales of Assets

            91.5      
   

(Loss) Income from Operations

    (228.4 )   425.1     357.6     881.9  

Gains on Sale of CEP LLC Equity

   
   
39.2
   
   
52.1
 

Other (Expense) Income

   
(16.1

)
 
29.1
   
41.3
   
116.7
 

Fixed Charges

                         
 

Interest expense

    100.0     80.3     252.3     231.7  
 

Interest capitalized and allowance for borrowed funds used during construction

    (10.5 )   (5.2 )   (26.2 )   (13.6 )
 

BGE preference stock dividends

    3.3     3.3     9.9     9.9  
   
 

Total fixed charges

    92.8     78.4     236.0     228.0  
   

(Loss) Income from Continuing Operations Before Income Taxes

    (337.3 )   415.0     162.9     822.7  

Income Tax (Benefit) Expense

    (111.6 )   164.3     71.4     258.4  
   

(Loss) Income from Continuing Operations

    (225.7 )   250.7     91.5     564.3  
 

Income (Loss) from discontinued operations, net of income taxes of $0.7 and $1.5, respectively

        0.7         (0.9 )
   

Net (Loss) Income

  $ (225.7 ) $ 251.4   $ 91.5   $ 563.4  
   

(Loss) Earnings Applicable to Common Stock

  $ (225.7 ) $ 251.4   $ 91.5   $ 563.4  
   

Average Shares of Common Stock Outstanding—Basic

    178.4     180.5     178.3     180.5  

Average Shares of Common Stock Outstanding—Diluted

    179.5     182.8     180.0     182.8  

(Loss) Earnings Per Common Share from Continuing Operations—Basic

  $ (1.27 ) $ 1.39   $ 0.51   $ 3.13  
 

Loss from discontinued operations

                (0.01 )
   

(Loss) Earnings Per Common Share—Basic

  $ (1.27 ) $ 1.39   $ 0.51   $ 3.12  
   

(Loss) Earnings Per Common Share from Continuing Operations—Diluted

  $ (1.27 ) $ 1.37   $ 0.51   $ 3.09  
 

Income (Loss) from discontinued operations

        0.01         (0.01 )
   

(Loss) Earnings Per Common Share—Diluted

  $ (1.27 ) $ 1.38   $ 0.51   $ 3.08  
   

Dividends Declared Per Common Share

  $ 0.4775   $ 0.435   $ 1.4325   $ 1.305  
   


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)

 

Net (Loss) Income

  $ (225.7 ) $ 251.4   $ 91.5   $ 563.4  
 

Other comprehensive income (loss) (OCI)

                         
   

Hedging instruments:

                         
     

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

    (166.4 )   275.1     (88.4 )   833.4  
     

Net unrealized loss on hedging instruments, net of taxes

    (1,059.4 )   (360.0 )   (186.0 )   (498.4 )
   

Available-for-sale securities:

                         
     

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

    8.9     (0.5 )   10.5     (3.3 )
     

Net unrealized (loss) gain on securities, net of taxes

    (79.1 )   (13.0 )   (107.8 )   0.7  
   

Defined benefit obligations:

                         
     

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

    5.4     5.8     15.9     18.3  
   

Net unrealized gain on foreign currency, net of taxes

    0.5     3.3     0.1     6.4  
   

Comprehensive (Loss) Income

  $ (1,515.8 ) $ 162.1   $ (264.2 ) $ 920.5  
   

See Notes to Consolidated Financial Statements.

3



CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

 
  September 30,
2008*
  December 31,
2007
 

 

 
 
  (In millions)
 

Assets

             
 

Current Assets

             
   

Cash and cash equivalents

  $ 1,434.0   $ 1,095.9  
   

Accounts receivable (net of allowance for uncollectibles of
$162.0 and $44.9, respectively)

    4,041.7     4,289.5  
   

Fuel stocks

    912.9     591.3  
   

Materials and supplies

    227.9     207.5  
   

Derivative assets

    1,604.7     760.6  
   

Unamortized energy contract assets

    67.0     32.0  
   

Deferred income taxes

        300.7  
   

Other

    727.7     408.1  
   
   

Total current assets

    9,015.9     7,685.6  
   

Investments and Other Noncurrent Assets

             
   

Nuclear decommissioning trust funds

    1,168.6     1,330.8  
   

Other investments

    475.4     542.2  
   

Regulatory assets (net)

    511.9     576.2  
   

Goodwill

    7.5     261.3  
   

Derivative assets

    1,006.0     1,030.2  
   

Unamortized energy contract assets

    160.8     178.3  
   

Other

    397.8     370.6  
   
   

Total investments and other noncurrent assets

    3,728.0     4,289.6  
   

Property, Plant and Equipment

             
   

Property, plant and equipment

    15,200.9     14,138.2  
   

Nuclear fuel (net of amortization)

    395.5     374.3  
   

Accumulated depreciation

    (4,986.6 )   (4,745.4 )
   
   

Net property, plant and equipment

    10,609.8     9,767.1  
   
 

Total Assets

 
$

23,353.7
 
$

21,742.3
 
   

* Unaudited

See Notes to Consolidated Financial Statements.

Certain prior-period amounts have been reclassified to conform with the current period's presentation.

4


CONSOLIDATED BALANCE SHEETS

Constellation Energy Group, Inc. and Subsidiaries

 
  September 30,
2008*
  December 31,
2007
 

 

 
 
  (In millions)
 

Liabilities and Equity

             
 

Current Liabilities

             
   

Short-term borrowings

  $ 1,249.5   $ 14.0  
   

Current portion of long-term debt

    644.2     380.6  
   

Accounts payable and accrued liabilities

    2,650.5     2,630.1  
   

Customer deposits and collateral

    127.8     146.6  
   

Derivative liabilities

    1,115.8     1,134.3  
   

Unamortized energy contract liabilities

    390.6     392.2  
   

Deferred income taxes

    42.3      
   

Accrued expenses and other

    697.0     956.0  
   
   

Total current liabilities

    6,917.7     5,653.8  
   
 

Deferred Credits and Other Noncurrent Liabilities

             
   

Deferred income taxes

    1,061.4     1,588.5  
   

Asset retirement obligations

    970.6     917.6  
   

Derivative liabilities

    1,171.1     1,118.9  
   

Unamortized energy contract liabilities

    984.7     1,218.6  
   

Defined benefit obligations

    781.2     828.6  
   

Deferred investment tax credits

    45.7     50.5  
   

Other

    150.5     155.9  
   
   

Total deferred credits and other noncurrent liabilities

    5,165.2     5,878.6  
   
 

Long-term Debt, net of current portion

   
6,201.8
   
4,660.5
 
 

Minority Interests

   
20.4
   
19.2
 
 

BGE Preference Stock Not Subject to Mandatory Redemption

   
190.0
   
190.0
 
 

Common Shareholders' Equity

             
   

Common stock

    2,586.7     2,513.3  
   

Retained earnings

    3,720.2     3,919.5  
   

Accumulated other comprehensive loss

    (1,448.3 )   (1,092.6 )
   
   

Total common shareholders' equity

    4,858.6     5,340.2  
   
 

Commitments, Guarantees, and Contingencies (see Notes)

             
 

Total Liabilities and Equity

 
$

23,353.7
 
$

21,742.3
 
   

* Unaudited

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

5



CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Constellation Energy Group, Inc. and Subsidiaries

Nine Months Ended September 30,
  2008
  2007
 

 

 
 
  (In millions)
 

Cash Flows From Operating Activities

             
 

Net income

  $ 91.5   $ 563.4  
 

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

             
   

Depreciation, depletion, and amortization

    424.5     413.5  
   

Amortization of nuclear fuel

    91.2     84.5  
   

Amortization of energy contracts

    (193.8 )   (196.7 )
   

All other amortization

    18.2     8.4  
   

Accretion of asset retirement obligations

    50.8     51.9  
   

Deferred income taxes

    45.0     118.7  
   

Investment tax credit adjustments

    (4.8 )   (5.0 )
   

Deferred fuel costs

    40.8     (248.7 )
   

Defined benefit obligation expense

    77.2     105.7  
   

Defined benefit obligation payments

    (111.4 )   (153.7 )
   

Workforce reduction costs

    2.2     2.3  
   

Impairments and other costs

    477.1     20.2  
   

Gains on sale of CEP LLC equity

        (52.1 )
   

Gains on sales of assets and investments

    (103.8 )    
   

Gains on termination of contracts

    (81.6 )    
   

Equity in earnings of affiliates less than dividends received

    1.1     36.6  
   

Derivative power sales contracts classified as financing activities under SFAS No. 149

    (37.1 )   15.1  
   

Changes in working capital

             
     

Accounts receivable, excluding margin

    221.2     (118.1 )
     

Derivative assets and liabilities, excluding collateral

    (935.0 )   (78.9 )
     

Net collateral and margin

    (568.6 )   109.8  
     

Materials, supplies, and fuel stocks

    (231.8 )   10.9  
     

Other current assets

    (134.7 )   (58.8 )
     

Accounts payable and accrued liabilities

    57.2     100.4  
     

Other current liabilities

    (270.5 )   (107.3 )
   

Other

    51.1     (5.4 )
   
 

Net cash (used in) provided by operating activities

    (1,024.0 )   616.7  
   

Cash Flows From Investing Activities

             
 

Investments in property, plant and equipment

    (1,360.5 )   (920.3 )
 

Acquisitions, net of cash acquired

    (316.5 )   (344.1 )
 

Investments in nuclear decommissioning trust fund securities

    (365.4 )   (514.6 )
 

Proceeds from nuclear decommissioning trust fund securities

    346.7     505.8  
 

Proceeds from sales of property, plant and equipment

    226.8      
 

Proceeds from sales of investments and other assets

    14.4     5.6  
 

Contract and portfolio acquisitions

        (474.2 )
 

Issuances of loans receivable

        (19.0 )
 

Repayments of loans receivable

    26.0     31.9  
 

Decrease (increase) in restricted funds

    8.3     (26.5 )
 

Other

    (4.1 )   (70.8 )
   
 

Net cash used in investing activities

    (1,424.3 )   (1,826.2 )
   

Cash Flows From Financing Activities

             
 

Net issuance of short-term borrowings

    1,207.5      
 

Proceeds from issuance of common stock

    17.6     47.7  
 

Proceeds from issuance of long-term debt (includes $1 billion proceeds from MidAmerican Energy Holdings Company)

    2,100.0     647.2  
 

Repayment of long-term debt

    (265.7 )   (740.2 )
 

Debt issuance costs

    (50.6 )    
 

Common stock dividends paid

    (250.7 )   (226.8 )
 

Reacquisition of common stock

    (16.2 )   (114.4 )
 

Proceeds from contract and portfolio acquisitions

        847.8  
 

Derivative power sales contracts classified as financing activities under SFAS No. 149

    37.1     (15.1 )
 

Other

    7.4     25.9  
   
 

Net cash provided by financing activities

    2,786.4     472.1  
   

Net Increase (Decrease) in Cash and Cash Equivalents

    338.1     (737.4 )

Cash and Cash Equivalents at Beginning of Period

    1,095.9     2,289.1  
   

Cash and Cash Equivalents at End of Period

  $ 1,434.0   $ 1,551.7  
   

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

6



CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

 
  Three Months Ended September 30,
  Nine Months Ended September 30,
 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Revenues

                         
 

Electric revenues

  $ 822.4   $ 778.2   $ 1,980.5   $ 1,837.3  
 

Gas revenues

    155.5     118.7     740.0     688.8  
   
 

Total revenues

    977.9     896.9     2,720.5     2,526.1  

Expenses

                         
 

Operating expenses

                         
   

Electricity purchased for resale

    556.6     522.6     1,416.2     1,117.7  
   

Gas purchased for resale

    107.5     70.6     505.2     457.6  
   

Operations and maintenance

    139.5     134.8     409.9     389.2  
   

Merger and strategic alternatives costs

    11.1         11.1      
 

Depreciation and amortization

    49.5     58.4     171.2     175.8  
 

Taxes other than income taxes

    44.1     44.0     130.7     132.8  
   
 

Total expenses

    908.3     830.4     2,644.3     2,273.1  
   

Income from Operations

    69.6     66.5     76.2     253.0  

Other Income

    9.0     9.2     23.4     19.2  

Fixed Charges

                         
 

Interest expense

    38.6     35.3     105.6     92.4  
 

Allowance for borrowed funds used during construction

    (1.2 )   (0.7 )   (3.3 )   (1.8 )
   
 

Total fixed charges

    37.4     34.6     102.3     90.6  
   

Income (Loss) Before Income Taxes

    41.2     41.1     (2.7 )   181.6  

Income Taxes

    18.0     13.4     1.9     67.7  
   

Net Income (Loss)

    23.2     27.7     (4.6 )   113.9  

Preference Stock Dividends

    3.3     3.3     9.9     9.9  
   

Earnings (Loss) Applicable to Common Stock

  $ 19.9   $ 24.4   $ (14.5 ) $ 104.0  
   

See Notes to Consolidated Financial Statements.

7



CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

 
  September 30,
2008*
  December 31,
2007
 

 

 
 
  (In millions)
 

Assets

             
 

Current Assets

             
   

Cash and cash equivalents

  $ 10.6   $ 17.6  
   

Accounts receivable (net of allowance for uncollectibles of
$29.6 and $20.3, respectively)

    193.6     316.7  
   

Accounts receivable, unbilled (net of allowance for uncollectibles of
$0.8 and $0.8, respectively)

    155.5     209.5  
   

Investment in cash pool, affiliated company

    63.1     78.4  
   

Accounts receivable, affiliated companies

    2.3     4.2  
   

Fuel stocks

    172.9     98.8  
   

Materials and supplies

    42.3     42.7  
   

Prepaid taxes other than income taxes

    67.1     49.9  
   

Regulatory assets (net)

    86.9     74.9  
   

Restricted cash

    44.5     39.2  
   

Income taxes refundable

    94.4      
   

Other

    2.0     7.4  
   
   

Total current assets

    935.2     939.3  
   
 

Investments and Other Assets

             
   

Regulatory assets (net)

    511.9     576.2  
   

Receivable, affiliated company

    167.8     149.2  
   

Other

    129.2     148.1  
   
   

Total investments and other assets

    808.9     873.5  
   
 

Utility Plant

             
   

Plant in service

             
     

Electric

    4,425.8     4,244.4  
     

Gas

    1,209.5     1,181.7  
     

Common

    452.3     456.1  
   
     

Total plant in service

    6,087.6     5,882.2  
   

Accumulated depreciation

    (2,163.8 )   (2,080.8 )
   
   

Net plant in service

    3,923.8     3,801.4  
   

Construction work in progress

    235.4     166.4  
   

Plant held for future use

    2.6     2.4  
   
   

Net utility plant

    4,161.8     3,970.2  
   
 

Total Assets

 
$

5,905.9
 
$

5,783.0
 
   

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

8



CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

 
  September 30,
2008*
  December 31,
2007
 

 

 
 
  (In millions)
 

Liabilities and Equity

             
 

Current Liabilities

             
   

Short-term borrowings

  $ 189.0   $  
   

Current portion of long-term debt

    142.2     375.0  
   

Accounts payable and accrued liabilities

    188.5     182.4  
   

Accounts payable and accrued liabilities, affiliated companies

    113.2     164.5  
   

Customer deposits and collateral

    73.2     70.5  
   

Current portion of deferred income taxes

    46.1     44.1  
   

Accrued taxes

    19.5     34.4  
   

Accrued expenses and other

    107.9     96.3  
   
   

Total current liabilities

    879.6     967.2  
   
 

Deferred Credits and Other Liabilities

             
   

Deferred income taxes

    816.7     785.6  
   

Payable, affiliated company

    245.5     243.7  
   

Deferred investment tax credits

    10.9     11.9  
   

Other

    24.8     33.6  
   
   

Total deferred credits and other liabilities

    1,097.9     1,074.8  
   
 

Long-term Debt

             
   

Rate stabilization bonds

    589.9     623.2  
   

First refunding mortgage bonds

        119.7  
   

Other long-term debt

    1,508.0     1,214.5  
   

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  
   

Long-term debt of nonregulated businesses

    25.0     25.0  
   

Unamortized discount and premium

    (2.4 )   (2.6 )
   

Current portion of long-term debt

    (142.2 )   (375.0 )
   
   

Total long-term debt

    2,236.0     1,862.5  
   
 

Minority Interest

   
17.0
   
16.8
 
 

Preference Stock Not Subject to Mandatory Redemption

   
190.0
   
190.0
 
 

Common Shareholder's Equity

             
   

Common stock

    912.2     912.2  
   

Retained earnings

    572.6     758.8  
   

Accumulated other comprehensive income

    0.6     0.7  
   
   

Total common shareholder's equity

    1,485.4     1,671.7  
   
 

Commitments, Guarantees, and Contingencies (see Notes)

             
 

Total Liabilities and Equity

 
$

5,905.9
 
$

5,783.0
 
   

* Unaudited
See Notes to Consolidated Financial Statements.

9



CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

Nine Months Ended September 30,
  2008
  2007
 

 

 
 
  (In millions)
 

Cash Flows From Operating Activities

             
 

Net (loss) income

  $ (4.6 ) $ 113.9  
 

Adjustments to reconcile to net cash provided by operating activities

             
   

Depreciation and amortization

    171.2     175.8  
   

Other amortization

    10.2     9.5  
   

Deferred income taxes

    20.5     85.5  
   

Investment tax credit adjustments

    (1.0 )   (1.2 )
   

Deferred fuel costs

    40.8     (248.7 )
   

Defined benefit plan expenses

    27.3     31.7  
   

Allowance for equity funds used during construction

    (6.1 )   (3.4 )
   

Changes in

             
     

Accounts receivable

    177.1     (125.7 )
     

Accounts receivable, affiliated companies

    1.9     (0.7 )
     

Materials, supplies, and fuel stocks

    (73.7 )   (6.5 )
     

Other current assets

    (106.0 )   47.0  
     

Accounts payable and accrued liabilities

    6.1     (49.2 )
     

Accounts payable and accrued liabilities, affiliated companies

    (51.3 )   7.5  
     

Other current liabilities

    12.2     31.3  
     

Long-term receivables and payables, affiliated companies

    (44.1 )   (38.5 )
     

Other

    (36.7 )   (22.4 )
   
 

Net cash provided by operating activities

    143.8     5.9  
   

Cash Flows From Investing Activities

             
 

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

    (319.0 )   (264.6 )
 

Change in cash pool at parent

    15.3     (201.2 )
 

Sales of investments and other assets

    12.9      
 

Increase in restricted funds

    (5.4 )   (21.1 )
   
 

Net cash used in investing activities

    (296.2 )   (486.9 )
   

Cash Flows From Financing Activities

             
 

Proceeds from issuance of short-term borrowings

    189.0      
 

Proceeds from issuance of long-term debt

    400.0     623.2  
 

Repayment of long-term debt

    (259.5 )   (124.8 )
 

Debt issuance costs

    (2.5 )    
 

Preference stock dividends paid

    (9.9 )   (9.9 )
 

Distribution to parent

    (171.7 )    
   
 

Net cash provided by financing activities

    145.4     488.5  
   

Net (Decrease) Increase in Cash and Cash Equivalents

    (7.0 )   7.5  

Cash and Cash Equivalents at Beginning of Period

    17.6     10.9  
   

Cash and Cash Equivalents at End of Period

  $ 10.6   $ 18.4  
   

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

10



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

Reclassifications

We have reclassified certain prior-period amounts:

Pending Merger with MidAmerican Energy Holdings Company

On September 19, 2008, Constellation Energy entered into an Agreement and Plan of Merger with MidAmerican Energy Holdings Company (MidAmerican) under which MidAmerican will acquire Constellation Energy for $26.50 per common share. As a result, upon closing of the transaction, Constellation Energy will become a wholly owned subsidiary of MidAmerican.

