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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

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

For the quarterly period ended March 31, 2011

or

 

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

For the transition period from              to             

Commission file number 000-50039

 

 

OLD DOMINION ELECTRIC COOPERATIVE

(Exact name of registrant as specified in its charter)

 

 

 

VIRGINIA   23-7048405

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. employer

identification no.)

4201 Dominion Boulevard, Glen Allen, Virginia   23060
(Address of principal executive offices)   (Zip code)

 

 

(804) 747-0592

(Registrant’s telephone number, including area code)

 

 

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

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

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

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x    Smaller reporting company   ¨

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

The Registrant is a membership corporation and has no authorized or outstanding equity securities.

 

 

 


Table of Contents

OLD DOMINION ELECTRIC COOPERATIVE

INDEX

 

     Page
Number
 

PART I. Financial Information

  

Item 1. Financial Statements

  

Condensed Consolidated Balance Sheets – March 31, 2011 (Unaudited) and December 31, 2010

     3   

Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited) – Three months ended March 31, 2011 and 2010

     4   

Condensed Consolidated Statements of Cash Flows (Unaudited) – Three Months Ended March  31, 2011 and 2010

     5   

Notes to Condensed Consolidated Financial Statements

     6   

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     13   

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     23   

Item 4. Controls and Procedures

     23   

PART II. Other Information

  

Item 1. Legal Proceedings

     24   

Item 1A. Risk Factors

     24   

Item 6. Exhibits

     25   

 

2


Table of Contents

OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

 

     March 31,
2011
    December 31,
2010
 
     (in thousands)  
     (unaudited)        

ASSETS:

    

Electric Plant:

    

Property, plant, and equipment

   $ 1,620,832      $ 1,627,643   

Less accumulated depreciation

     (666,997     (663,871
                
     953,835        963,772   

Nuclear fuel, at amortized cost

     18,858        20,872   

Construction work in progress

     33,048        52,760   
                

Net Electric Plant

     1,005,741        1,037,404   
                

Investments:

    

Nuclear decommissioning trust

     102,105        97,531   

Lease deposits

     90,006        89,355   

Unrestricted investments and other

     9,923        9,711   
                

Total Investments

     202,034        196,597   
                

Current Assets:

    

Cash and cash equivalents

     14,767        4,391   

Accounts receivable

     3,254        23,495   

Accounts receivable–deposits

     5,000        3,000   

Accounts receivable–members

     44,509        98,423   

Fuel, materials, and supplies

     35,902        35,798   

Prepayments and other

     3,110        3,438   
                

Total Current Assets

     106,542        168,545   
                

Deferred Charges:

    

Regulatory assets

     103,023        93,199   

Other

     11,547        16,690   
                

Total Deferred Charges

     114,570        109,889   
                

Total Assets

   $ 1,428,887      $ 1,512,435   
                

CAPITALIZATION AND LIABILITIES:

    

Capitalization:

    

Patronage capital

   $ 342,066      $ 339,678   

Non-controlling interest

     13,142        13,166   
                

Total Patronage capital and Non-controlling interest

     355,208        352,844   

Long-term debt

     664,798        449,798   
                

Total Capitalization

     1,020,006        802,642   
                

Current Liabilities:

    

Long-term debt due within one year

     22,917        238,917   

Notes payable

     —          7,043   

Accounts payable

     51,461        91,686   

Accounts payable–members

     49,548        76,458   

Interest rate hedge

     —          10,944   

Accrued expenses

     16,813        4,606   

Deferred energy

     33,815        45,377   
                

Total Current Liabilities

     174,554        475,031   
                

Deferred Credits and Other Liabilities

    

Asset retirement obligations

     68,762        67,876   

Obligations under long-term leases

     65,920        64,801   

Regulatory liabilities

     88,037        87,406   

Other

     11,608        14,679   
                

Total Deferred Credits and Other Liabilities

     234,327        234,762   
                

Commitments and Contingencies

     —          —     
                

Total Capitalization and Liabilities

   $ 1,428,887      $ 1,512,435   
                

The accompanying notes are an integral part of the condensed consolidated financial statements.