        In connection with the merger transaction, on September 22, 2008, Constellation Energy issued 10,000 shares of 8% Series A Convertible Preferred Stock (Preferred Stock) of Constellation Energy to MidAmerican for an aggregate purchase price of $1 billion. We discuss this Preferred Stock in more detail beginning on page 21.

        The merger agreement has been approved by both companies' boards of directors, but completion of the merger is contingent upon, among other things:

        The parties are working to complete the merger in the second quarter of 2009. The merger agreement may be terminated by either party if the merger does not occur by June 19, 2009 (or September 19, 2009 if all conditions other than those relating to regulatory approvals, debt ratings, and/or required consents have been fulfilled as of June 19, 2009). We discuss our risk factors associated with this merger in the Risk Factors section beginning on page 68.

        The merger agreement contains certain termination rights for both Constellation Energy and MidAmerican. If

11


the merger agreement is terminated for any reason other than a breach of the merger agreement by MidAmerican:

        In addition, the Preferred Stock will automatically convert as set forth above if the merger is not completed by June 19, 2009 (which may be extended to September 19, 2009).

        Constellation Energy has agreed that the maximum aggregate liability of MidAmerican for losses or damages in connection with the merger agreement would be limited to $1 billion. Our recourse for such losses or damages is limited to the Preferred Stock issued to MidAmerican or the shares of Constellation Energy common stock and $1 billion in senior notes issued upon conversion of the Preferred Stock or the proceeds of the redemption or repayment of the Preferred Stock or senior notes. In addition, if Constellation Energy attempts to challenge the validity of the $1 billion damage cap, such amount is automatically reduced to $1,000.

Merger and Strategic Alternatives Costs

We incurred costs during the quarter ended September 30, 2008 related to our pending merger with MidAmerican and our pursuit of other strategic alternatives to the merger with MidAmerican. These costs totaled $39.2 million pre-tax, including a payment of $25 million to MidAmerican, of which BGE recorded $11.1 million. A significant portion of these costs are not tax deductible, and BGE will not seek recovery of these costs in regulated electric and gas service rates.

Impairments and Other Costs

Impairment Evaluations

We discuss our evaluations of assets for impairment and other than temporary declines in value in the Significant Accounting Policies section of our 2007 Annual Report on Form 10-K. We perform impairment evaluations for our long-lived assets, equity method investments, nuclear decommissioning trust assets, and goodwill when triggering events occur that would indicate that the potential for an impairment exists.

        In addition, Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets requires goodwill to be evaluated for impairment on an annual basis regardless of whether any triggering events have occurred. Our accounting policy is to perform that annual impairment review in the third quarter of each year.

        During the third quarter of 2008, the following triggering events resulted in the need for us to perform impairment analyses:

        As a result of these evaluations, we recorded impairments of our upstream gas assets, goodwill, and certain investments in debt and equity securities. We describe the impairment evaluations we performed in the following sections.

Long-Lived Assets

We evaluate potential impairment of long-lived assets classified as held for use under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which provides that an impairment loss shall be recognized if the carrying amount of such assets is not recoverable. The carrying amount of an asset held for use is not recoverable if it exceeds the total undiscounted future cash flows expected to result from the use and eventual disposition of the asset.

        This evaluation requires us to estimate uncertain future cash flows. In order to estimate future cash flows, we consider historical cash flows and changes in the market environment and other factors that may affect future cash flows. The assumptions we use are consistent with forecasts that we make for other purposes (for example, in preparing our other earnings forecasts) or have been adjusted to reflect relevant subsequent changes. If we are considering alternative courses of action (such as the potential sale of an asset), we probability-weight the alternative courses of action to estimate the expected cash flows.

        We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, and operating costs. However, actual

12


future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

Upstream Gas Properties

During the third quarter of 2008, we performed impairment analyses for our upstream gas properties as a result of the following triggering events:

        We evaluate proved properties under SFAS No. 144. We evaluate unproved property under SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Properties. Unproved property is impaired if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience necessitates a valuation allowance. To the extent that unproved property is part of an asset that contains proved property, the accounting guidance under SFAS No. 144 applies for evaluating impairment.

        While we have begun the process necessary to sell these properties, we have not yet obtained the formal approval of our board of directors, which is required to commit to a plan for sale. As a result, we continue to classify these properties as held for use as of September 30, 2008. Accordingly, our impairment evaluation consisted of estimating expected undiscounted cash flows and comparing those amounts to the carrying value.

        We evaluated our upstream gas portfolio for impairment at the individual property level, which is the lowest level of identifiable cash flows, since each property has separate financial statements identifying and capturing the related cash flows. We evaluated a combination of cash flows from operations scenarios for the remaining period for which we expect to hold these properties as well as estimates of proceeds from each property's ultimate disposal. The primary inputs to our estimates of cash flows from operations were natural gas and oil prices based upon forward curves and modeled data for unobservable periods. The primary inputs to our estimate of proceeds from disposal were a combination of external market bids, internal models and reserve reports, and information from external advisors assisting in the sale of these assets. We maximized the use of market information to the extent it was available. We evaluated several possible courses of action and timing, and we probability-weighted the cash flows associated with each of these scenarios based upon our best estimates of the expected outcome and timing in order to arrive at each property's expected future cash flows.

        Our evaluation indicated that estimated cash flows were less than the carrying value of three of our seven upstream gas properties. The primary factor leading to the decline in expected cash flows was the decrease in market prices for natural gas and oil during the third quarter of 2008 combined with our expectation that we would sell these properties rather than hold them for their full useful lives. As a result, we recorded an approximately $143 million pre-tax impairment charge during the quarter ended September 30, 2008 to write-down each impaired property's carrying value to fair value. The asset groups impaired include our interest in proved and unproved crude oil and natural gas reserves in south Texas of $62.6 million, proved natural gas reserves in the Rocky Mountains of $73.2 million, and proved and unproved natural gas reserves in the Offshore-Gulf of Mexico of $7.1 million.

        We recorded the total impairment charge in the "Impairments and Other Costs" line in our Consolidated Statements of Income (Loss), and it is reported in our merchant energy business results. The impairment charge for our interest in the Rocky Mountains natural gas reserves was offset partially by reclassifying cash-flow hedges with a pre-tax net gain deferred in "Accumulated other comprehensive loss" of $4.5 million into "Nonregulated revenues" in the Consolidated Statements of Income (Loss).

Debt and Equity Securities

We evaluated certain of our investments in debt and equity securities (both equity-method and cost-method investments) in light of recent declines in market prices, particularly during the month of September 2008. The investments we evaluated include our investment in Constellation Energy Partners LLC (CEP), our nuclear decommissioning trust fund assets, and our investment in UniStar Nuclear Energy (UNE). We record an impairment if an investment has experienced a decline in fair value to a level less than our carrying value and the decline is "other than temporary." We do not record an impairment if the decline in value is temporary and we have the ability and intent to hold the investment until its value recovers.

        In making this determination, we evaluate the reasons for an investment's decline in value, the extent and length of that decline, and factors that indicate whether and when the value will recover. For securities held in our nuclear decommissioning trust fund for which the market value is below book value, the decline in fair value for these securities is considered other than temporary and we write them down to fair value.

        As of September 30, 2008, the fair value of our investment in CEP based upon its closing unit price was $73 million, which was lower than its carrying value of $128 million. The fair value of our investment fell below

13


carrying value at the end of August, continued to decline through the end of September, and has further declined during October. While CEP's estimate of net asset value exceeds our carrying value, the decline in fair value of our investment in CEP reflects a number of other factors, including:

        As a result of evaluating these factors, we determined that the decline in the value of our investment is other than temporary. Therefore, we recorded an approximately $55 million pre-tax impairment charge during the quarter ended September 30, 2008 to write-down our investment to fair value as of that date. We recorded this charge in "Impairments and other costs" in our Consolidated Statements of Income (Loss). To the extent that the market price of our investment declines further in future quarters, we may record additional write-downs if we determine that those additional declines are other than temporary.

        As a result of significant declines in the stock market during the third quarter of 2008, the fair values of several of the securities held in our nuclear decommissioning trust fund declined below book value. As a result, we recorded an approximately $31 million pre-tax impairment charge in the "Other (expense) income" line in our Consolidated Statements of Income (Loss). In addition, we recorded other changes in the fair value of our nuclear decommissioning trust fund assets that are not impaired in other comprehensive income.

        We also evaluated the impact of the events that occurred in the third quarter of 2008 on the recoverability of our investment in UNE. Based upon our consideration of these events and the status of UNE's activities, we determined that our investment in UNE is not impaired as of September 30, 2008.

        The estimates we utilize in evaluating impairment of our debt and equity securities require judgment and the evaluation of economic and other factors that are subject to variation, and the impact of such variations could be material.

Goodwill

Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We account for goodwill and other intangibles under the provisions of SFAS No. 142. SFAS No. 142 requires us to evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, in the third quarter of each year, we evaluate goodwill for impairment.

        The primary judgment affecting our impairment evaluation is the requirement to estimate fair value of the reporting units to which the goodwill relates. We evaluate impairment at the reportable segment level, which is the lowest level in the organization that constitutes a business for which discreet financial information is available.

        Substantially all of our goodwill relates to our merchant energy segment. The lack of observable market prices for the merchant energy segment requires us to estimate fair value, which we determined on a preliminary basis using the income valuation approach by computing discounted cash flows, consistent with prior evaluations. Although our estimate of discounted cash flows exceeded the carrying value of the merchant energy segment, because our common stock continued to trade at a price less than carrying value for the entire company throughtout the last half of September and all of October, we also estimated fair value for the merchant energy segment using current market price information.

        The primary inputs and assumptions to our estimate of fair value based upon market information were as follows:

        Using this information, we deducted the estimated fair value of non-merchant energy segment businesses from the fair value of Constellation Energy as a whole in order to estimate the fair value of the merchant energy segment. Based upon this estimate, the fair value of the merchant energy segment was substantially less than its carrying value. The primary difference between this estimate and our modeled estimates using the discounted cash flow income approach is that the market price approach incorporates the market's valuation discount associated with our merchant energy segment due to its significant liquidity and collateral requirements. We believe that this is a more appropriate method for estimating fair value as of the end of September 2008 than the modeled valuation techniques because it incorporates observable market information to a greater extent, which reflects current market conditions, and

14


because it requires fewer and less subjective judgments and estimates than our modeled estimates.

        As a final consideration, we also evaluated the circumstances surrounding MidAmerican's purchase of Constellation Energy and whether the current market price of our common stock should be considered to represent fair value for accounting purposes. While the transaction price for the purchase of Constellation Energy resulted from negotiations that occurred over an abbreviated period of time during which the Company was experiencing financial difficulty, ongoing trading of the stock at levels approximating the transaction price represents the market's present assessment of fair value in a liquid, active market. This is consistent with recent guidance issued by the SEC Office of the Chief Accountant and FASB Staff on the determination of fair value in distressed markets.

        Based on our evaluation of these alternative measures of fair value, we determined that the fair value of the merchant energy business segment is less than its carrying value. Therefore, in order to measure the potential impairment of goodwill, we estimated the fair value of the merchant energy segment's assets and liabilities. We determined that the fair value of its assets net of liabilities substantially exceeds the segment's total fair value, indicating that the merchant energy segment's goodwill is impaired as of September 30, 2008. Accordingly, we recorded a pre-tax charge of approximately $265 million to write-off the entire balance of our merchant energy segment goodwill as of September 30, 2008. This charge is recorded in "Impairments and other costs" in our Consolidated Statements of Income (Loss).

Other Costs

In September 2008, we entered into a non-binding agreement to settle a class action complaint that alleged a subsidiary's ash placement operations at a third party site damaged surrounding properties. As a result of this agreement, we estimated and recorded a $15 million pre-tax charge net of an expected insurance recovery during the quarter ended September 30, 2008.

Variable Interest Entities

We have a significant interest in the following variable interest entities (VIE) for which we are not the primary beneficiary:

VIE
  Nature of
Involvement

  Date of
Involvement

 

Power projects

 

Equity investment and guarantees

  Prior to 2003

Power contract monetization entities

 

Power sale agreements, loans, and guarantees

 

March 2005

Retail power supply

 

Power sale agreement

 

September 2006

        We discuss the nature of our involvement with the power contract monetization VIEs in detail in Note 4 to our 2007 Annual Report on Form 10-K.

        The following is summary information available as of September 30, 2008 about the VIEs in which we have a significant interest, but are not the primary beneficiary:

 
  Power
Contract
Monetization
VIEs

  All Other
VIEs

  Total
 

 

 
 
  (In millions)
 

Total assets

  $ 673.0   $ 394.0   $ 1,067.0  

Total liabilities

    529.7     216.5     746.2  

Our ownership interest

        48.1     48.1  

Other ownership interests

    143.3     129.4     272.7  

Our maximum exposure to loss

    48.4     224.2     272.6  

        The maximum exposure to loss represents the loss that we would incur in the unlikely event that our interests in all of these entities were to become worthless and we were required to fund the full amount of all guarantees associated with these entities.

        Our maximum exposure to loss as of September 30, 2008 consists of the following:

        We assess the risk of a loss equal to our maximum exposure to be remote.

15


Workforce Reduction Costs

We incurred costs related to workforce reduction efforts initiated at our nuclear generating facilities in 2006 and 2007. We discuss these costs in more detail in Note 2 of our 2007 Annual Report on Form 10-K. We substantially completed both of these workforce reduction efforts during 2008.

        In September 2008, our merchant energy business approved a restructuring of the workforce at our Customer Supply operations. We recognized a liability of $2.2 million pre-tax during the quarter ended September 30, 2008 related to the elimination of approximately 100 positions associated with this restructuring. The restructuring is expected to be completed within the next 12 months.

Earnings Per Share

Basic earnings per common share (EPS) is computed by dividing earnings applicable 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
September 30,

  Nine Months Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Non-dilutive stock options

    2.6         1.5      

Dilutive common stock equivalent shares

    1.1     2.3     1.7     2.3  
   

As a result of the Company incurring a loss for the quarter ended September 30, 2008, diluted common stock equivalent shares were not included in calculating diluted EPS.

        The $1 billion in Preferred Stock issued to MidAmerican on September 22, 2008, is convertible into Constellation Energy's common stock as discussed in more detail beginning on page 21. This conversion feature did not impact our diluted earnings per share for the quarter ended September 30, 2008, but it will impact our diluted earnings per share in future periods.

Accretion of Asset Retirement Obligations

We discuss our asset retirement obligations in more detail in Note 1 of our 2007 Annual Report on Form 10-K. The change in our "Asset retirement obligations" liability during 2008 was as follows:

 

 
 
  (In millions)
 

Liability at January 1, 2008

  $ 917.6  

Accretion expense

    50.8  

Liabilities incurred

    1.0  

Liabilities settled

    (0.6 )

Revisions to cash flows

    2.0  

Other

    (0.2 )
   

Liability at September 30, 2008

  $ 970.6  
   

Acquisitions

Hillabee Energy Center

On February 14, 2008, we acquired the Hillabee Energy Center, a partially completed 774MW gas-fired combined cycle power generation facility located in Alabama for $156.9 million (including direct costs), which we accounted for as an asset acquisition. We allocated the purchase price primarily to the equipment with lesser amounts allocated to land and contracts acquired. We plan to complete the construction of this facility and expect it to be ready for commercial operation in late 2009.

West Valley Power Plant

On June 1, 2008, we acquired the West Valley Power Plant, a 200MW gas-fired peaking plant located in Utah for approximately $88.6 million (including direct costs). We accounted for this transaction as an asset acquisition and have included this plant's results of operations in the Generation operations of our merchant energy business segment since the date of acquisition. We allocated the purchase price primarily to the equipment with lesser amounts allocated to land and spare parts inventory.

Nufcor International Limited

On June 26, 2008, we acquired Nufcor International Limited (Nufcor). We include Nufcor as part of our Global Commodities operations in our merchant energy business segment and have included its results of operations in our consolidated financial statements since the date of acquisition. Nufcor is a uranium market participant that provides marketing services to uranium producers, utilities and an investment fund in the North American and European markets.

        We acquired 100% ownership of Nufcor for $102.8 million, including direct costs, of which $104.9 million was paid in cash at closing. Subsequent to

16


closing, we received $3.1 million back from the seller as a result of adjustments to Nufcor's net assets. As part of the purchase, we acquired $37.3 million in cash.

        The total consideration related to Nufcor was allocated to the net assets acquired as follows:

At June 26, 2008
   
 

 

 
 
  (In millions)
 

Cash

  $ 37.3  

Fuel stocks

    126.8  

Other current assets

    8.5  
   

Total current assets

    172.6  

Goodwill(1)(2)

    6.3  

Other assets

    30.4  
   

Total assets acquired

    209.3  
   

Short-term borrowings

    (28.0 )

Unamortized energy contract liabilities

    (15.8 )

Other current liabilities

    (29.7 )
   

Total current liabilities

    (73.5 )

Unamortized energy contract liabilities

    (33.0 )
   

Total liabilities

    (106.5 )
   

Net assets acquired

  $ 102.8  
   

(1) Not deductible for tax purposes.
(2) Amount has been subsequently charged to expense as part of our merchant energy goodwill impairment charge recorded during the third quarter of 2008.

        Our initial purchase price allocation is based on preliminary estimates and the purchase price is subject to adjustments, which could impact our purchase price allocation.

        The pro-forma impact of the Nufcor acquisition would not have been material to our results of operations for the three and nine months ended September 30, 2008 and 2007.

        In connection with efforts to improve our liquidity, we announced strategic initiatives that included the sale of our international business, including Nufcor. We discuss our strategy in more detail on page 21.

Asset Sales

Working Interests in Gas Producing Fields

On June 30, 2008, our merchant energy business sold a portion of its working interests in proved natural gas reserves and unproved properties in Arkansas for total proceeds of $145.4 million, which is subject to certain purchase price adjustments. Our merchant energy business recognized a $76.5 million pre-tax gain on this sale.

        In addition, on March 31, 2008, we sold our working interest in certain oil and natural gas producing properties to CEP, a related party, and recognized a gain of $14.3 million, net of the minority interest gain of $0.7 million. We discuss this transaction in more detail on page 34.

        These gains are included in "Gains on Sales of Assets" line in our Consolidated Statements of Income (Loss).

Dry Bulk Vessel

On July 10, 2008, a shipping joint venture, in which our merchant energy business has a 50% ownership interest, sold one of the six dry bulk vessels it owns. Our merchant energy business recognized a $29.0 million pre-tax gain on this sale. The gain is included in "Nonregulated revenues" line in our Consolidated Statements of Income (Loss).

Emissions Allowances

The Clean Air Interstate Rule (CAIR) required states in the eastern United States to reduce emissions of sulfur dioxide (SO2) and established a cap-and-trade program for annual nitrogen oxides (NOx) emission allowances. On July 11, 2008, the United States Court of Appeals for the D.C. Circuit (the "Court") issued an opinion vacating CAIR, subject to a 45 day delay during which parties may petition for rehearing. This delay was extended for an additional 30 days and on September 24, 2008 the Environmental Protection Agency (EPA) filed a petition for rehearing. On October 21, 2008, the Court asked for parties to submit supporting arguments on the EPA's petition for rehearing. Furthermore, the Court specifically requested briefing on whether any party is requesting that CAIR be revoked, and whether the Court should stay its mandate until the EPA issues a revised rule.

        Since the mandate has not yet been issued, the EPA continues to operate the trading system for SO2 and annual NOx emission allowances in accordance with CAIR. Trading of SO2 allowances will continue even if the Court issues a mandate. However, due to the ongoing uncertainty caused by the Court's July 11, 2008 decision, market prices for SO2 and annual NOx allowances are lower than they were prior to the Court's decision.

        We account for our emission allowance inventory at the lower of cost or market, which includes consideration of our expected requirements related to the future generation of electricity. The weighted-average cost of our current-year SO2 allowance inventory in excess of amounts needed to satisfy these requirements was greater than market value at June 30, 2008 and market prices decreased further for both SO2 and annual NOx emission allowances through September 30, 2008. After giving consideration to the Court's decision and the subsequent decline in the market price of these allowances, we recorded a write-down of our SO2 allowance inventory totaling $22.1 million

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pre-tax to reflect the June 30, 2008 market price. At September 30, 2008, we recorded an additional write-down of our SO2 emission allowance inventory and recorded a write-down of our annual NOx emission allowance inventory of $58.9 million to reflect market prices at September 30, 2008. The write-down was recorded in the "Nonregulated revenues" line in our Consolidated Statements of Income (Loss). This write-down was partially offset by mark-to-market gains in the quarter ended September 30, 2008 of $22.2 million pre-tax on derivative contracts for the forward sale of emission allowances. This gain reflects the impact of lower market prices on the value of those derivative contracts.

        The ultimate amount of any additional losses will be determined based on future market prices, which could vary materially from current market price levels, and could be affected by the ultimate resolution of the proceedings before the Court. At this time, we cannot predict the outcome of the EPA petition for rehearing or any further judicial, regulatory or legislative developments that might result in some or all of the provisions of CAIR being preserved. If any of these developments were to occur prior to December 31, 2008, the market prices of SO2 and annual NOx allowances may recover and the write-down of our inventory of allowances and contracts for the forward sale of annual NOx allowances may be reduced or avoided. As a result, these developments could have a material impact on our financial results.

Information by Operating Segment

Our reportable operating segments are—Merchant Energy, Regulated Electric, and Regulated Gas:

        Our remaining nonregulated businesses:

        In connection with efforts to improve our liquidity, we have announced strategic initiatives including the sale of our upstream gas properties, our international business, which includes our coal sourcing, freight, uranium, power, natural gas and emissions marketing activities outside the United States, and our gas trading activities. We discuss these strategies and their effect on liquidity on page 21.

        Our Merchant Energy, Regulated Electric, and Regulated Gas 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 on the next page.

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  Reportable Segments    
   
   
 
 
  Merchant
Energy
Business

  Regulated
Electric
Business

  Regulated
Gas
Business

  Other
Nonregulated
Businesses

  Eliminations
  Consolidated
 

 

 
 
  (In millions)
 

For the three months ended September 30,

                                     

2008

                                     

Unaffiliated revenues

  $ 4,300.8   $ 822.3   $ 150.3   $ 50.2   $   $ 5,323.6  

Intersegment revenues

    191.8     0.1     5.2         (197.1 )    
   

Total revenues

    4,492.6     822.4     155.5     50.2     (197.1 )   5,323.6  

Net (loss) income

    (246.0 )   31.7     (12.2 )   0.8         (225.7 )

2007

                                     

Unaffiliated revenues

  $ 4,910.4   $ 778.2   $ 112.8   $ 55.0   $   $ 5,856.4  

Intersegment revenues

    365.5         5.9         (371.4 )    
   

Total revenues

    5,275.9     778.2     118.7     55.0     (371.4 )   5,856.4  

Income from discontinued operations

    0.7                     0.7  

Net income (loss)

    227.2     34.3     (9.8 )   (0.3 )       251.4  

For the nine months ended September 30,

                                     

2008

                                     

Unaffiliated revenues

  $ 12,011.9   $ 1,980.3   $ 724.4   $ 175.3   $   $ 14,891.9  

Intersegment revenues

    707.8     0.2     15.6     0.2     (723.8 )    
   

Total revenues

    12,719.7     1,980.5     740.0     175.5     (723.8 )   14,891.9  

Net income (loss)

    105.9     (38.8 )   24.1     0.3         91.5  

2007

                                     

Unaffiliated revenues

  $ 13,157.6   $ 1,837.3   $ 674.4   $ 174.5   $   $ 15,843.8  

Intersegment revenues

    956.1         14.4         (970.5 )    
   

Total revenues

    14,113.7     1,837.3     688.8     174.5     (970.5 )   15,843.8  

Loss from discontinued operations

    (0.9 )                   (0.9 )

Net income

    449.4     85.9     18.2     9.9         563.4  

Certain prior-period amounts have been reclassified to conform with the current period's presentation. Revenues for the nine months ended September 30, 2008 reflect the reclassification of $321 million relating to the three months ended June 30, 2008 to conform with the current period presentation. We discuss our reclassifications in more detail on page 11 of the Notes to Consolidated Financial Statements.

Total assets increased approximately $1.6 billion during 2008. Most of the increase relates to our merchant energy segment assets and is primarily due to an $820 million increase in derivative assets and an $843 million increase in property, plant and equipment. We discuss the increase in derivative assets in more detail on page 32 of the Notes to the Consolidated Financial Statements.

Our merchant energy operating results for the quarter ended September 30, 2008 include the following after-tax charges: impairments and other costs of $298.8 million, net emission allowance write-down of $22.8 million, and an impairment charge of our nuclear decommissioning trust assets of $15.3 million.

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Pension and Postretirement Benefits

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

 
  Quarter Ended
September 30,

  Nine Months
Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Components of net periodic pension benefit cost

                         

Service cost

  $ 14.6   $ 13.3   $ 42.4   $ 38.0  

Interest cost

    26.6     25.6     76.8     72.9  

Expected return on plan assets

    (29.6 )   (27.8 )   (85.5 )   (79.1 )

Recognized net actuarial loss

    6.6     8.7     19.0     25.1  

Amortization of prior service cost

    2.8     1.4     8.3     4.0  

Amount capitalized as construction cost

    (2.3 )   (2.9 )   (7.1 )   (8.8 )
   

Net periodic pension benefit cost1

  $ 18.7   $ 18.3   $ 53.9   $ 52.1  
   

1 BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $4.5 million for the quarter ended September 30, 2008 and $5.8 million for the quarter ended September 30, 2007. BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $13.2 million for the nine months ended September 30, 2008 and $16.1 million for the nine months ended September 30, 2007.

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

 
  Quarter Ended
September 30,

  Nine Months
Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)

 

Components of net periodic postretirement benefit cost

                         

Service cost

  $ 1.3   $ 1.6   $ 4.9   $ 5.1  

Interest cost

    5.4     5.7     19.3     19.0  

Amortization of transition obligation

    0.5     0.4     1.7     1.6  

Recognized net actuarial loss

    0.5     1.0     1.6     3.2  

Amortization of prior service cost

    (0.8 )   (0.8 )   (2.8 )   (2.7 )

Amount capitalized as construction cost

    (1.5 )   (1.7 )   (5.5 )   (6.0 )
   

Net periodic postretirement benefit cost1

  $ 5.4   $ 6.2   $ 19.2   $ 20.2  
   

1 BGE's portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was $3.3 million for the quarter ended September 30, 2008 and $3.7 million for the quarter ended September 30, 2007. BGE's portion of our net periodic postretirement benefit costs, excluding amounts capitalized, was $11.0 million for the nine months ended September 30, 2008 and $11.9 million for the nine months ended September 30, 2007.

        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 $10 million in pension benefit payments for our non-qualified pension plans and approximately $29 million for retiree health and life insurance benefit payments during 2008. We contributed $76 million to our qualified pension plans in March 2008 and there is no requirement to contribute additional amounts in 2008.

Financing Activities

Credit Facilities

Constellation Energy had bank lines of credit under facilities totaling $5.7 billion at September 30, 2008 for short-term financial needs. These facilities can issue letters of credit, commercial paper, and/or cash borrowings up to approximately $5.7 billion. At September 30, 2008, we had $4.0 billion in letters of credit issued and borrowed $750.0 million against one of the credit facilities. At the end of October 2008 we estimate that we had $4.0 billion in letters of credit issued under these facilities and $750.0 million borrowed. In addition, at September 30, 2008, we had $310.5 million in commercial paper outstanding and at the end of October 2008 we had approximately $17 million in commercial paper outstanding under these facilities.

        At September 30, 2008, BGE had a $400.0 million five-year revolving credit facility expiring in 2011. BGE can borrow directly from the banks, use the facility to allow commercial paper to be issued or issue letters of credit. As of September 30, 2008, BGE had $1.1 million in letters of credit issued under this facility. As of October 31, 2008, BGE had $1.1 million in letters of credit issued and borrowed $270.0 million against the facility. In addition, at September 30, 2008 BGE had $189.0 million in commercial paper outstanding and at the end of October 2008 BGE had approximately $18 million in commercial paper outstanding.

        Total estimated net available liquidity as of October 31, 2008 was as follows:

 
  Constellation Energy
  BGE
  Total Consolidated
 

 

 
 
  (In millions)

 

Credit facilities

  $ 5,730   $ 400   $ 6,130  

Less: Letters of credit issued

    (3,977 )   (1 )   (3,978 )

Less: Cash drawn on credit facilities

    (750 )   (270 )   (1,020 )
   

Undrawn facilities

    1,003     129     1,132  

Less: Commercial paper outstanding

    (17 )   (18 )   (35 )
   

Net available facilities

    986     111     1,097  

Add: Cash

    719     59     778  
   

Net available liquidity

  $ 1,705   $ 170   $ 1,875  
   

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        Constellation Energy has credit facilities totaling $1.38 billion that will expire before December 31, 2008. We anticipate closing in November 2008 on a new credit facility of approximately $1.2 billion. In early November 2008, we also executed agreements with MidAmerican that provide us the option to sell one or both of the following assets to MidAmerican for aggregate proceeds of $350 million:

        The agreements are expected to become effective by November 14, 2008, provided that MidAmerican has approved certain disclosure schedules related to each agreement, and expire upon the earlier of the sale of the assets, the closing of the merger, or November 6, 2009.

        Upon exercise of an option, Constellation Energy's subsidiary will enter into a purchase agreement for the sale of the asset to MidAmerican and Constellation Energy will guarantee its subsidiary's obligations under the purchase agreement. The closing of the sale, including payment of the purchase price to Constellation Energy, will be subject to customary closing conditions, including receipt of required regulatory approvals.

        In addition to these efforts, we are actively seeking to increase available liquidity and to reduce our business risk. Specifically, we are reducing capital spending and ongoing expenses, scaling down the expected variability in long-term earnings and short-term collateral usage, and limiting our exposure to business activities that require contingent capital support. We have announced strategic initiatives including efforts to sell our upstream gas properties, our international business, which includes our coal sourcing, freight, uranium, power, natural gas and emissions marketing activities outside North America, and our gas trading activities.

        Collectively, we believe these efforts will provide sufficient liquidity to manage our business and successfully close the pending merger with MidAmerican. However, if market factors prevent us from successfully executing our plan or we are otherwise unable to successfully execute our plan, our liquidity would be adversely affected, which would have a material adverse effect on our business, results of operations, and financial condition.

Debt

In June 2008, Constellation Energy closed on the following financing transactions:

        In June 2008, BGE issued $400.0 million of 6.125% Notes due July 1, 2013. Interest is payable semi-annually on January 1 and July 1, beginning January 1, 2009.

        All net proceeds from the issuances above were used for general corporate purposes.

Mandatorily Redeemable Convertible Preferred Stock

On September 19, 2008, Constellation Energy entered into an Agreement and Plan of Merger with MidAmerican. We discuss the merger agreement in more detail beginning on page 11. In connection with the merger agreement, Constellation issued 10,000 shares of 8% Series A Convertible Preferred Stock of Constellation Energy (Preferred Stock) to MidAmerican for $1 billion. The Preferred Stock is mandatorily redeemable on

21


September 22, 2010 for an amount in cash equal to 100% of the stated value, subject to adjustments, plus all accrued but unpaid dividends.

        Because of the mandatory redemption provision, the Preferred Stock will be accounted for as debt and included in the "Long-term debt, net of current portion" line on our Consolidated Balance Sheets. Dividends will be included in the "Interest expense" line on our Consolidated Statements of Income (Loss).

        If the merger agreement is terminated for any reason other than a breach of the agreement by MidAmerican or the merger is not completed by June 19, 2009 (which may be extended to September 19, 2009), the Preferred Stock will automatically convert into $1 billion aggregate principal amount of 14% Senior Notes of Constellation Energy and either:

        We determined that the conversion provisions requiring a combination of a cash payment and issuance of up to 35.5 million shares of common stock upon a cancellation of the merger agreement constitute an embedded derivative that must be bifurcated from the Preferred Stock and recorded at fair value with changes in fair value recorded in earnings. Accordingly, we recorded a current derivative liability of approximately $46.2 million as the fair value of this conversion feature as of September 30, 2008 and we recorded a corresponding discount on the Preferred Stock. We will amortize the discount to interest expense as an additional dividend cost on the Preferred Stock over its term using the effective interest method.

        Determining the fair value of this derivative required the exercise of judgment because it is an embedded provision in a nonderivative host contract, is not traded on any market, and its value is dependent upon certain inputs that are not observable in any market. The primary factor affecting the fair value is the estimate of the probability that the merger may be cancelled.

        We estimated the merger cancellation discount using market information by comparing the merger purchase price per share, adjusted for the time value of money prior to closing of the transaction, to the average market price of our common stock for the five day period after the public announcement that another potential bidder was no longer seeking to acquire the company. We considered this period appropriate for estimating this input because we believe that it reflects a value for our common stock that primarily incorporates the risk of cancellation of the merger and the time value of money. This valuation methodology incorporates an assumption that a market-derived merger cancellation probability is 5% for the purpose of determining the fair value of the derivative.

        The fair value of this derivative could change substantially based upon discrete factors. The primary factors that could change its value, other than the passage of time and changes in interest rates, are:

        It is not possible to predict whether these events could occur, but if and when they do, the estimated fair value of the derivative could increase or decrease substantially, and such changes would be recorded in earnings when they occur. Upon receipt of all approvals necessary to issue 19.9% of the shares of our common stock to a single party, the derivative will be considered an equity instrument, and we will reclassify the fair value at that time to common shareholders' equity and discontinue recording changes in its fair value, in accordance with SFAS No. 133. At that time, the potential issuance of equity will be considered in determining diluted shares outstanding and diluted earnings per share.

        So long as any shares of the Preferred Stock are outstanding, Constellation Energy and its subsidiaries may not, without the consent of holders of at least a majority of then outstanding shares of Preferred Stock, undertake certain actions. Such actions include incurring indebtedness of Constellation Energy other than senior unsecured debt ranking equally with existing senior unsecured debt of Constellation Energy and of BGE other than indebtedness consistent with past practices and regulatory approvals.

        If issued, the Senior Notes will accrue interest at 14% per year, payable monthly in cash. These Senior Notes would mature and become due on December 31, 2009. The Senior Notes also contain restrictions on the conduct of Constellation Energy's business including limitations on:

22


        The proceeds from the Preferred Stock issuance will be used for general corporate purposes.

Maryland Settlement Agreement

In March 2008, Constellation Energy, BGE and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Public Service Commission of Maryland (Maryland PSC) and certain State of Maryland officials to resolve pending litigation and to settle other prior legal, regulatory and legislative issues. On April 24, 2008, the Governor of Maryland signed enabling legislation, which became effective on June 1, 2008. Pursuant to the terms of the settlement agreement:

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Income Taxes

Total income taxes differ from the amount that would be computed by applying the statutory Federal income tax rate of 35% to book income before income taxes as follows:

 
  Quarter Ended
September 30,
  Nine Months
Ended
September 30,
 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

(Loss) Income before income taxes (excluding BGE preference stock dividends)

  $ (334.0 ) $ 418.3   $ 172.8   $ 832.6  

Statutory federal income tax rate

    35 %   35 %   35 %   35 %
   

Income taxes computed at statutory federal rate

    (116.9 )   146.4     60.5     291.4  

(Decreases) increases in income taxes due to:

                         
 

Synthetic fuel tax credits flowed through to income

        (37.1 )       (119.7 )
 

Synthetic fuel tax credit phase-out

        20.1         44.0  
 

Synthetic fuel tax credit phase-out true-up from prior periods

        20.5     (4.6 )   12.6  
 

Merger-related transaction costs

    11.9         11.9      
 

State income taxes, net of federal tax benefit

    (10.0 )   19.0     13.4     36.6  
 

Other

    3.4     (4.6 )   (9.8 )   (6.5 )
   

Total income taxes

  $ (111.6 ) $ 164.3   $ 71.4   $ 258.4  
   

Effective tax rate

    33.4 %   39.3 %   41.3 %   31.0 %
   

        The changes in our effective tax rate for the quarter and nine months ended September 30, 2008 compared to the quarter and nine months ended September 30, 2007 are primarily due to lower 2008 taxable income increasing the relative impact of the unfavorable tax adjustments on the effective tax rate, the impact of nondeductible merger costs, and the absence of synthetic fuel tax credits, which expired at December 31, 2007.