 

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Table of Contents

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES, AND PATRONAGE CAPITAL (UNAUDITED)

 

     Three Months Ended
March 31,
 
     2011     2010  
     (in thousands)  

Operating Revenues

   $ 232,095      $ 175,657   

Operating Expenses:

    

Fuel

     35,215        28,423   

Purchased power

     161,259        91,524   

Deferred energy

     (11,562     8,071   

Operations and maintenance

     8,276        8,898   

Administrative and general

     10,030        12,605   

Depreciation, amortization, and decommissioning

     10,331        10,334   

Amortization of regulatory asset/(liability), net

     1,084        967   

Accretion of asset retirement obligations

     885        809   

Taxes, other than income taxes

     2,227        2,081   
                

Total Operating Expenses

     217,745        163,712   
                

Operating Margin

     14,350        11,945   
                

Other expense, net

     (1,681     (442

Investment income

     1,385        1,296   

Interest charges, net

     (11,695     (10,638

Income taxes

     5        6   
                

Net Margin including Non-controlling interest

     2,364        2,167   

Non-controlling Interest

     24        24   
                

Net Margin attributable to ODEC

     2,388        2,191   

Patronage Capital - Beginning of Period

     339,678        329,520   
                

Patronage Capital - End of Period

   $ 342,066      $ 331,711   
                

The accompanying notes are an integral part of the condensed consolidated financial statements.

 

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Table of Contents

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

     Three Months Ended
March 31,
 
     2011     2010  
     (in thousands)  

Operating Activities:

    

Net Margin including Non-controlling interest

   $ 2,364      $ 2,167   

Adjustments to reconcile net margin to net cash provided by operating activities:

    

Depreciation, amortization, and decommissioning

     10,331        10,334   

Other non-cash charges

     3,025        2,499   

Amortization of lease obligations

     1,119        1,045   

Interest on lease deposits

     (651     (636

Change in current assets

     72,379        11,713   

Change in deferred energy

     (11,562     8,071   

Change in current liabilities

     (54,928     10,705   

Change in regulatory assets and liabilities

     (1,617     (5,119

Change in deferred charges and credits

     2,338        (144
                

Net Cash Provided by Operating Activities

     22,798        40,635   
                

Financing Activities:

    

Payment of long-term debt

     (1,000     —     

Draws on revolving credit facilities

     51,772        82,769   

Repayments on revolving credit facilities

     (58,815     (109,723
                

Net Cash Used for Financing Activities

     (8,043     (26,954
                

Investing Activities:

    

Increase in other investments

     (1,256     (1,078

Electric plant additions

     (4,310     (9,142

Amortization of loss on auction rate securities recorded as a regulatory asset

     1,394        —     

Gain on investments

     (207     —     
                

Net Cash Used for Investing Activities

     (4,379     (10,220
                

Net Change in Cash and Cash Equivalents

     10,376        3,461   

Cash and Cash Equivalents - Beginning of Period

     4,391        6,278   
                

Cash and Cash Equivalents - End of Period

   $ 14,767      $ 9,739   
                

The accompanying notes are an integral part of the condensed consolidated financial statements.

 

5


Table of Contents

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

1. In the opinion of our management, the accompanying unaudited condensed consolidated financial statements contain all adjustments, which include only normal recurring adjustments, necessary for a fair statement of our consolidated financial position as of March 31, 2011, and our consolidated results of operations, and cash flows for the three months ended March 31, 2011 and 2010. The consolidated results of operations for the three months ended March 31, 2011, are not necessarily indicative of the results to be expected for the entire year. These financial statements should be read in conjunction with the financial statements and notes thereto included in our 2010 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

 

2. Presentation

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative (“ODEC” or “we” or “our”) and TEC Trading, Inc. (“TEC”). We are a not-for-profit wholesale power supply cooperative, incorporated under the laws of the Commonwealth of Virginia in 1948. We have two classes of members. Our Class A members are eleven customer-owned electric distribution cooperatives engaged in the retail sale of power to member consumers located in Virginia, Delaware, and Maryland. Our sole Class B member is TEC, a taxable corporation owned by our member distribution cooperatives. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which we are the primary beneficiary. We have eliminated all intercompany balances and transactions in consolidation. The assets and liabilities and non-controlling interest of TEC are recorded at carrying value and the net assets consolidated were $13.1 million and $13.2 million at March 31, 2011, and December 31, 2010, respectively. The income taxes reported on our Condensed Consolidated Statement of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC. As TEC is 100% owned by our Class A members, its equity is presented as a non-controlling interest in our consolidated financial statements.

Our rates are set periodically by a formula that was accepted for filing by the Federal Energy Regulatory Commission (“FERC”), but are not regulated by the respective states’ public service commissions.

We comply with the Uniform System of Accounts as prescribed by FERC. In conformity with accounting principles generally accepted in the United States (“GAAP”), the accounting policies and practices applied by us in the determination of rates are also employed for financial reporting purposes.

The preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported therein. Actual results could differ from those estimates.

We do not have any other comprehensive income for the periods presented.

Certain reclassifications have been made to the prior years’ consolidated financial statements to conform to the current year’s presentation.

 

3. Fair Value Measurements

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

 

6


Table of Contents

The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2011, and December 31, 2010:

 

     March 31,
2011
     Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
     Significant
Other
Observable
Inputs

(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
 
     (in thousands)  

Nuclear decommissioning trust (1)

   $ 102,105       $ 102,105       $ —         $ —     

Unrestricted investments and other (2)(3)

     8,154         85         —           8,069   

Derivatives – renewable energy credit sales

     300         —           300         —     
                                   

Total Financial Assets

   $ 110,559       $ 102,190       $ 300       $ 8,069   
                                   

Derivatives (4)

   $ 4,178       $ 4,178       $ —         $ —     
                                   

Total Financial Liabilities

   $ 4,178       $ 4,178       $ —         $ —     
                                   
     December 31,
2010
     Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
 
     (in thousands)  

Nuclear decommissioning trust (1)

   $ 97,531       $ 97,531       $ —         $ —     

Unrestricted investments and other (2)(3)

     7,942         80         —           7,862   

Derivatives – renewable energy credit sales

     257         —           257         —     
                                   

Total Financial Assets

   $ 105,730       $ 97,611       $ 257       $ 7,862   
                                   

Derivatives – gas and power (4)

   $ 6,904       $ 6,831       $ 73       $ —     

Derivative – interest rate hedge (5)

     10,944         —           10,944         —     
                                   

Total Financial Liabilities

   $ 17,848       $ 6,831       $ 11,017       $ —     
                                   

 

(1)

For additional information about our nuclear decommissioning trust see Note 9 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

(2) 

Unrestricted investments and other includes investments that were available for sale and classified as Level 1 related to equity securities.

(3) 

Unrestricted investments and other includes investments that were classified as Level 3 and were trading securities as of March 31, 2011 and were available for sale as of December 31, 2010. As of March 31, 2011 and December 31, 2010, we had $16.8 million of principal invested in five auction rate securities and preferred stock (“ARS”). As of March 31, 2011 and December 31, 2010, the ARS had a fair value of $8.1 million and $7.9 million, respectively. For the three months ended March 31, 2011, we had an unrealized gain of $0.2 million related to the increase in the fair value of the ARS which was recorded as gain on investments in other expense, net, in our Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital. As of December 31, 2010, we had an unrealized loss of $5.6 million related to the decline in the fair value of our ARS which was recorded as a regulatory asset in accordance with Accounting for Regulated Operations. For the three months ended March 31, 2011, we amortized $1.4 million of this regulatory asset which was recorded as loss on investments in other expense, net, in our Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital. For additional information, see Notes 9 and 10 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

(4) 

Derivatives–gas and power represent natural gas futures contracts and purchased power contracts. For additional information about our derivative financial instruments, see Notes 1 and 4 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

(5) 

Derivative–interest rate hedge represents the fair value of the interest rate hedge. On May 14, 2010, we entered into an interest rate hedge with an initial notional amount of $300.0 million and a settlement rate tied to the 30-year U.S. Treasury bond. At December 31, 2010, the fair value of this interest rate hedge was a liability of $10.9 million, which is recorded on our balance sheet as a current liability. On January 21, 2011, we terminated the interest rate hedge in accordance with the terms of the transaction, resulting in a settlement payment of $3.4 million, the fair value of the hedge as of that date. The $3.4 million is recorded as a regulatory asset and will be amortized over the life of the long-term debt we issued on April 7, 2011.

 

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Table of Contents

The following table presents the net change in the assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the three months ended March 31, 2011:

 

     Three
Months
Ended

March  31,
2011
 
     (in thousands)  

Balance at January 1, 2011

   $ 7,862   

Total unrealized gain:

  

Included in gain on investments

     207   

Purchases, issuances and settlements

     —     

Transfers out of Level 3

     —     
        

Balance at March 31, 2011

   $ 8,069   
        

The unrealized gain (change in fair value) was reported in other expense, net in our Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital as of March 31, 2011.

 

4. Derivatives and Hedging:

We are exposed to market purchases of power and natural gas to meet the power supply needs of our member distribution cooperatives that are not met by our owned generation. To manage this exposure, we utilize derivative contracts. See Note 1 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

Changes in the fair value of our derivative instruments are recorded as a regulatory asset or regulatory liability. The change in these accounts is included in the operating section of our statement of cash flows.