        BGE's effective tax rate was 43.6% and (69.2%) for the quarter and nine months ended September 30, 2008, respectively, compared to 32.4% and 37.2% for the quarter and nine months ended September 30, 2007. This reflects the impact of estimated lower 2008 taxable income related to the Maryland settlement agreement, which increased the relative impact of unfavorable permanent tax adjustments on BGE's effective tax rate. These unfavorable permanent tax adjustments include the nondeductible portion of merger and strategic alternatives costs and the true-up of the 2007 tax provision to the 2007 tax return as filed. We discuss the merger and strategic alternatives costs in more detail on page 12 of the Notes to Consolidated Financial Statements.

        State income taxes for the quarter and nine months ended September 30, 2008 reflect the impact of an increase in the State of Maryland corporate tax rate from 7% to 8.25% effective January 1, 2008.

Unrecognized Tax Benefits

The following table summarizes the change in unrecognized tax benefits during 2008 and our total unrecognized tax benefits at September 30, 2008:

At September 30, 2008
   
 

 

 
 
  (In millions)
 

Total unrecognized tax benefits, January 1, 2008

  $ 114.5  

Increases in tax positions related to the current year

    13.6  

Reductions in tax positions related to prior years

    (11.8 )

Reductions in tax positions related to audit settlements

    (21.5 )
   

Total unrecognized tax benefits, September 30, 20081

  $ 94.8  
   

1 BGE's portion of our total unrecognized tax benefits at September 30, 2008 was $4.7 million.

        Increases in current year tax positions and reductions in prior year tax positions are primarily due to unrecognized tax benefits for repair and depreciation deductions measured at amounts consistent with prior IRS examination results and state income tax accruals.

        In April 2008, we received a closing agreement from the State of Hawaii regarding audit examinations for the tax years 2001-2003. Additionally, in June 2008, we received notice that the United States Congressional Joint Committee on Taxation had approved the results of the IRS examination of our federal consolidated income tax returns for the 2002-2004 tax years. We reduced our liability for unrecognized tax benefits by $21.5 million to reflect the results of these audits. Substantially all of this reduction has been reclassified to current tax liabilities on our Consolidated Balance Sheets to reflect payments due to the tax authorities in connection with the audit results. The impact of the audit settlements on income tax expense was immaterial.

        Total unrecognized tax benefits as of September 30, 2008 of $94.8 million include outstanding state refund claims of approximately $49 million for which no tax benefit was recorded on our Consolidated Balance Sheets because refunds were not received and the claims do not meet the "more-likely-than-not" threshold.

        If the total amount of unrecognized tax benefits of $94.8 million were ultimately realized, our income tax expense would decrease by approximately $65 million. However, the $65 million includes state tax refund claims of approximately $49 million discussed above that have been disallowed by tax authorities and we believe that there

24


is a remote likelihood of ultimately realizing any benefit from these refund claim amounts. These refund claims and other unrecognized state tax benefits of $2.7 million currently being reviewed by state tax authorities may be resolved by September 30, 2009. For this reason, we believe it is reasonably possible that reductions to our total unrecognized tax benefits in the range of $40 to $50 million may occur by September 30, 2009, but would not materially impact income tax expense.

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

 
  Quarter Ended September 30,
  Nine Months Ended September 30,
 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Interest and penalties recorded as tax expense

  $ 0.2   $ 2.2   $ 1.9   $ 4.6  
   

        Accrued interest and penalties recognized in our Consolidated Balance Sheets were $12.7 million at September 30, 2008 and $16.8 million at December 31, 2007.

Taxes Other Than Income Taxes

BGE collects from certain customers franchise and other taxes that are levied by state or local governments on the sale or distribution of gas and electricity. We include these types of taxes in "Taxes other than income taxes" in our Consolidated Statements of Income (Loss). Some of these taxes are imposed on the customer and others are imposed on BGE. We account for the taxes imposed on the customer on a net basis, which means we do not recognize revenue and an offsetting tax expense for the taxes collected from customers. We account for the taxes imposed on BGE on a gross basis, which means we recognize revenue for the taxes collected from customers. Accordingly, we record the taxes accounted for on a gross basis as revenues in the accompanying Consolidated Statements of Income (Loss) for BGE as follows:

 
  Quarter Ended September 30,
  Nine Months Ended September 30,
 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Taxes other than income taxes included in revenues—BGE

  $ 19.1   $ 19.4   $ 54.3   $ 57.9  
   

Commitments, Guarantees, and Contingencies

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

        Our merchant energy business enters into various long-term 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 2008 and 2020. In addition, our merchant energy business enters into long-term 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 2008 and 2024.

        Our merchant energy business also has committed to long-term service agreements and other purchase commitments for our plants.

        Our regulated electric business enters into various long-term contracts for the procurement of electricity. These contracts expire during 2009 and 2010, representing 100% of our estimated requirements until May 2009, approximately 75% of our estimated requirements from June 2009 to September 2009, approximately 50% of our estimated requirements from October 2009 to May 2010, and approximately 25% of our estimated requirements from June 2010 to September 2010. The cost of power under these contracts is recoverable under the POLR agreement reached with the Maryland PSC.

        Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. Our regulated gas business has gas procurement, transportation and storage contracts that expire between 2008 and 2027. As discussed in Note 1 of our 2007 Annual Report on Form 10-K, our regulated gas business charges its customers for natural gas, and other associated costs, using gas adjustment clauses set by the Maryland PSC.

        Our other nonregulated businesses have committed to gas purchases, as well as to contribute additional capital for construction programs and joint ventures in which they have an interest.

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

        At September 30, 2008, the total amount of commitments was $6,141.8 million. These commitments are primarily related to our merchant energy business.

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

25


of our power plants. Our load-serving power sales contracts extend for terms through 2019 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 2014 and provide for the sale of all or a portion of the actual output of certain of our power plants. Most long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

Guarantees

Our guarantees generally 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 September 30, 2008
  Stated Limit
 

 

 
 
  (In millions)
 

Constellation Energy guarantees

  $ 17,539.1  

Merchant energy business guarantees

    80.6  

BGE guarantees

    250.0  

Other non-regulated guarantees

    1.2  
   

Total guarantees

  $ 17,870.9  
   

        At September 30, 2008, Constellation Energy had a total of $17,870.9 million in guarantees outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described below.

Contingencies

Environmental Matters

Solid and Hazardous Waste

The Environmental Protection Agency (EPA) and several state agencies have notified us that we are considered a potentially responsible party with respect to the clean-up of certain environmentally contaminated sites. We cannot estimate the final clean-up costs for all of these sites, but the current estimated costs for, and current status of, each site is described in more detail below.

68th Street Dump

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 liable 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 fully indemnified by a wholly-owned subsidiary of Constellation Energy for costs related to this settlement, as well as any clean-up costs. The clean-up costs will not be known until the investigation is

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closer to completion. However, those costs could have a material effect on our financial results.

Spring Gardens

In December 1996, BGE signed a consent order with the Maryland Department of the Environment that requires it to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. The Spring Gardens site was once used to manufacture gas from coal and oil. Based on remedial action plans and cost modeling performed in late 2006, BGE estimates its probable clean-up costs will total $43 million. BGE has recorded these costs as a liability in its Consolidated Balance Sheets and has deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. Based on the results of studies at this site, it is reasonably possible that additional costs could exceed the amount BGE has recognized by approximately $3 million. Through September 30, 2008, BGE has spent approximately $41 million for remediation at this site.

        BGE also has investigated other small sites where gas was manufactured in the past. We do not expect the clean-up costs of the remaining smaller sites to have a material effect on our financial results.

Air Quality

In late July 2005, we received two Notices of Violation (NOVs) from the Placer County Air Pollution Control District, Placer County California (District) alleging that the Rio Bravo Rocklin facility located in Lincoln, California had violated certain District air emission regulations between January 2003 and March 2005. We have a combined 50% ownership interest in the partnership which owns the Rio Bravo Rocklin facility. In July 2008, the partnership settled the allegations by agreeing to pay approximately $242,000, of which our share will be approximately $121,000, and to implement supplemental environmental projects at the facility over the next 18 months.

        In May 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment to resolve alleged violations of air quality opacity standards at three fossil fuel plants in Maryland. The consent decree requires the subsidiary to pay a $100,000 penalty, provide $100,000 to a supplemental environmental project, and install technology to control emissions from those plants.

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 $7.9 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 $2.3 million of these costs as of September 30, 2008, resulting in a remaining liability at September 30, 2008 of $5.6 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 November 2007, a class action complaint was filed in Baltimore City Circuit Court alleging that the subsidiary's ash placement operations at the third party site damaged surrounding properties. The complaint seeks injunctive and remedial relief relating to the alleged contamination, unspecified compensatory damages for any personal injuries and property damages associated with the alleged contamination, and unspecified punitive damages. In September 2008, we entered into a non-binding agreement with representatives for the class action plaintiffs and, as a result, recorded a liability for the anticipated settlement. On October 31, 2008, we entered into a definitive settlement agreement which was filed with the Court and is subject to Court approval. The Court is expected to schedule a hearing for final approval of the settlement sometime in December 2008.

Litigation

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

Pending Merger with MidAmerican

Beginning September 18, 2008, six shareholders of Constellation Energy filed lawsuits in the Circuit Court for Baltimore City, Maryland challenging our pending merger with MidAmerican. Three similar suits have been filed by other shareholders of Constellation Energy in the United States District Court for the District of Maryland.

        The lawsuits claim that the merger consideration is inadequate and does not maximize value for shareholders, that the sales process leading up to the merger was unreasonably short and procedurally flawed, and that unreasonable deal protection devices were agreed to that ward off competing bids and coerce shareholders into accepting the merger. The federal lawsuits also assert that the conversion of the Preferred Stock issued to MidAmerican into debt is not permitted under Maryland

27


law. The lawsuits seek declaratory judgments establishing the unenforceability of the merger based on the alleged breaches of duty, injunctive relief to enjoin the merger, rescission of the merger or rescissory damages, the imposition of a constructive trust in favor of shareholders of any benefits received by the individual members of the board of directors of Constellation Energy, and reasonable costs and expenses, including attorney's fees.

        Although Constellation Energy is unable at this time to determine the ultimate outcome of these lawsuits, injunctive relief or an adverse determination in these lawsuits could affect our ability to complete the pending merger.

Securities Class Action

On September 22, 2008, a federal securities class action lawsuit was filed in the United States District Court for the Southern District of New York on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures, of Constellation Energy between January 30, 2008 and September 16, 2008, and who acquired Series A Junior Subordinated Debentures in an offering completed in June 2008. On October 27, 2008, another federal securities class action lawsuit was filed in the United States District Court for the District of Maryland, on behalf of a proposed class of persons who acquired common stock of Constellation Energy between January 30, 2008 and September 16, 2008.

        The New York securities class action alleges 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 Series A Junior Subordinated Debentures. The New York and Maryland securities class actions also allege that Constellation Energy issued false or misleading statements or was aware of material undisclosed information which contradicted public statements included 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 case as a class action, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.

        A lead plaintiff has not yet been appointed in either the New York or Maryland securities class action pursuant to the provisions of the Private Securities Litigation Reform Act and Constellation Energy and other defendants have accordingly not been required to respond to the complaint or take other action to defend the litigation. We are unable at this time to determine the ultimate outcome of the securities class action or its possible effect on our, or BGE's financial results.

ERISA Actions

In October and November 2008, four class action lawsuits were filed in the United States District Court for the District of Maryland and one class action was filed in the United States District Court for the Southern District of New York against Constellation Energy; Mayo A. Shattuck III, Constellation Energy's Chairman of the Board, President and Chief Executive Officer; and others in their roles as fiduciaries of the Constellation Energy Employee Savings Plan. The lawsuits allege that the defendants, in violation of various sections of ERISA, breached their fiduciary duties to prudently and loyally manage Constellation Energy Savings Plan's assets by designating Constellation Energy common stock as an investment, by failing to properly provide accurate information about the investment, by failing to properly monitor the investment and by failing to properly monitor other fiduciaries. The lawsuits seek to compel the defendants to reimburse the plaintiffs and the Constellation Energy Savings Plan for all losses resulting from the defendants' breaches of fiduciary duty, to impose a constructive trust on any unjust enrichment, to award actual damages with pre- and post-judgment interest, to award appropriate equitable relief including injunction and restitution and to award costs and expenses, including attorneys' fees. We are unable at this time to determine the ultimate outcome of these ERISA 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.

        In rulings applicable to all but three of the cases, involving claims related to approximately 47 children, the Circuit Court for Baltimore City dismissed with prejudice all claims against BGE and Constellation Energy. Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE and Constellation Energy once the cases are finally concluded as to all defendants. We believe that we have meritorious defenses and intend to defend the remaining actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or BGE's, financial results.

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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 515 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 against us have been dismissed or resolved without any payment and a small minority have been resolved for amounts that were not material to our financial results. The remaining claims are currently pending in state courts in Maryland and Pennsylvania.

        BGE and Constellation Energy do not know the specific facts necessary to estimate their potential liability for these claims. The specific facts we do not know include:

        Until the relevant facts are determined, we are unable to estimate what our, or BGE's, liability might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions, the potential effect on our, or BGE's, financial results could be material.

Insurance

We discuss our nuclear and non-nuclear insurance programs in Note 12 of our 2007 Annual Report on Form 10-K.

SFAS No. 133 Hedging Activities

We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities. We discuss our market risk in more detail in our 2007 Annual Report on Form 10-K.

Commodity Prices

Our merchant energy business uses a variety of derivative and non-derivative instruments to manage the commodity price risk of our wholesale and retail activities and our electric generation facilities, including power sales, fuel and energy purchases, gas purchased for resale, emission credits, weather risk, and the market risk of outages. In order to manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include:

        The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operational, and other factors.

        Our merchant energy business designated certain fixed-price forward contracts as cash-flow hedges of forecasted sales of energy and forecasted purchases of fuel and energy for the years 2008 through 2016 under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Our merchant energy business had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive loss" of $1,946.7 million at September 30, 2008 and net unrealized pre-tax losses of $1,498.7 million at December 31, 2007.

        We expect to reclassify $945.0 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 September 30, 2008. However, the actual amount reclassified into earnings could vary from the amounts recorded at September 30, 2008, due to future changes in market prices. Additionally, for cash-flow hedges settled by physical delivery of the underlying commodity, "Reclassification of net gains or losses on hedging instruments from OCI to net income" represents the fair value of those derivatives, which is realized through gross settlement at the contract price.

        During the nine months ended September 30, 2008, we de-designated contracts previously designated as cash-flow hedges for which the forecasted transactions originally hedged are probable of not occurring and as a result we recognized a pre-tax gain of $17.7 million. During the nine months ended September 30, 2007, we de-designated contracts previously designated as cash-flow hedges for which the forecasted transactions originally hedged are probable of not occurring and as a result we recognized a pre-tax loss of $21.6 million.

        Our merchant energy business also enters into natural gas storage contracts under which the gas in storage qualifies for fair value hedge accounting treatment under SFAS No. 133. We record changes in fair value of these hedges related to our wholesale supply operations as a

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component of "Nonregulated revenues" in our Consolidated Statements of Income (Loss).

        We recorded in earnings the following pre-tax (losses) gains related to hedge ineffectiveness:

 
  Quarter Ended
September 30,

  Nine Months
Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Cash-flow hedges

  $ (13.2 ) $ 32.5   $ (103.0 ) $ 2.2  

Fair value hedges

    (6.2 )   (1.6 )   6.7     (0.5 )
   

Total

  $ (19.4 ) $ 30.9   $ (96.3 ) $ 1.7  
   

        The ineffectiveness amounts in the table above exclude:

Interest Rates

We use interest rate swaps to manage our interest rate exposures associated with new debt issuances, to manage our exposure to fluctuations in interest rates on variable rate debt, and to optimize the mix of fixed and floating-rate debt. The swaps used to manage our exposure prior to the issuance of new debt are designated as cash-flow hedges under SFAS No. 133, with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in "Accumulated other comprehensive loss" in anticipation of planned financing transactions. We reclassify gains and losses on the hedges from "Accumulated other comprehensive loss" into "Interest expense" in our Consolidated Statements of Income (Loss) during the periods in which the interest payments being hedged occur.

        The swaps used to optimize the mix of fixed and floating-rate debt are designated as fair value hedges under SFAS No. 133. We record any gains or losses on swaps that qualify for fair value hedge accounting treatment, as well as changes in the fair value of the debt being hedged, in "Interest expense," and we record any changes in fair value of the swaps and the debt in "Derivative assets and liabilities" and "Long-term debt," respectively, in our Consolidated Balance Sheets. In addition, we record the difference between interest on hedged fixed-rate debt and floating-rate swaps in "Interest expense" in the periods that the swaps settle.

        "Accumulated other comprehensive loss" includes net unrealized pre-tax gains on interest rate cash-flow hedges terminated upon debt issuance totaling $12.0 million at September 30, 2008 and $11.9 million at December 31, 2007. 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.

        In order to optimize the mix of fixed and floating-rate debt, we entered into interest rate swaps qualifying as fair value hedges relating to $450.0 million of our fixed-rate debt maturing in 2012 and 2015, and converted this notional amount of debt to floating-rate. The change in fair value of these hedges resulted in an unrealized gain of $23.6 million at September 30, 2008 and was recorded as an increase in our "Derivative assets" and "Long-term debt." The change in fair value of these hedges resulted in an unrealized gain of $11.8 million at December 31, 2007 and was recorded as an increase in our "Derivative assets" and "Long-term debt." We had no hedge ineffectiveness on these interest rate swaps.

Accounting Standards Issued

SFAS No. 161

In March 2008, the FASB issued SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities. SFAS No. 161 is effective beginning January 1, 2009 and requires entities to provide expanded disclosure about derivative instruments and hedging activities regarding (1) the ways in which an entity uses derivatives, (2) the accounting for derivatives and hedging activities, and (3) the impact that derivatives have (or could have) on an entity's financial position, financial performance, and cash flows. SFAS No. 161 requires expanded disclosures, but does not change the accounting for derivatives. We are currently evaluating the impact of SFAS No. 161, but, because it only provides for additional disclosure, we do not expect the adoption of this standard to have a material impact on our, or BGE's, financial results.

Accounting Standards Adopted

FSP FIN 39-1

In April 2007, the FASB issued Staff Position (FSP) FIN 39-1, Amendment of FASB Interpretation No. 39. As amended, FIN 39, Offsetting of Amounts Related to Certain Contracts, requires an entity to report all derivatives recorded at fair value net of any associated fair value cash collateral with the same counterparty under a master netting arrangement. Therefore, effective January 1, 2008, we reported all derivatives recorded at fair value net of the associated fair value cash collateral. We applied the provisions of FSP FIN 39-1 by adjusting all financial statement periods presented, which reduced total assets at December 31, 2007 by $203.4 million. We present the fair

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value cash collateral that has been offset against our net derivative positions as part of our adoption of SFAS No. 157, Fair Value Measurements, below.

FSP SFAS No. 157-3

In October 2008, the FASB issued FSP SFAS No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active. FSP SFAS No. 157-3 does not change the guidance contained in SFAS No. 157, Fair Value Measurements; rather, it clarifies the application of SFAS No. 157 in a market that is not active. This FSP is effective for the periods ended September 30, 2008, and the adoption of this FSP did not have an effect on our financial results.

SFAS No. 157

Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value, and requires certain disclosures about fair value measurements. Fair value is the price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

        Consistent with the exit price concept, upon adoption we reduced our derivative liabilities to reflect our own credit risk. As a result, during the first quarter of 2008 we recorded a pre-tax reduction in "Accumulated other comprehensive loss" totaling $10 million for the portion related to cash-flow hedges and a pre-tax gain in earnings totaling $3 million for the remainder of our derivative liabilities. All other impacts of adoption were immaterial.

        We present all derivatives recorded at fair value net with the associated fair value cash collateral. This presentation of the net position reflects our credit exposure for our on-balance sheet positions but excludes the impact of any off-balance sheet positions and collateral. Examples of off-balance sheet positions and collateral include in-the-money accrual contracts for which the right of offset exists in the event of default and letters of credit. We discuss our letters of credit in more detail beginning on page 20.

        Our assets and liabilities measured at fair value on a recurring basis consist of the following:

 
  As of September 30, 2008
 
 
  Assets
  Liabilities
 

 

 
 
  (In millions)
 

Cash equivalents

  $ 393.4   $  

Debt and equity securities

    1,237.4      

Derivative instruments:

             
 

Classified as derivative assets and liabilities:

             
   

Current

    1,604.7     (1,115.8 )
   

Noncurrent

    1,006.0     (1,171.1 )
   
   

Total classified as derivative assets and liabilities

    2,610.7     (2,286.9 )
 

Classified as accounts receivable *

    (971.4 )    
   
 

Total derivative instruments

    1,639.3     (2,286.9 )
   

Total recurring fair value measurements

  $ 3,270.1   $ (2,286.9 )
   

* Represents the unrealized fair value of exchange traded derivatives excluding cash margin posted.

        Cash equivalents represent money market mutual funds which are included in "Cash and cash equivalents" in the Consolidated Balance Sheets. Debt and equity securities represent available-for-sale investments which are included in "Nuclear decommissioning trust funds" and "Other assets" in the Consolidated Balance Sheets. Derivative instruments represent unrealized amounts related to all derivative positions, including futures, forwards, swaps, and options. We classify exchange-listed contracts as part of "Accounts Receivable" in our Consolidated Balance Sheets. We classify the remainder of our derivative contracts as "Derivative assets" or "Derivative liabilities" in our Consolidated Balance Sheets.

        The table on the next page disaggregates our net derivative assets and liabilities on a gross contract-by-contract basis as required by SFAS No. 157. A primary focus of SFAS No. 157 is the fair value hierarchy that provides information about how fair value measurements are determined. SFAS No. 157 requires each individual asset or liability that is remeasured at fair value on a recurring basis to be presented in this table and classified, in its entirety, within the appropriate level in the fair value hierarchy. Therefore, 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. Because contracts with the same counterparty could fall into multiple levels within the fair value hierarchy, it is necessary to make this gross presentation in order to classify entire contracts into the appropriate fair value hierarchy level as required by SFAS No. 157. However, these gross balances are not indicative of either our actual credit exposure or net economic exposure since they do not reflect legally enforceable master netting

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agreements or cash or other forms of collateral, nor do they reflect the extent to which offsetting derivative and nonderivative positions or the capacity of physical assets reduce our economic exposure to risk. 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.

        The table below sets forth by level within the fair value hierarchy the company's assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2008. The gross derivative assets and liabilities presented in this table decreased significantly during the quarter ended September 30, 2008. This decrease is primarily due to a decreasing commodity price environment during the third quarter of 2008.

At September 30, 2008
  Level 1
  Level 2
  Level 3
  Netting and
Cash Collateral*

  Total Net Fair
Value

 

 

 
 
  (In millions)
 

Cash equivalents

  $ 393.4   $   $   $   $ 393.4  

Debt and equity securities

   
375.9
   
861.5
   
   
   
1,237.4
 

Derivative assets

   
1,175.1
   
31,373.9
   
3,714.8
   
(34,624.5

)
 
1,639.3
 

Derivative liabilities

    (1,276.3 )   (32,660.1 )   (3,000.2 )   34,649.7     (2,286.9 )
   
 

Net derivative position

    (101.2 )   (1,286.2 )   714.6     25.2     (647.6 )
   

Total

  $ 668.1   $ (424.7 ) $ 714.6   $ 25.2   $ 983.2  
   

* 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 September 30, 2008, we included $126.3 million of cash collateral held and $101.1 million of cash collateral posted (excluding margin posted on exchange traded derivatives) in netting amounts in the above table. See discussion of FSP FIN 39-1 beginning on page 30 for more details on our net presentation.

        The fair value hierarchy prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:

        We determine the fair value of our assets and liabilities using unadjusted quoted prices in active markets (Level 1) or pricing inputs that are observable (Level 2) whenever that information is available. We use unobservable inputs (Level 3) to estimate fair value only when relevant observable inputs are not available.

        We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. We determine fair value using Level 1 inputs by multiplying the market price by the quantity of the asset or liability. We primarily determine fair value measurements classified as Level 2 or Level 3 using the income valuation approach, which involves discounting estimated cash flows.

        Cash equivalents are comprised of exchange traded money market funds. These instruments are valued based upon unadjusted quoted prices in active markets and are classified within Level 1.

        Debt and equity securities include trust assets securing certain executive benefits, other marketable securities, and our nuclear decommissioning trust funds. Trust assets securing certain executive benefits consist of mutual funds, which are actively traded and are valued based upon unadjusted quoted prices, and are classified within Level 1. Our other marketable securities consist of publicly traded individual securities, which are valued based on unadjusted quoted prices in active markets, and are classified within Level 1. Nuclear decommissioning trust funds consist of a number of different types of securities, including the following:

        Derivative instruments include exchange-traded and bilateral contracts. Exchange-traded contracts include futures and certain options. Bilateral derivative instruments

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include swaps, forwards, certain options and complex structured transactions. We utilize models to measure the fair value of bilateral derivative contracts. Generally, we use similar models to value similar instruments. Valuation models utilize various inputs, which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs, which are inputs derived principally from or corroborated by observable market data by correlation or other means. However, the primary input to our valuation models is the forward commodity price. We have classified derivative contracts within the fair value hierarchy as follows:

        In order to determine fair value, we utilize various factors, including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. These factors include:

        As previously mentioned, we incorporate the effect of exposure to a particular counterparty's credit (or counterparties exposure to us) in calculating the fair value of our derivative assets and liabilities. We adjust the value of our derivative assets to reflect the credit-worthiness of each counterparty based upon either published credit ratings or equivalent internal credit ratings and associated default probability percentages. We compute this adjustment by applying a default probability percentage to our outstanding credit exposure, net of collateral for each counterparty. The level of this adjustment increases/decreases as our credit exposure to counterparties increases/decreases, the maturity terms of our transactions increase/decrease, or the credit ratings of our counterparties deteriorate/improve. We also assess whether the counterparties published credit rating is reflective of current market conditions based on review of available observable data including bond prices and yields and credit default swaps.

        We regularly evaluate and validate the inputs we use to estimate fair value by a number of methods, consisting of various market price verification procedures, including the use of pricing services and multiple broker quotes to support the market price of the various commodities in which we transact, as well as review and verification of models and changes to those models. These activities are undertaken by individuals that are independent of those responsible for estimating fair value.

        The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy. Because of the long-term nature of certain assets and liabilities measured at fair value as well as differences in the availability of market prices and market liquidity over their terms, inputs for some assets and liabilities may fall into any one of the three levels in the fair value hierarchy or some combination thereof. While SFAS No. 157 requires us to classify these assets and liabilities in the lowest level in the hierarchy for which inputs are significant to the fair value measurement, a portion of that measurement may be determined using inputs from a higher level in the hierarchy.

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        The following table sets forth a reconciliation of changes in Level 3 fair value measurements:

 
  Quarter ended
September 30, 2008

  Nine months ended
September 30, 2008

 

 

 
 
  (In millions)
 

Balance at beginning of period

  $ 211.4   $ (147.1 )

Realized and unrealized gains (losses):

             
 

Recorded in income

    37.4     203.3  
 

Recorded in other comprehensive income

    (24.3 )   226.2  

Purchases, sales, issuances, and settlements

    (39.5 )   (3.2 )

Transfers into and out of level 3

    529.6     435.4  
   

Balance as of September 30, 2008

  $ 714.6   $ 714.6  
   

Change in unrealized gains relating to derivatives still held as of September 30, 2008

  $ 338.8   $ 478.5  
   

        Realized and unrealized gains (losses) are included primarily in "Nonregulated revenues" for our derivative contracts that are marked-to-market in our Consolidated Statements of Income (Loss) and are included in "Accumulated other comprehensive loss" for our derivative contracts designated as cash-flow hedges in our Consolidated Balance Sheets. We discuss the income statement classification for realized gains and losses related to cash-flow hedges for our various hedging relationships in Note 1 of our 2007 Annual Report on Form 10-K.

        Realized and unrealized gains (losses) include the realization of derivative contracts through maturity. This includes the fair value, as of the beginning of each quarterly reporting period, of contracts that matured during each quarterly reporting period. Purchases, sales, issuances, and settlements represent cash paid or received for option premiums, and the acquisition or termination of derivative contracts prior to maturity, including the $46.2 million embedded derivative liability contained in the Preferred Stock issued to MidAmerican. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the inputs to the model became unobservable. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable based on the criteria discussed on the previous page for classification in either Level 1 or Level 2.

Related Party Transactions

Constellation Energy

On March 31, 2008, our merchant energy business sold its working interest in 83 oil and natural gas producing wells in Oklahoma to Constellation Energy Partners (CEP), an equity method investment of Constellation Energy, for total proceeds of approximately $53 million. Our merchant energy business recognized a $14.3 million gain, net of the minority interest gain of $0.7 million on the sale and exclusive of our 28.5% ownership interest in CEP. This gain is recorded in "Gains on Sales of Assets" in our Consolidated Statements of Income (Loss).

BGE—Income Statement

BGE is obligated to provide market-based standard offer service to all of its electric customers. 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 merchant energy business will supply a portion of BGE's market-based standard offer service obligation to residential electric customers through May 31, 2010.

        The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was as follows:

 
  Quarter Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Purchased energy

  $ 175.6   $ 355.1   $ 632.9   $ 912.1  
   

        In addition, Constellation Energy charges BGE for the costs of certain corporate functions. Certain costs 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.

        The following table presents the costs Constellation Energy charged to BGE in each period.

 
  Quarter Ended September 30,
  Nine Months Ended September 30,
 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Charges to BGE

  $ 44.5   $ 41.8   $ 114.6   $ 111.6  
   

34


BGE—Balance Sheet

BGE participates in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating subsidiaries may invest in or borrow from the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments or issues commercial paper to manage consolidated cash requirements. Under this arrangement, BGE had invested $63.1 million at September 30, 2008 and $78.4 million at December 31, 2007.

        BGE's Consolidated Balance Sheets include intercompany amounts related to corporate functions performed at the Constellation Energy holding company, 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, and the participation of BGE's employees in the Constellation Energy defined benefit plans.

        We believe our allocation methods are reasonable and approximate the costs that would be charged to unaffiliated entities.

35



Item 2. Management's Discussion

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 including a merchant energy business and Baltimore Gas and Electric Company (BGE). We describe our operating segments in the Notes to Consolidated Financial Statements beginning on page 18.

        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 in more detail in Item 1—Business section of our 2007 Annual Report on Form 10-K and we discuss the risks affecting our business in Item 1A. Risk Factors section beginning on page 68.

        Our 2007 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 require management's most difficult, subjective, or complex judgment. Our critical accounting policies include derivative accounting, evaluation of assets for impairment and other than temporary decline in value, and asset retirement obligations.

        Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements, as discussed in the Notes to Consolidated Financial Statements beginning on page 31. We discuss our accounting policy for determining fair value in more detail in the Notes to Consolidated Financial Statements as well as in our Critical Accounting Policies section and Note 1 in our 2007 Annual Report on Form 10-K.

        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 (Loss) on page 3, which present the results of our operations for the quarters and nine months ended September 30, 2008 and 2007. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income (Loss).

        We have organized our discussion and analysis as follows:


Strategy

We discuss our business strategy in detail in the Strategy section of our 2007 Annual Report on Form 10-K. In that discussion, we indicate that we are constantly reevaluating our strategies. As a result of the unprecedented events of 2008 as discussed below, in addition to focusing on our basic business plan, we have made substantial changes in our strategy, including focusing on the following immediate goals:

36


        The execution of our strategy in the future will be affected by our ability to achieve these goals as well as by continued instability in financial and commodities markets. Execution of our goals could have a substantial effect on the nature and mix of our business activities. In turn, this could affect our financial position, results of operations, and cash flows in material amounts, and these amounts could vary substantially from historical results.


Business Environment

Various factors affect our financial results. We discuss these various factors in the Forward Looking Statements section on page 74 and in Item 1A. Risk Factors section beginning on page 68. We discuss our market risks in the Market Risk section beginning on page 64.

        In this section, we discuss in more detail events which have impacted our business during 2008.

Federal Regulation

In May 2008, five state public service commissions, including the Public Service Commission of Maryland (Maryland PSC), consumer advocates and others filed a complaint against PJM Interconnection (PJM), the regional transmission organization for the Mid-Atlantic region, at the Federal Energy Regulatory Commission (FERC) alleging that the PJM reliability pricing model (RPM) produced unreasonable prices during the period from June 1, 2008 through May 31, 2011. The complaint requests that FERC establish a refund effective date of June 1, 2008, reject the results of the 2007/08 through 2010/11 RPM capacity auction results, and significantly reduce prices for capacity beginning as of June 1, 2008 through 2011/12. We, along with other power suppliers and supplier trade groups, have filed protests to the complaint. In September 2008, FERC dismissed the complaint and in October 2008, the complainants requested a rehearing at FERC. We cannot predict the outcome of this proceeding or the amount of refunds that may be owed by or due to us, if any. However, the outcome, and any refunds that are ultimately assessed, could have a material impact on our financial results.

Environmental Matters

Air Quality

National Ambient Air Quality Standards (NAAQS)

In March 2008, the Environmental Protection Agency (EPA) adopted a stricter NAAQS for ozone. We are unable to determine the impact that complying with the stricter NAAQS for ozone will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standards.

        In July 2008, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that effectively repealed the Clean Air Interstate Rule (CAIR). We do not believe that the decision will result in a material change to our emissions reduction plan in Maryland as the emissions reduction requirements of Maryland's Healthy Air Act and Clean Power Rule are more stringent and apply sooner than those under CAIR. On September 24, 2008, the EPA petitioned the District of Columbia Circuit for rehearing. We cannot predict what additional judicial, legislative or regulatory actions will be taken in response to the court's decision or the EPA's petition for rehearing or whether such actions may affect our financial results. We discuss the impact that this ruling had on our third quarter of 2008 results in the Merchant Energy Business section on page 45. We discuss this ruling in more detail in the Notes to Consolidated Financial Statements beginning on page 17.

Capital Expenditures

As discussed in our 2007 Annual Report on Form 10-K, we expect to incur additional environmental capital expenditures to comply with air quality laws and regulations. Based on updated information from vendors, we expect our estimated environmental capital requirements for these air quality projects to be approximately $550 million in 2008, $305 million in 2009, $40 million in 2010 and $35 million from 2011-2012.

        Our estimates may change further as we implement our compliance plan. As discussed in our 2007 Annual Report on Form 10-K, our estimates of capital expenditures continue to be subject to significant uncertainties.

Accounting Standards Issued and Adopted

We discuss recently issued and adopted accounting standards in the Accounting Standards Issued and Accounting Standards Adopted sections of the Notes to Consolidated Financial Statements beginning on page 30.

Events of 2008

Pending Merger with MidAmerican

On September 19, 2008, Constellation Energy entered into an Agreement and Plan of Merger with MidAmerican. We discuss the details of this pending merger in the Notes to Consolidated Financial Statements beginning on page 11.

37



Current Market Developments

Volatility in the financial markets throughout 2008 intensified in the third quarter, leading to dramatic declines in equity prices and substantially reducing liquidity in the credit markets. Most equity indices declined significantly, the cost of credit default swaps and bond spreads increased substantially, and credit markets effectively ceased to be accessible for all but the most highly rated borrowers.

        Precipitated by these conditions, major financial institutions experienced significant financial difficulty and widespread fears developed about the viability of any business that required access to credit markets to support liquidity needs or that required substantial access to the capital markets to function. During the week of September 15, 2008, Constellation Energy faced rapidly growing doubts among investors and business partners about its ability to navigate through this market crisis. Concerns focused on our liquidity, and the trading price of our common stock fell to a 52-week low of $13.00 during the day on September 16, 2008. Despite having announced a number of actions to address our liquidity situation, we needed to raise immediate equity capital and take other steps to enhance our overall liquidity, and as a result on September 19, 2008, we entered into a definitive merger agreement with MidAmerican. We discuss our pending merger with MidAmerican in more detail in the Notes to Consolidated Financial Statements beginning on page 11.