Excluding contracts accounted for as normal purchase/normal sale, we had the following outstanding derivative instruments:

 

Commodity

  

Unit of Measure

   As of
March 31, 2011
Quantity
     As of
December 31, 2010

Quantity
 

Natural gas

   MMBTU      3,890,000         4,610,000   

Purchased power

   MWh      —           161,632   

Renewable energy credits

   REC      40,000         40,000   

Interest rate hedge

   US Dollars      —           300,000,000   

 

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Table of Contents

The fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows:

Fair Value of Derivative Instruments

 

          Fair Value  
    

Balance Sheet Location

   As of
March 31,
2011
     As of
December 31,
2010
 
     (in thousands)  

Derivatives in an asset position designated as hedging instruments:

     

Renewable energy credit sales

   Prepayments and other    $ 300       $ 257   
                    

Total derivatives in an asset position designated as hedging instruments

   $ 300       $ 257   
                    

Derivatives in a liability position designated as hedging instruments:

     

Natural gas futures contracts

   Deferred credits and other liabilities-other    $ 4,178       $ 6,831   

Purchased power contracts

   Deferred credits and other liabilities-other      —           73   

Interest rate hedge

   Interest rate hedge      —           10,944   
                    

Total derivatives in a liability position designated as hedging instruments

   $ 4,178       $ 17,848   
                    

The Effect of Derivative Instruments on the Statement of Revenues, Expenses, and Patronage Capital

for the Three Months Ended March 31, 2011 and March 31, 2010

 

Derivatives Accounted for Utilizing Regulatory Accounting

   Amount of
Gain (Loss)
Recognized within
Regulatory

Asset/Liability for
Derivatives as of
March 31,
   

Location of Gain
(Loss) Reclassified
from Regulatory
Asset/Liability into
Income

   Amount of
Gain (Loss)
Reclassified from
Regulatory

Asset/Liability into
Income for the
Three Months
Ended March 31,
 
     2011     2010          2011     2010  
     (in thousands)          (in thousands)  

Natural gas futures contracts(1)

   $ (4,257   $ (9,295   Fuel    $ (3,304   $ (1,049

Renewable energy credit sales

     300        —        Operating revenue      —          —     

Purchased power contracts

     —          —        Purchased power      483        (365
                                   

Total

   $ (3,957   $ (9,295      $ (2,821   $ (1,414
                                   

 

(1)

For 2011, includes $78.8 thousand of loss on natural gas futures contracts designated for April 2011 that were physically sold in March 2011 and the impact on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital has been deferred until April 2011. For 2010, includes $77.4 thousand of loss on natural gas futures contracts designated for April 2010 that were physically sold in March 2010 and the impact on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital was deferred until April 2010.

Our hedging activities expose us to credit-related risks. We use hedging instruments, including forwards, futures, financial transmission rights, and options, to manage our power market price risks. Because we rely substantially on the use of hedging instruments, we are exposed to the risk that counterparties will default in performance of their obligations to us. Although we assess the creditworthiness of counterparties and other credit issues related to these purchases, and we may require our counterparties to post collateral with us, defaults may still occur. Defaults may take the form of failure to physically deliver the purchased energy or failure to pay. If this occurs, we may be forced to enter into alternative contractual arrangements or purchase energy in the forward, short-term or spot markets at then-current market prices that may be more or less than the prices previously agreed upon with the defaulting counterparty.

 

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Table of Contents
5. Investments

Investments were as follows at March 31, 2011 and December 31, 2010:

 

Description

  

Designation

   Cost      Gross
Unrealized
Gains
     Gross
Unrealized
Losses
    Fair
Value
     Carrying
Value
 
          (in thousands)  

March 31, 2011

                

Nuclear decommissioning trust (1)

                

Debt securities

   Available for sale    $ 41,427       $ 1,281       $ —        $ 42,708       $ 42,708   

Equity securities

   Available for sale      49,422         11,544         (1,785     59,181         59,181   

Cash and other

   Available for sale      216         —           —          216         216   
                                              

Total Nuclear Decommissioning Trust

   $ 91,065       $ 12,825       $ (1,785   $ 102,105       $ 102,105   
                                              

Lease deposits (2)

                

Government obligations

   Held to maturity    $ 90,006       $ 160       $ (1,353   $ 88,813       $ 90,006   
                                              

Total Lease Deposits

      $ 90,006       $ 160       $ (1,353   $ 88,813       $ 90,006   
                                              

Unrestricted investments (3)

                

Debt securities

   Trading securities    $ 7,917       $ —         $ —        $ 7,917       $ 7,917   

Equity securities

   Trading securities      152         —           —          152         152   
                                              

Total Unrestricted Investments

      $ 8,069       $ —         $ —        $ 8,069       $ 8,069   
                                              

Other

                

Equity securities

   Available for sale    $ 78       $ 7       $ —        $ 85       $ 85   

Non-marketable equity investments (4)