        This market environment contributed to the following:


Commodity Prices

During the six months ended June 30, 2008 and nine months ended September 30, 2008, the energy markets were affected by large fluctuations in commodity prices as indicated in the following table:

Increases (decreases)
  Six months ended
June 30, 2008

  Nine months ended
September 30, 2008

 

 

 

Power

    33 %   (8 )%

Natural gas

    44 %   (5 )%

Coal

    153 %   58 %

Crude oil

    55 %   1 %

        During the third quarter of 2008 and continuing into the fourth quarter of 2008, prices for most commodities, including energy, fell sharply after peaking early in July. The commodity price environment contributed to the following impacts on our results:

38



Merger and Strategic Alternatives Costs

We incurred costs during the third quarter of 2008 related to our pending merger with MidAmerican and the pursuit of other strategic alternatives to that merger. We discuss these costs in more detail in the Notes to Consolidated Financial Statements on page 12.


Workforce Reduction Costs

During the third quarter of 2008, our merchant energy business approved a restructuring of its Customer Supply operations and recognized a $2.2 million pre-tax charge. We discuss our workforce reduction costs in more detail in the Notes to Consolidated Financial Statements on page 16.


Emission Allowances

During the third quarter of 2008, as a result of a July 11, 2008 decision by the United States Court of Appeals for the D. C. Circuit that vacated the Clean Air Interstate Rule and the subsequent decline in market price for our emission allowance inventory, we recorded a write-down of our emissions inventory and recognized partially offsetting gains on certain forward sales contracts. We discuss this net charge in the Notes to Consolidated Financial Statements beginning on page 17.

Acquisitions

Hillabee Energy Center

On February 14, 2008, we acquired a partially completed gas-fired power generating facility in Alabama. We discuss this acquisition in more detail in the Notes to Consolidated Financial Statements on page 16.

West Valley Power Plant

On June 1, 2008, we acquired a gas-fired peaking plant in Utah. We discuss this acquisition in more detail in the Notes to Consolidated Financial Statements on page 16.

Nufcor International Limited

On June 26, 2008, we acquired a uranium marketing services company in the United Kingdom. We discuss this acquisition in more detail in the Notes to Consolidated Financial Statements beginning on page 16.


Asset Sales

Working Interests in Gas Producing Property

On June 30, 2008, we sold a portion of our working interests in certain proved and unproved oil and gas properties. We discuss this asset sale in more detail in the Notes to Consolidated Financial Statements on page 17.

Dry Bulk Vessel

On July 10, 2008, a shipping joint venture in which our merchant energy business owns a 50% ownership interest sold one of six dry bulk vessels it owns for a gain to us of approximately $29 million. We discuss this sale in more detail in the Notes to Consolidated Financial Statements on page 17.


Financing Activities

In June 2008, we issued the following:

        Also, in June 2008, BGE issued $400.0 million of 6.125% Notes due July 1, 2013.

        In connection with the merger with MidAmerican, Constellation Energy issued 10,000 shares of 8% Series A Convertible Preferred Stock (Preferred Stock) that are mandatorily redeemable on September 22, 2010 to MidAmerican for $1 billion. If the merger is terminated other than because of a breach by MidAmerican or is not completed by June 19, 2009 (which may be extended to September 19, 2009), the Preferred Stock automatically converts into $1 billion of 14% Senior Notes of Constellation Energy and requires a payment to MidAmerican of Constellation Energy common stock or cash if approvals to issue shares have not yet been received. We discuss the Preferred Stock in more detail in the Notes to Consolidated Financial Statements beginning on page 21.

        We discuss our financing activities in more detail in the Notes to Consolidated Financial Statements beginning on page 20.


Maryland Settlement Agreement

In March 2008, Constellation Energy, BGE and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Maryland PSC and certain State of Maryland officials to resolve pending litigation and to settle other prior legal, regulatory and legislative issues. We discuss this settlement in more detail in the Notes to Consolidated Financial Statements on page 23.

39



Results of Operations for the Quarter and Nine Months Ended September 30, 2008 Compared with the Same Periods of 2007

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. Changes in other income, fixed charges, and income taxes are discussed, as necessary, in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section beginning on page 56.

Overview

Results

 
  Quarter
Ended
September 30,

  Nine Months
Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions, after-tax)
 

Merchant energy

  $ (246.0 ) $ 226.5   $ 105.9   $ 450.3  

Regulated electric

    31.7     34.3     (38.8 )   85.9  

Regulated gas

    (12.2 )   (9.8 )   24.1     18.2  

Other nonregulated

    0.8     (0.3 )   0.3     9.9  
   

(Loss) Income from Continuing Operations

    (225.7 )   250.7     91.5     564.3  
 

Income (loss) from discontinued operations

        0.7         (0.9 )
   

Net (Loss) Income

  $ (225.7 ) $ 251.4   $ 91.5   $ 563.4  
   

Other Items Included in Operations (after-tax)

 
 

Impairments and other costs

  $ (298.8 ) $   $ (298.8 ) $ (12.2 )
 

Merger and strategic alternatives costs

    (37.3 )       (37.3 )    
 

Accrual of Maryland settlement credit

            (125.3 )    
 

Effective tax rate impact of Maryland settlement agreement

    2.0         10.7      
 

Impairment of nuclear decommissioning trust assets

    (15.3 )       (21.5 )    
 

Emission allowance write-down, net

    (22.8 )       (36.2 )    
 

Non-qualifying hedges

    12.0     1.9     (57.3 )   (6.0 )
 

Workforce reduction costs

    (1.6 )       (1.6 )   (1.5 )
   

Total Other Items

  $ (361.8 ) $ 1.9   $ (567.3 ) $ (19.7 )
   

Quarter and Nine Months Ended September 30, 2008

Our total net income for the quarter and nine months ended September 30, 2008 compared to the same periods of 2007 decreased primarily due to the following:

 
  Quarter
Ended
September 30,

  Nine Months
Ended
September 30,

 
 
  2008 vs. 2007
 

 

 
 
  (In millions, after-tax)
 

Generation gross margin

  $ 78   $ 105  

Customer Supply gross margin

    (28 )   (4 )

Global Commodities gross margin

    (200 )   47  

Sale of upstream gas assets

        55  

2007 sale of CEP LLC equity

    (24 )   (31 )

Hedge ineffectiveness

    (28 )   (43 )

Credit loss—coal supplier bankruptcy

        (33 )

Merchant operating expenses, primarily labor and benefit costs

    99     24  

Merchant interest expense

    (19 )   (35 )

Synthetic fuel facilities

    15     (11 )

Other nonregulated businesses

        (10 )

Total Other Items included in operations per Overview—Results table

    (364 )   (548 )

Interest and investment income

    (9 )   (27 )

All other changes

    3     39  
   

Total

  $ (477 ) $ (472 )
   

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

40


Merchant Energy Business

Background

Our merchant energy business is a competitive provider of energy solutions for various customers. We discuss the impact of deregulation on our merchant energy business in Item 1. Business—Competition section of our 2007 Annual Report on Form 10-K.

        Our merchant energy business focuses on delivery of physical, customer-oriented products to producers and consumers, manages the risk and optimizes the value of our owned generation assets, and uses our portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. Currently, we are assessing the ongoing capital requirements of the merchant energy business, including evaluating the proper size of our Customer Supply business, and with respect to our Global Commodities business we are considering various strategic alternatives. As previously discussed, we have made substantial changes in our strategy, including focusing on the following immediate goals:

        The execution of our strategy in the future will be affected by our ability to achieve these goals as well as by continued instability in financial and commodities markets. Execution of our goals could have a substantial effect on the nature and mix of our business activities. In turn, this could affect our financial position, results of operations, and cash flows in material amounts, and these amounts could vary substantially from historical results. We discuss our strategy in more detail beginning on page 36.

        We record merchant energy revenues and expenses in our financial results in different periods depending upon which portion of our business they affect and based on the associated accounting policies. We discuss our revenue recognition policies in the Critical Accounting Policies section and Note 1 of our 2007 Annual Report on Form 10-K. We summarize our revenue and expense recognition policies as follows:

        The accounting for derivatives requires us to use judgment to make estimates and assumptions in determining the fair value of certain contracts and in recording revenues from those contracts. We discuss the effects of mark-to-market accounting on our results in the Mark-to-Market section beginning on page 46.

        Our Global Commodities operation actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. As part of these activities, we trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn additional returns. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines, and may have a material impact on our financial results. We discuss the impact of our portfolio management and trading activities and value at risk in more detail in the Mark-to-Market section beginning on page 46 and the Market Risk section beginning on page 64. As discussed above, we are currently assessing the ongoing capital requirements of the merchant energy business and are considering various alternative strategies. Additionally, we have focused our activities on reducing capital required, reducing long-term economic risk, and reducing short-term liquidity requirements. These actions may impact the future results of the merchant energy business.

41


Results

 
  Quarter Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Revenues

  $ 4,492.6   $ 5,275.9   $ 12,719.7   $ 14,113.7  

Fuel and purchased energy expenses

    (3,843.0 )   (4,319.2 )   (10,371.1 )   (11,808.0 )

Operating expenses

    (322.0 )   (486.1 )   (1,298.0 )   (1,338.0 )

Impairments and other costs

    (477.1 )       (477.1 )   (20.2 )

Workforce reduction costs

    (2.2 )       (2.2 )   (2.3 )

Merger and strategic alternatives costs

    (27.2 )       (27.2 )    

Depreciation, depletion, and amortization

    (68.6 )   (66.9 )   (207.8 )   (197.7 )

Accretion of asset retirement obligations

    (17.2 )   (16.0 )   (50.8 )   (51.9 )

Taxes other than income taxes

    (35.8 )   (29.1 )   (94.0 )   (85.0 )

Gains on sales of upstream gas assets

            91.5      
   

(Loss) Income from Operations

  $ (300.5 ) $ 358.6   $ 283.0   $ 610.6  
   

(Loss) Income from Continuing Operations (after-tax)

  $ (246.0 ) $ 226.5   $ 105.9   $ 450.3  
 

Income (loss) from discontinued operations (after-tax)

        0.7         (0.9 )
   

Net (Loss) Income

  $ (246.0 ) $ 227.2   $ 105.9   $ 449.4  
   

Other Items Included in Operations
(after-tax)

 
 

Impairments and other costs

  $ (298.8 ) $   $ (298.8 ) $ (12.2 )
 

Merger and strategic alternatives costs

    (25.8 )       (25.8 )    
 

Impairment of nuclear decommissioning trust assets

    (15.3 )       (21.5 )    
 

Emission allowance write-down, net

    (22.8 )       (36.2 )    
 

Non-qualifying hedges

    12.0     1.9     (57.3 )   (6.0 )
 

Workforce reduction costs

    (1.6 )       (1.6 )   (1.5 )
   

Total Other Items

  $ (352.3 ) $ 1.9   $ (441.2 ) $ (19.7 )
   

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 19 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

Revenues and Fuel and Purchased Energy Expenses

Our merchant energy business manages the revenues we realize from the sale of energy and energy-related products to our customers and our costs of procuring fuel and energy. As previously discussed, our merchant energy business uses either accrual, cash-flow hedge, or mark-to-market accounting to record our revenues and expenses. Mark-to-market results reflect the net impact of amounts recorded in earnings to recognize the changes in fair value of derivative contracts subject to mark-to-market accounting during the reporting period. We discuss the effects of mark-to-market accounting on our results separately in the Mark-to-Market section beginning on page 46.

Revenues

Our merchant energy revenues decreased $783.3 million and $1,394.0 million during the quarter and nine months ended September 30, 2008, respectively, compared to the same periods in 2007 primarily due to the following:

 
  Quarter
Ended
September 30,

  Nine Months
Ended
September 30,

 
 
  2008 vs. 2007
 

 

 
 
  (In millions)

 

Change in Global Commodities trading mark-to-market revenues due to unfavorable changes in power and gas prices

  $ (219 ) $ (27 )

Change in contract prices primarily related to our coal businesses

    (105 )   23  

Realization of higher contract prices on wholesale and retail load at our Global Commodities and Customer Supply operations

    217     401  

All other (substantially all due to change in gas procurement activities)1

    (676 )   (1,791 )
   

Total decrease in merchant energy revenues

  $ (783 ) $ (1,394 )
   

1 In the third quarter of 2007, we changed the management of the wholesale procurement function for retail gas activities from our Customer Supply operation to our Global Commodities operation. In connection with this change, we began to account for the underlying retail gas derivative contracts using mark-to-market accounting, under which changes in fair value are recorded in revenues as they occur. This activity was previously accounted for on a gross basis and recorded in accrual revenues and fuel and purchased energy expenses. The change to market-to-market accounting for this activity reduced both our accrual revenues and fuel and purchased energy expenses.

42


Fuel and Purchased Energy Expenses

During the quarter and nine months ended September 30, 2008, merchant energy fuel and purchased energy expenses decreased $476.2 million and $1,436.9 million, respectively, compared to the same periods in 2007 primarily due to the following:

 
  Quarter
Ended
September 30,

  Nine Months
Ended
September 30,

 
 
  2008 vs. 2007
 

 

 
 
  (In millions)
 

Change in Global Commodities mark-to-market expenses related to international coal purchase contracts

  $ (211 ) $ (219 )

Change in contract prices primarily related to our coal businesses

    (119 )   12  

Realization of higher contract prices on wholesale and retail purchases at our Global Commodities and Customer Supply operations

    280     510  

Decrease in synfuels expenses due to expiration of tax credits in 2007

    (32 )   (110 )

All other (substantially all due to change in gas procurement activities)1

    (394 )   (1,630 )
   

Total decrease in merchant energy purchased fuel and energy expenses

  $ (476 ) $ (1,437 )
   

1 In the third quarter of 2007, we changed the management of the wholesale procurement function for retail gas activities from our Customer Supply operation to our Global Commodities operation. In connection with this change, we began to account for the underlying retail gas derivative contracts using mark-to-market accounting, under which changes in fair value are recorded in revenues as they occur. This activity was previously accounted for on a gross basis and recorded in accrual revenues and fuel and purchased energy expenses. The change to market-to-market accounting for this activity reduced both our accrual revenues and fuel and purchased energy expenses.

        The difference between revenues and fuel and purchased energy expenses, including all direct expenses, represents the gross margin of our merchant energy business, and this measure is a useful tool for assessing the profitability of our merchant energy business. Accordingly, we believe it is appropriate to discuss the operating results of our merchant energy business by analyzing the changes in gross margin between periods. In managing our portfolio, we may terminate, restructure, or acquire contracts. Such transactions are within the normal course of managing our portfolio and may materially impact the timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows.

        We analyze our merchant energy gross margin in the following categories:

43


        We provide a summary of our gross margin for these three components of our merchant energy business as follows:

 
  Quarter Ended September 30,
  Nine Months Ended September 30,
 
 
  2008
   
  2007
   
  2008
   
  2007
   
 

 

 
 
  (Dollar amounts in millions)
 
 
   
  % of
Total
   
  % of
Total
   
  % of
Total
   
  % of
Total
 

Gross Margin:

                                                 
 

Generation

  $ 626     96 % $ 497     52 % $ 1,499     64 % $ 1,326     58 %
 

Customer Supply

    142     22     189     20     537     23     544     23  
 

Global Commodities

    (119 )   (18 )   271     28     312     13     436     19  
   
 

Total

  $ 649     100 % $ 957     100 % $ 2,348     100 % $ 2,306     100 %
   

Certain prior-period amounts have been reclassified to conform with the current period's presentation.

Generation

The $129 million increase in Generation gross margin during the quarter ended September 30, 2008 compared to the same period of 2007 is primarily due to the following:

        The $173 million increase in generation gross margin during the nine months ended September 30, 2008 compared to the same period of 2007 is primarily due to the following:

44


Customer Supply

The $47 million decrease in Customer Supply gross margin during the quarter ended September 30, 2008 compared to the same period of 2007 is primarily due to the following:

        These decreases were partially offset by the following:

        The $7 million decrease in Customer Supply gross margin during the nine months ended September 30, 2008 compared to the same period of 2007 is primarily due to approximately $70 million of lower expected realization of contracts executed in prior periods and lower new business originated and realized during the nine months ended September 30, 2008.

        This decrease was partially offset by the following:

Global Commodities

We present Global Commodities results in the following categories:

        As previously discussed in the Events of 2008 section beginning on page 38, the energy markets were affected by substantial changes in commodity prices during the nine months ended September 30, 2008. These market impacts are reflected in the $390 million decrease in gross margin from our Global Commodities activities during the quarter ended September 30, 2008 compared to the same period of 2007. This decrease is primarily a result of approximately $466 million of lower gross margin related to our portfolio management and trading operation due to the following factors:

        The decrease in gross margin is partially offset by higher gross margin of:

45


        The $124 million decrease in gross margin from our Global Commodities operation for the nine months ended September 30, 2008 compared to the same period in 2007 is primarily due to lower gross margin of approximately $405 million related to our portfolio management and trading operation, partially offset by approximately $204 million of higher gross margin in our structured products portfolio and approximately $77 million of higher gross margin in our energy investments portfolio. We discuss these changes below.

        The decrease in gross margin of $405 million as a result of portfolio management and trading is primarily related to the following:

        These decreases were partially offset by the following:

        The increase in gross margin of $204 million for the structured products portfolio is primarily related to the following:

        The increase in gross margin of $77 million for energy investments is primarily related to the following:

Mark-to-Market

Mark-to-market results include net gains and losses from origination, trading, and risk management 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 2007 Annual Report on Form 10-K.

        As a result of the nature of our operations and the use of mark-to-market accounting for certain activities, mark-to-market earnings will fluctuate. We cannot predict these fluctuations, but the impact on our earnings could be material. We discuss our market risk in more detail in the Market Risk section beginning on page 64. The primary factors that cause fluctuations in our mark-to-market results are:

        As discussed earlier, we are currently assessing the ongoing capital requirements of the merchant energy business and are considering various alternative strategies.

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Additionally, we have focused our activities on reducing capital requirements, reducing long-term economic risk, and reducing short-term liquidity requirements. These actions may impact the future results of the merchant energy business, particularly the size of and potential for changes in fair value of activities subject to mark-to-market accounting. In the fourth quarter of 2008, we dedesignated our cash-flow hedge transactions related to our international business resulting in mark-to-market accounting for these transactions going forward.

        The primary components of mark-to-market results are origination gains and gains and losses from risk management and trading activities.

        Origination gains arise primarily from contracts that our Global Commodities operation structures to meet the risk management needs of our customers or relate to our trading activities. Transactions that result in origination gains may be unique and provide the potential for individually significant revenues and gains from a single transaction.

        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 derivative contracts subject to mark-to-market accounting to manage our exposure to changes in market prices as a result of our gas transportation and storage activities, while in general the underlying physical transactions related to our gas transportation and storage activities are accounted for on an accrual basis. We use other non-trading derivative transactions subject to mark-to-market accounting to manage our exposure to changes in market prices related to our other activities that 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
September 30,

  Nine Months Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Unrealized mark-to-market results

                         
 

Origination gains

  $ 5.3   $ 4.3   $ 73.8   $ 37.4  
   
 

Risk management and trading—mark-to-market

                         
   

Unrealized changes in fair value

    (54.4 )   92.4     243.1     170.0  
   

Changes in valuation techniques

                 
   

Reclassification of settled contracts to realized

    288.1     (21.3 )   141.2     (189.2 )
   
 

Total risk management and trading—mark-to-market

    233.7     71.1     384.3     (19.2 )
   

Total unrealized mark-to-market*

    239.0     75.4     458.1     18.2  

Realized mark-to-market

    (288.1 )   21.3     (141.2 )   189.2  
   

Total mark-to-market results

  $ (49.1 ) $ 96.7   $ 316.9   $ 207.4  
   

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

        Total mark-to-market results decreased $145.8 million during the quarter ended September 30, 2008 compared to the same period of 2007 primarily due to unrealized changes in fair value. The period-to-period variance in unrealized changes in fair value was primarily due to:

        The risk management and trading results were partially offset by:

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        Total mark-to-market results increased $109.5 million during the nine months ended September 30, 2008 compared to the same period of 2007 primarily due to:

        The $73.1 million increase in gains from unrealized changes in fair value was primarily due to

        During the nine months ended September 30, 2008, our Global Commodities operation amended certain nonderivative contracts to mitigate counterparty performance risk under the existing contracts. As a result of these amendments, the revised contracts are derivatives subject to mark-to-market accounting under Statement of Financial Accounting Standard (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The change in accounting for these contracts from nonderivative to derivative resulted in substantially all of the origination gains for 2008 presented in the table on the previous page.

        During the nine months ended September 30, 2007, our Global Commodities operation amended certain nonderivative power sales contracts such that the new contracts are derivatives subject to mark-to-market accounting under SFAS No. 133. Simultaneous with the amending of the nonderivative contracts, we executed at current market prices several new offsetting derivative power purchase contracts subject to mark-to-market accounting. The combination of these transactions resulted in substantially all of the origination gains presented for the first nine months of 2007 in the table on the previous page, as well as mitigated our risk exposure under the amended contracts. The origination gain from these 2007 transactions was partially offset by approximately $12 million of losses in our accrual portfolio due to the reclassification of losses related to cash-flow hedges previously established for the amended nonderivative contracts from "Accumulated other comprehensive loss" into earnings. In the absence of these transactions, the origination gain and the losses associated with cash-flow hedges would have been recognized over the remaining term of the contracts, which would have extended through the first quarter of 2009.

Derivative Assets and Liabilities

        Derivative assets and liabilities consisted of the following:

 
  September 30,
2008

  December 31,
2007

 

 

 
 
  (In millions)
 

Current Assets

  $ 1,604.7   $ 760.6  

Noncurrent Assets

    1,006.0     1,030.2  
   

Total Assets

    2,610.7     1,790.8  
   

Current Liabilities

    1,115.8     1,134.3  

Noncurrent Liabilities

    1,171.1     1,118.9  
   

Total Liabilities

    2,286.9     2,253.2  
   

Net Derivative Position

  $ 323.8   $ (462.4 )
   

Composition of net derivative exposure:

       

Embedded derivative associated with $1 billion preferred stock issued to MidAmerican

  $ (46.2 ) $  

Hedges

    (1,215.0 )   (937.6 )

Mark-to-market

    1,559.8     673.0  

Net cash collateral included in derivative balances

    25.2     (197.8 )
   

Net Derivative Position

  $ 323.8   $ (462.4 )
   

        As discussed in our 2007 Annual Report on Form 10-K, our "Derivative assets and liabilities" include contracts accounted for as hedges and those accounted for on a mark-to-market basis. The amounts are presented in our Consolidated Balance Sheets after the impact of netting as required by FSP FIN 39-1, which is discussed in more detail in the Notes to Consolidated Financial Statements beginning on page 30. Due to the impacts of commodity prices, the number of open positions, master netting arrangements, and offsetting risk positions on the presentation of our derivative assets and liabilities in our Consolidated Balance Sheets, we believe an evaluation of the net position is the most relevant measure of the economic exposure and performance of our derivatives, and is discussed in more detail below. However, in order to provide information about how we determine the fair value of derivatives, we present our gross derivatives as required by SFAS No. 157 in the Notes to Consolidated Financial Statements beginning on page 31.

        We determined that the conversion provisions of the Preferred Stock that we issued to MidAmerican constitute an embedded derivative that must be bifurcated from the Preferred Stock and recorded at fair value with changes in fair value recorded in earnings. Accordingly, we recorded a current derivative liability of approximately $46.2 million as the fair value of this conversion feature as of September 30, 2008 and we recorded a corresponding discount on the Preferred Stock. We discuss the Preferred Stock in detail in

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the Notes to Consolidated Financial Statements beginning on page 21.

        The fair value of this derivative could change substantially in the future based upon discrete factors. The primary factors that could change its value, other than the passage of time and changes in interest rates, are:

        It is not possible to predict whether these events could occur, but if and when they do, the fair value of the derivative could increase or decrease substantially. Such changes would be recorded in earnings when they occur and could be material. Upon receipt of all approvals necessary to issue 19.9% of the shares of our common stock to a single party, we expect the derivative will be an equity instrument, and we will reclassify the fair value at that time to common shareholders equity and discontinue recording changes in its fair value, in accordance with SFAS No. 133.

        The increase of $277.4 million in our net derivative liability exposure relating to hedges since December 31, 2007 was primarily due to $353 million of losses associated with existing hedge positions due to unfavorable price changes and $267 million of losses associated with hedges entered into during 2008, partially offset by $328 million related to the settlement of out-of-the-money cash-flow hedges during the first nine months of 2008.

        The following are the primary sources of the change in the net mark-to-market derivative asset during the quarter and nine months ended September 30, 2008:

 
  Quarter Ended
September 30, 2008

  Nine Months Ended
September 30, 2008

 

 

 
 
  (in millions)
 

Fair value beginning of period

        $ 1,380.1         $ 673.0  

Changes in fair value recorded in earnings

                         
 

Origination gains

  $ 5.3         $ 73.8        
 

Unrealized changes in fair value

    (54.4 )         243.1        
 

Changes in valuation techniques

                     
 

Reclassification of settled contracts to realized

    288.1           141.2        
                       

Total changes in fair value

          239.0           458.1  

Changes in value of exchange-listed futures and options

          (124.6 )         418.7  

Net change in premiums on options

          68.1           75.2  

Contracts acquired

                     

Other changes in fair value

          (2.8 )         (65.2 )
   

Fair value at end of period

        $ 1,559.8         $ 1,559.8  
   

        Changes in our net mark-to-market derivative asset included in earnings were as follows:

        The net mark-to-market derivative asset also changed due to the following items recorded in accounts other than in our Consolidated Statements of Income (Loss):

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        Effective January 1, 2008, we adopted SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and requires certain disclosures about fair value measurements. Fair value is the price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

        Consistent with the exit price concept, upon adoption we reduced our derivative liabilities to reflect our own credit risk. As a result, during the first quarter of 2008, we recorded a pre-tax reduction in "Accumulated other comprehensive loss" totaling $10 million for the portion related to cash-flow hedges and a pre-tax gain in earnings totaling $3 million for the remainder of our derivative liabilities. All other impacts of adoption were immaterial. We discuss SFAS No. 157 and how we determine fair value in more detail in the Notes to Consolidated Financial Statements beginning on page 31.

        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 established by SFAS No. 157 are as follows as of September 30, 2008:

 
  Settlement Term
   
 
 
     
 
 
  2008
  2009
  2010
  2011
  2012
  2013
  Thereafter
  Fair Value
 

 

 
 
  (In millions)
 

Level 1

  $ 10.9   $   $   $   $   $   $   $ 10.9  

Level 2

    278.6     579.3     (77.5 )   113.3     59.1     (7.7 )   0.2     945.3  

Level 3

    54.4     161.2     333.7     101.1     (37.5 )   (9.2 )   (0.1 )   603.6  
   

Total net derivative asset subject to mark-to-market accounting

  $ 343.9   $ 740.5   $ 256.2   $ 214.4   $ 21.6   $ (16.9 ) $ 0.1   $ 1,559.8  
   

        Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. Additionally, because the depth and liquidity of the power markets varies substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed. Future market prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is possible that such variations could be material.

        We manage our mark-to-market risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each contract. Accordingly, we manage the energy purchase and sale obligations under our contracts in separate components based upon the commodity (e.g., electricity or gas), the product (e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk profile (e.g., forward or option), and the delivery period (e.g., by month and year).

        The electricity, fuel, and other energy contracts we hold have varying terms to maturity, ranging from contracts for delivery the next hour to contracts with terms of ten years or more. Because an active, liquid electricity futures market comparable to that for other commodities has not developed, many contracts are direct contracts between market participants and are not exchange-traded or financially settling contracts that can be readily offset in their entirety through an exchange or other market mechanism. Consequently, we and other market participants generally realize the value of these contracts as cash flows become due or payable under the terms of the contracts rather than through selling or liquidating the contracts themselves.

        In order to realize the entire value of a long-term contract in a single transaction, we would need to sell or assign the entire contract. If we were to sell or assign any of our long-term contracts in their entirety, we may not realize the entire value reflected in the preceding table.

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Operating Expenses

Our merchant energy business operating expenses decreased $164.1 million during the quarter ended September 30, 2008 compared to the same period of 2007, primarily due to lower performance-based labor and benefits costs at our merchant energy business of $143.0 million and lower nonlabor operating expenses of $21.1 million.

        Our merchant energy business operating expenses decreased $40.0 million during the nine months ended September 30, 2008 compared to the same period of 2007. The decrease was primarily due to lower performance-based labor and benefit costs of $56.1 million, partially offset by higher nonlabor operating expenses of $16.1 million.

Workforce Reduction Costs

In September 2008, our merchant energy business approved a restructuring of the workforce at our Customer Supply operations. We recognized a $2.2 million pre-tax expense during the quarter ended September 30, 2008 related to the elimination of approximately 100 positions associated with this restructuring. We discuss our workforce reduction costs in more detail in the Notes to Consolidated Financial Statements on page 16.

Impairments and Other Costs

During the quarter ended September 30, 2008, our merchant energy business recorded a $462.1 million charge associated with an impairment of our upstream gas assets, our investment in Constellation Energy Partners LLC, and goodwill. We discuss these impairments in more detail in the Notes to Consolidated Financial Statements beginning on page 12. Additionally, we recorded a liability for the anticipated settlement of the fly ash class action litigation of $15.0 million, net of an estimated insurance recovery. We discuss the fly ash litigation settlement in more detail in the Notes to Consolidated Financial Statements on pages 15 and 27.

Merger and Strategic Alternatives Costs

During the quarter ended September 30, 2008, our merchant energy business recorded a $27.2 million pre-tax charge associated with the pending merger with MidAmerican and other strategic alternatives costs. We discuss our merger and strategic alternatives costs in more detail in the Notes to Consolidated Financial Statements on page 12.

Depreciation, Depletion and Amortization Expense

Our merchant energy business incurred higher depreciation, depletion and amortization expenses of $10.1 million during the nine months ended September 30, 2008 compared to the same period of 2007, primarily due to increased depletion expenses related to our upstream natural gas operations as a result of increased drilling and production, partially offset by the cessation of operations at our synfuel facilities in December 2007.

Gains on Sales of Assets

For the nine months ended September 30, 2008, we recognized gains of $91.5 million, including a $14.3 million gain, net of the minority interest gain of $0.7 million, related to the sale of our working interests in oil and natural gas producing wells in Oklahoma to Constellation Energy Partners that was completed in the first quarter of 2008.

        We discuss our gains on sale of assets in more detail in the Notes to Consolidated Financial Statements on page 17.

Regulated Electric Business

Our regulated electric business is discussed in detail in Item 1. Business—Electric Business section of our 2007 Annual Report on Form 10-K.

Results

 
  Quarter Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Revenues

  $ 822.4   $ 778.2   $ 1,980.5   $ 1,837.3  

Electricity purchased for resale expenses

    (556.6 )   (522.6 )   (1,416.2 )   (1,117.7 )

Operations and maintenance expenses

    (99.0 )   (96.7 )   (291.9 )   (274.9 )

Merger and strategic alternatives costs *

    (7.9 )       (7.9 )    

Depreciation and amortization

    (39.4 )   (46.8 )   (138.0 )   (140.5 )

Taxes other than income taxes

    (36.3 )   (36.1 )   (104.1 )   (105.8 )
   

Income from Operations

  $ 83.2   $ 76.0   $ 22.4   $ 198.4  
   

Net Income (Loss)

  $ 31.7   $ 34.3   $ (38.8 ) $ 85.9  
   

Other Items Included in Operations (after-tax):

                         

Maryland settlement credit

  $   $   $ (125.3 ) $  

Effective tax rate impact of Maryland settlement agreement

    3.4         8.4      

Merger and strategic alternatives costs *

    (7.5 )       (7.5 )    
   

Total Other Items

  $ (4.1 ) $   $ (124.4 ) $  
   

        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 19 provides a reconciliation of operating results by segment to our Consolidated Financial Statements

* Recovery of these costs will not be sought in rates.

        Net income from the regulated electric business decreased $2.6 million during the quarter ended September 30, 2008 compared to the same period in 2007, mostly due to merger and strategic alternatives costs of $7.5 million after-tax partially offset by the impact on the effective tax rate of the Maryland settlement credit of $3.4 million after-tax.

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        Net income from the regulated electric business decreased $124.7 million during the nine months ended September 30, 2008 compared to the same periods in 2007, mostly due to the impact of the Maryland settlement credit of $125.3 million after-tax and the merger and strategic alternatives costs of $7.5 million after-tax. This was partially offset by the favorable impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $8.4 million for the nine months ended September 30, 2008.

Electric Revenues

The changes in electric revenues in 2008 compared to 2007 were caused by:

 
  Quarter Ended
September 30,
2008 vs. 2007

  Nine Months Ended
September 30,
2008 vs. 2007

 

 

 
 
  (In millions)
 

Distribution volumes

  $ (4.7 ) $ (9.8 )

Maryland settlement credit

    (0.6 )   (188.8 )

Revenue decoupling

    8.8     15.8  

Standard offer service

    22.8     5.9  

Rate stabilization credits

    4.6     285.4  

Rate stabilization recovery

    6.5     34.9  

Financing credits

    (1.0 )   (8.1 )

Senate Bill 1 credits

    5.6     (0.4 )
   

Total change in electric revenues from electric system sales

    42.0     134.9  

Other

    2.2     8.3  
   

Total change in electric revenues

  $ 44.2   $ 143.2  
   

Distribution Volumes

Distribution volumes are the amount of electricity that BGE delivers to customers in its service territory.

        The percentage changes in our electric distribution volumes, by type of customer, in 2008 compared to 2007 were:

 
  Quarter Ended
September 30,
2008 vs. 2007

  Nine Months Ended
September 30,
2008 vs. 2007

 

 

 

Residential

    (7.9 )%   (4.9 )%

Commercial

    (0.7 )   (3.1 )

Industrial

    (4.5 )   (2.2 )

        During the quarter ended September 30, 2008 compared to the same period of 2007, we distributed less electricity to residential customers mostly due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed less electricity to commercial customers due to milder weather, partially offset by increased usage per customer and an increased number of customers. We distributed less electricity to industrial customers, primarily due to decreased usage per customer, partially offset by an increased number of customers.

        During the nine months ended September 30, 2008 compared to the same period of 2007, we distributed less electricity to residential and commercial customers due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed less electricity to industrial customers, primarily due to decreased usage per customer, partially offset by an increased number of customers.

Maryland Settlement Credit

As discussed in more detail in the Notes to Consolidated Financial Statements on page 23, BGE entered into a settlement agreement with the State of Maryland and other parties, which provided residential electric customers a credit of $170 per customer. The estimated settlement of $188.2 million was accrued in the second quarter of 2008 and $188.8 million was credited to customers in the third quarter of 2008.

Revenue Decoupling

Beginning in January 2008, the Maryland PSC allows us to record a monthly adjustment to our electric distribution revenues from residential and small commercial customers to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes. This means our monthly electric distribution revenues for residential and small commercial customers are based on weather and usage that is considered "normal" for the month. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.

Standard Offer Service

BGE provides standard offer service for customers that do not select an alternative supplier. We discuss the provisions of Senate Bill 1 related to residential electric rates in the Item 7. Management's Discussion and Analysis—Business Environment—Regulation—Maryland—Senate Bills 1 and 400 section of our 2007 Annual Report on Form 10-K.

        Standard offer service revenues increased during the quarter and nine months ended September 30, 2008 compared to the same periods of 2007, mostly due to higher standard offer service rates, partially offset by lower standard offer service volumes.

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Rate Stabilization Credits

As a result of Senate Bill 1, we were required to defer from July 1, 2006 until May 31, 2007 a portion of the full market rate increase resulting from the expiration of the residential rate freeze. In addition, we offered a second plan also required under Senate Bill 1 allowing residential customers the option to defer the transition to market rates from June 1, 2007 until January 1, 2008. The decrease in rate stabilization credits during the quarter and nine months ended September 30, 2008 compared to the same periods in 2007 was primarily due to the expiration of the second rate stabilization plan which began on June 1, 2007 and ended on December 31, 2007.

Rate Stabilization Recovery

In late June 2007, BGE began recovering amounts deferred during the first rate deferral period that ended on May 31, 2007. In April 2008, BGE began recovering amounts deferred during the second rate deferral period that ended on December 31, 2007. The recovery of the second rate deferral will occur over a 21-month period that began April 1, 2008 and ending on December 31, 2009. The recovery of the first rate stabilization plan will occur over approximately ten years.

Financing Credits

Concurrent with the recovery of the deferred amounts related to the first rate deferral period, we are providing credits to residential customers to compensate them primarily for income tax benefits associated with the financing of the deferred amounts with rate stabilization bonds.

Senate Bill 1 Credits

As a result of Senate Bill 1, beginning January 1, 2007, we were required to provide to residential electric customers a credit equal to the amount collected from all BGE electric customers for the decommissioning of our Calvert Cliffs nuclear power plant and to suspend collection of the residential return component of the POLR administrative charge collected through residential rates through May 31, 2007. Under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, we were required to reinstate collection of the residential return component of the POLR administration charge in rates and to provide all residential electric customers a credit for the residential return component of the administrative charge. Under the Maryland settlement agreement, which is discussed in more detail on page 23 of Notes to Consolidated Financial Statements, BGE was allowed to resume collection of the residential return portion of the POLR administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to residential customers.

        The increase in revenues during the quarter ended September 30, 2008 compared to the same period of 2007 is primarily due to the absence of the credit for the residential return component of the administrative charge which was suspended under the Maryland settlement agreement.

Electricity Purchased for Resale Expenses

Electricity purchased for resale expenses include the cost of electricity purchased for resale to our standard offer service customers. These costs do not include the cost of electricity purchased by delivery service only customers.

 
  Quarter Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Actual costs

  $ 537.7   $ 508.4   $ 1,372.0   $ 1,379.1  

Deferral under rate stabilization plan

        (4.5 )       (285.4 )

Recovery under rate stabilization plan

    18.9     18.7     44.2     24.0  
   

Electricity purchased for resale expenses

  $ 556.6   $ 522.6   $ 1,416.2   $ 1,117.7  
   

Actual Costs

BGE's actual costs for electricity purchased for resale increased $29.3 million during the quarter ended September 30, 2008 compared to the same period of 2007, primarily due to higher contract prices to purchase electricity for our customers, partially offset by lower volumes.

        BGE's actual costs for electricity purchased for resale decreased $7.1 million during the nine months ended September 30, 2008 compared to the same period of 2007, primarily due to lower volumes, partially offset by higher contract prices to purchase electricity for our customers.

Deferral under Rate Stabilization Plan

The deferral of the difference between our actual costs of electricity purchased for resale and what we were allowed to bill customers under Senate Bill 1 ended on December 31, 2007. These deferred expenses, plus carrying charges, are included in "Regulatory Assets (net)" in our, and BGE's, Consolidated Balance Sheets.

Recovery under Rate Stabilization Plans

In late June 2007, we began recovering previously deferred amounts from customers related to our first rate stabilization plan. In April 2008, we began recovering previously deferred amounts from customers related to our second rate stabilization plan. During the quarter and nine months ended September 30, 2008, we recovered $18.9 million and $44.2 million, respectively, in deferred electricity purchased for resale expenses. The collections related to the first rate stabilization plan secure the payment of principal and interest and other ongoing costs associated

53


with rate stabilization bonds issued by a subsidiary of BGE in June 2007.

Electric Operations and Maintenance Expenses

Regulated operations and maintenance expenses increased $17.0 million in the nine months ended September 30, 2008 compared to the same period in 2007, mostly due to increased uncollectible accounts receivable expense of $10.0 million and $6.2 million of higher labor and benefit costs and the impact of inflation on other costs.

Electric Depreciation and Amortization

Regulated electric depreciation and amortization expense decreased $7.4 million during the quarter ended September 30, 2008 compared to the same period in 2007, primarily due to revised depreciation rates implemented as of June 1, 2008. As a result of the Maryland settlement agreement, which is discussed in more detail on page 23 of the Notes to Consolidated Financial Statements, BGE implemented revised depreciation rates for regulatory and financial reporting purposes effective June 1, 2008 that are expected to reduce annual depreciation expense by approximately $16 to $18 million for BGE's electric business. The impact of the revised depreciation rates on BGE's electric business for the nine months ended September 30, 2008 was a reduction in depreciation expense of $5.7 million.

Regulated Gas Business

Our regulated gas business is discussed in detail in Item 1. Business—Gas Business section of our 2007 Annual Report on Form 10-K.

Results

 
  Quarter Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Revenues

  $ 155.5   $ 118.7   $ 740.0   $ 688.8  

Gas purchased for resale expenses

    (107.5 )   (70.6 )   (505.2 )   (457.6 )

Operations and maintenance expenses

    (40.5 )   (38.1 )   (118.0 )   (114.3 )

Merger and strategic alternatives costs*

    (3.2 )       (3.2 )    

Depreciation and amortization

    (10.1 )   (11.6 )   (33.2 )   (35.3 )

Taxes other than income taxes

    (7.8 )   (7.9 )   (26.6 )   (27.0 )
   

(Loss) Income from operations

  $ (13.6 ) $ (9.5 ) $ 53.8   $ 54.6  
   

Net (Loss) Income

  $ (12.2 ) $ (9.8 ) $ 24.1   $ 18.2  
   

Other Items Included in Operations (after-tax):

                         

Effective tax rate impact of Maryland settlement agreement

  $ (1.4 ) $   $ 2.3   $  

Merger and strategic alternatives costs*

    (3.1 )       (3.1 )    
   

Total Other Items

  $ (4.5 ) $   $ (0.8 ) $  
   

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 19 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
* Recovery of these costs will not be sought in rates.

Net loss from the regulated gas business increased $2.4 million during the quarter ended September 30, 2008 compared to the same period of 2007, primarily due to merger and strategic alternatives costs of $3.1 million after-tax and the impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $1.4 million, partially offset by reduced depreciation and amortization expense of $1.0 million after-tax.

        Net income from the regulated gas business increased $5.9 million during the nine months ended September 30, 2008 compared to the same period of 2007, primarily due to an increase in revenues less gas purchased for resale expenses of $2.4 million after-tax and the impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $2.3 million.

54


Gas Revenues

The changes in gas revenues in 2008 compared to 2007 were caused by:

 
  Quarter Ended
September 30,
2008 vs. 2007

  Nine Months Ended
September 30,
2008 vs. 2007

 

 

 
 
  (In millions)
 

Distribution volumes

  $ (0.3 ) $ (9.6 )

Base rates

        (0.1 )

Revenue decoupling

    0.4     10.8  

Gas cost adjustments

    14.6     (1.5 )
   

Total change in gas revenues from gas system sales

    14.7     (0.4 )

Off-system sales

    22.4     51.3  

Other

    (0.3 )   0.3  
   

Total change in gas revenues

  $ 36.8   $ 51.2  
   

Distribution Volumes

The percentage changes in our distribution volumes, by type of customer, in 2008 compared to 2007 were:

 
  Quarter Ended
September 30,
2008 vs. 2007

  Nine Months Ended
September 30,
2008 vs. 2007

 

 

 

Residential

    (1.0 )%   (10.3 )%

Commercial

    (12.1 )   (5.3 )

Industrial

    5.3     10.1  

        During the quarter ended September 30, 2008 compared to the same period in 2007, we distributed less gas to residential and commercial customers due to decreased usage per customer, partially offset by an increased number of customers. We distributed more gas to industrial customers mostly due to increased usage per customer.

        During the nine months ended September 30, 2008 compared to the same period in 2007, we distributed less gas to residential and commercial customers due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed more gas to industrial customers mostly due to increased usage per customer.

Base Rates

In December 2005, the Maryland PSC issued an order granting BGE a $35.6 million annual increase in its gas base rates. In December 2006, the Baltimore City Circuit Court upheld the rate order. Certain parties filed an appeal with the Court of Special Appeals. However, in September 2008, the Court of Special Appeals upheld the rate order.

Revenue Decoupling

The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather and usage patterns on our gas distribution volumes. This means our monthly gas distribution revenues are based on weather and usage that is considered "normal" for the month. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.

Gas Cost Adjustments

We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC as described in Note 1 of our 2007 Annual Report on Form 10-K.

        Gas cost adjustment revenues increased $14.6 million during the quarter ended September 30, 2008 compared to the same period of 2007, primarily due to higher prices, partially offset by less gas sold.

        Gas cost adjustment revenues decreased $1.5 million during the nine months ended September 30, 2008 compared to the same period of 2007 because we sold less gas, partially offset by higher prices.

Off-System Gas Sales

Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Off-system gas sales, which occur after we have satisfied our customers' demand, are not subject to gas cost adjustments. The Maryland PSC approved an arrangement for part of the margin from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). Changes in off-system sales do not significantly impact earnings.

        Revenues from off-system gas sales increased during the quarter ended September 30, 2008 compared to the same period of 2007 because the gas we sold off-system was at higher prices, partially offset by less gas sold.

        Revenues from off-system gas sales increased during the nine months ended September 30, 2008 compared to the same period of 2007 because we sold more gas at higher prices.

Gas Purchased For Resale Expenses

Gas purchased for resale expenses include the cost of gas purchased for resale to our customers and for off-system sales. These costs do not include the cost of gas purchased by delivery service only customers.

        Gas costs increased $36.9 million during the quarter ended September 30, 2008 compared to the same period of 2007 because we purchased gas at higher prices, partially offset by lower volumes.

        Gas costs increased $47.6 million during the nine months ended September 30, 2008 compared to the same period of 2007 because we purchased gas at higher prices, partially offset by lower volumes.

55


Gas Operations and Maintenance Expenses

Gas operations and maintenance expenses increased $2.4 million in the quarter ended September 30, 2008 compared to the same period in 2007, mostly due to increased uncollectible accounts receivable expense of $2.4 million.

        Gas operations and maintenance expenses increased $3.7 million in the nine months ended September 30, 2008 compared to the same period in 2007, mostly due to increased uncollectible accounts receivable expense of $4.1 million.

Gas Depreciation and Amortization

As a result of the Maryland settlement agreement, which is discussed in more detail on page 23 of Notes to Consolidated Financial Statements, BGE implemented revised depreciation rates for regulatory and financial reporting purposes effective June 1, 2008 that are expected to reduce annual depreciation expense by approximately $6 million for its gas business. The impact of the revised depreciation rates on BGE's gas business for the nine months ended September 30, 2008 was a reduction in depreciation expense of $2.0 million.

Other Nonregulated Businesses

Results

 
  Quarter Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2008
  2007
  2008
  2007
 

 

 
 
  (In millions)
 

Revenues

  $ 50.2   $ 55.0   $ 175.5   $ 174.5  

Operating expense

    (29.4 )   (41.4 )   (128.4 )   (114.5 )

Merger and strategic alternatives costs

    (0.9 )       (0.9 )    

Depreciation and amortization

    (16.2 )   (13.0 )   (45.5 )   (40.0 )

Taxes other than income taxes

    (1.2 )   (0.6 )   (2.3 )   (1.9 )
   

Income (Loss) from Operations

  $ 2.5   $   $ (1.6 ) $ 18.1  
   

Net Income

  $ 0.8   $ (0.3 ) $ 0.3   $ 9.9  
   

Other Items Included in Operations (after-tax):

                         

Merger and strategic alternatives costs

  $ (0.9 ) $   $ (0.9 ) $  
   

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 19 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

        Net income decreased $9.6 million during the nine months ended September 30, 2008 compared to the same period of 2007 primarily because the first quarter of 2007 included a gain related to a sale of a leasing arrangement that did not occur in 2008.

Consolidated Nonoperating Income and Expenses

Gains on Sale of CEP LLC Equity

Gains on sale of CEP LLC Equity decreased $39.2 million and $52.1 million for the quarter and nine months ended September 30, 2008, respectively, as CEP LLC, an equity investment of Constellation Energy, did not sell additional equity in 2008 as it had in the second and third quarters of 2007.

Other (Expense) Income

Other (expense) income decreased during the quarter and nine months ended September 30, 2008 compared to the same periods of 2007 mostly due to lower interest and investment income as a result of a lower average cash balance and an increase in other-than-temporary impairment charges related to our nuclear decommissioning trust fund assets of $29.2 million for the quarter ended September 30, 2008 and $39.1 million for the nine months ended September 30, 2008.

        Other income at BGE increased $4.2 million during the nine months ended September 30, 2008 compared to the same period of 2007 primarily due to an increase in equity funds capitalized on increased construction work in progress in 2008.

Fixed Charges

Our fixed charges increased during the quarter and nine months ended September 30, 2008 compared to the same periods of 2007 mostly due to a higher level of interest expense associated with the new debt issuances in June 2008, partially offset by higher capitalized interest and allowance for borrowed funds used during construction. We discuss our long-term debt financings in more detail in the Notes to Consolidated Financial Statements on page 21.

        Fixed charges at BGE increased during the quarter and nine months ended September 30, 2008 compared to the same periods of 2007 mostly due to interest expense recognized on the rate stabilization bonds that were issued in June 2007 and the Senior Notes issued in June 2008. We discuss BGE's long-term debt financings in more detail in the Notes to Consolidated Financial Statements on page 21.

Income Taxes

Our income tax expense decreased $275.9 million during the quarter ended September 30, 2008 and $187.0 million during the nine months ended September 30, 2008 compared to the same periods of 2007 mostly due to a decrease in income before income taxes, partially offset by the absence of synthetic fuel tax credits, which expired in 2007.

        During the quarter ended September 30, 2008, BGE's income tax expense increased $4.6 million, primarily due to higher pre-tax income, which included the impact of

56


approximately $11 million in merger and strategic alternatives costs, substantially all of which are not tax deductible. During the nine months ended September 30, 2008, BGE's income tax expense decreased $65.8 million, primarily due to lower pre-tax income as a result of the $188 million Maryland settlement credit recorded in the second quarter of 2008. We discuss the Maryland settlement agreement in more detail in the Notes to Consolidated Financial Statements on page 23.

Defined Benefit Plans Expense and Funded Status

Our actual return on qualified pension plan assets was a loss of 16.9% for the nine months ended September 30, 2008 as compared to our assumption of an expected annual return on pension plan assets of 8.75% for the purpose of computing annual net periodic pension cost in accordance with SFAS No. 87, Employers' Accounting for Pensions. This loss reflects the substantial declines in financial markets experienced through the first nine months of 2008. As disclosed in Note 7 of our 2007 Annual Report on Form 10-K, we determine the expected return on pension plan assets component of our annual pension expense using a market-related value of pension plan assets that recognizes asset gains and losses over a five-year period. As a result, the losses incurred during the first nine months of 2008 would increase our annual pension expense beginning in 2009. In addition, a lower fair value of our pension plan assets would result in an increase in our unfunded pension obligation at December 31, 2008 and a related after-tax charge to "Accumulated other comprehensive loss" in accordance with SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans.

        In addition to the losses experienced on our pension plan assets for the nine months ended September 30, 2008, there has also been an overall increase in the level of interest rates, which will impact the discount rate used to determine our defined benefit plan liabilities. In accordance with SFAS No. 87, Employers' Accounting for Pensions, and SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, we are currently using a 6.25% discount rate assumption, which is based on interest rate levels at December 31, 2007, to determine our 2008 pension and postretirement benefit expense. The next time we will update our discount rate assumption will be at December 31, 2008. That updated assumption will impact 2009 annual pension and postretirement benefits expense and the funded status of our pension and postretirement benefit plans at December 31, 2008. Based on interest rate levels at September 30, 2008, our discount rate assumption would increase from 6.25% to 7.50% and have the result of reducing 2009 pension and postretirement benefits expense and improving the funded status of those plans at December 31, 2008.

        Assuming that our qualified pension plan assets earn approximately 2.2% in the fourth quarter (one-fourth of our expected annual asset return of 8.75%) and that interest rate levels remain unchanged between September 30, 2008 and December 31, 2008, we estimate that:

        Since September 30, 2008, our pension plan assets have experienced further losses. However, our actual 2009 pension and postretirement benefits expense and December 31, 2008 funded status of our defined benefit plans will reflect the impact of actual asset returns for the year 2008 and actual interest rate levels at December 31, 2008. Therefore, those amounts could be materially different from the estimates above as of September 30, 2008. Actual asset returns and interest rate levels may also materially impact the level of our contributions to our qualified pension plans in 2009 and subsequent years.

57



Financial Condition

Cash Flows

The following table summarizes our cash flows for 2008 and 2007, excluding the impact of changes in intercompany balances.

 
  2008 Segment Cash Flows   Consolidated Cash Flows  
 
  Nine Months Ended
September 30, 2008

  Nine Months Ended
September 30,

 
 
  Merchant
  Regulated
  Other
   
  2008
  2007
 

 

 
 
  (In millions)

 

Operating Activities

                                   
 

Net income (loss)

  $ 105.9   $ (14.7 ) $ 0.3       $ 91.5   $ 563.4  
 

Non-cash adjustments to net income

    437.6     239.1     53.1         729.8     248.7  
 

Changes in working capital:

                                   
   

Derivative assets and liabilities, excluding collateral

    (931.4 )       (3.6 )       (935.0 )   (78.9 )
   

Net collateral and margin

    (571.2 )   2.6             (568.6 )   109.8  
   

Other changes

    (312.9 )   12.0     (57.7 )       (358.6 )   (172.9 )
 

Defined benefit obligations*

                    (34.2 )   (48.0 )
 

Other

    64.7     (41.0 )   27.4         51.1     (5.4 )
               

Net cash (used in) provided by operating activities

    (1,207.3 )   198.0     19.5         (1,024.0 )   616.7  
               

Investing Activities

                                   
 

Investments in property, plant and equipment

    (986.1 )   (314.9 )   (59.5 )       (1,360.5 )   (920.3 )
 

Acquisitions, net of cash acquired

    (309.4 )       (7.1 )       (316.5 )   (344.1 )
 

Contributions to nuclear decommissioning trust funds

    (18.7 )               (18.7 )   (8.8 )
 

Sales of investments and other assets

    14.4                 14.4     5.6  
 

Sales of property, plant and equipment

    212.8     12.9     1.1         226.8      
 

Contract and portfolio acquisitions

                        (474.2 )
 

Issuance of loans receivable

                        (19.0 )
 

Repayments of loans receivable

    26.0                 26.0     31.9  
 

Decrease (increase) in restricted funds

    2.7     (5.4 )   11.0         8.3     (26.5 )
 

Other

    (2.6 )       (1.5 )       (4.1 )   (70.8 )
               

Net cash used in investing activities

    (1,060.9 )   (307.4 )   (56.0 )       (1,424.3 )   (1,826.2 )
               

Cash flows from operating activities less cash flows from investing activities

  $ (2,268.2 ) $ (109.4 ) $ (36.5 )       (2,448.3 )   (1,209.5 )
               

Financing Activities*

                                   
 

Net issuance (repayment) of debt (includes $1 billion proceeds from MidAmerican)

                          3,041.8     (93.0 )
 

Debt issuance costs

                          (50.6 )    
 

Proceeds from issuance of common stock

                          17.6     47.7  
 

Common stock dividends paid

                          (250.7 )   (226.8 )
 

Reacquisition of common stock

                          (16.2 )   (114.4 )
 

Proceeds from contract and portfolio acquisitions