   Equity      1,769         —           —          1,769         1,769   
                                              

Total Other

      $ 1,847       $ 7       $ —        $ 1,854       $ 1,854   
                                              
              Total Carrying Value       $ 202,034   
                      

December 31, 2010

                

Nuclear decommissioning trust (1)

                

Debt securities

   Available for sale    $ 41,049       $ 839       $ —        $ 41,888       $ 41,888   

Equity securities

   Available for sale      48,522         9,095         (2,211     55,406         55,406   

Cash and other

   Available for sale      237         —           —          237         237   
                                              

Total Nuclear Decommissioning Trust

   $ 89,808       $ 9,934       $ (2,211   $ 97,531       $ 97,531   
                                              

Lease deposits (2)

                

Government obligations

   Held to maturity    $ 89,355       $ 185       $ (405   $ 89,135       $ 89,355   
                                              

Total Lease Deposits

      $ 89,355       $ 185       $ (405   $ 89,135       $ 89,355   
                                              

Unrestricted investments(5)

                

Debt securities

   Available for sale    $ 7,723       $ —         $ —        $ 7,723       $ 7,723   

Equity securities

   Available for sale      139         —           —          139         139   
                                              

Total Unrestricted Investments

      $ 7,862       $ —         $ —        $ 7,862       $ 7,862   
                                              

Other

                

Equity securities

   Available for sale    $ 78       $ 2       $ —        $ 80       $ 80   

Non-marketable equity investments (4)

   Equity      1,769         —           —          1,769         1,769   
                                              

Total Other

      $ 1,847       $ 2       $ —        $ 1,849       $ 1,849   
                                              
              Total Carrying Value       $ 196,597   
                      

 

(1) 

Investments in the nuclear decommissioning trust are restricted for the use of funding our share of the asset retirement obligations of the future decommissioning of North Anna. See Note 3 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K. Realized and unrealized gains and losses related to assets held in the nuclear decommissioning trust are deferred as a regulatory asset or liability.

(2) 

Investments in lease deposits are restricted for the use of funding our future lease obligations. See Note 8 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

(3) 

Effective January 1, 2011, we began accounting for ARS as trading securities.

(4) 

We believe the carrying value approximates fair value for our equity investments.

(5) 

The cost represents investments in ARS with a principal value of $16.8 million. The cost has been written down by $9.0 million due to the fair value adjustment. During 2010, we amortized $3.4 million of the regulatory asset as loss on investment and we have deferred the remaining balance of $5.6 million as a regulatory asset in accordance with Accounting for Regulated Operations. See Note 10 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

 

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Our investments by classification at March 31, 2011 and December 31, 2010, were as follows:

 

     March 31, 2011      December 31, 2010  

Description

   Cost      Carrying
Value
     Cost      Carrying
Value
 
     (in thousands)  

Available for sale

   $ 91,143       $ 102,190       $ 97,748       $ 105,473   

Held to maturity

     90,006         90,006         89,355         89,355   

Trading securities

     8,069         8,069         —           —     

Equity

     1,769         1,769         1,769         1,769   
                                   
   $ 190,987       $ 202,034       $ 188,872       $ 196,597   
                                   

 

6. Other

Indebtedness

On January 24, 2011, our Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, was terminated as the result of the redemption of $1.0 million of outstanding obligations issued prior to September 1, 2001. Following the redemption of these obligations, the Amended and Restated Indenture, dated as of September 1, 2001 (the “2001 Indenture”), became effective.

On January 26, 2011, we entered into the Second Amended and Restated Indenture of Mortgage and Deed of Trust (the “New Indenture”) with Branch Banking and Trust Company, as trustee, and terminated the 2001 Indenture. The New Indenture subjects substantially all of our real property and tangible personal property and some of our intangible personal property to a lien in favor of the trustee. The obligations outstanding under the New Indenture are secured equally and ratably with all of our other obligations issued under the indenture, including pre-existing obligations issued under the indenture, as previously in effect.

In May 2010, we entered into an interest rate hedge transaction to mitigate a portion of the exposure to fluctuations in long-term interest rates related to the issuance of long-term debt and the refinancing of our $215.0 million 2001 Series A Bonds. On January 21, 2011, we terminated the interest rate hedge in accordance with the terms of the transaction, resulting in a settlement payment of $3.4 million, the fair value of the hedge as of that date. On April 7, 2011, we issued $350.0 million of first mortgage bonds in a private placement. The bonds consist of $90.0 million of 4.83% First Mortgage Bonds, 2011 Series A due December 1, 2040; $165.0 million of 5.54% First Mortgage Bonds, 2011 Series B due December 1, 2040; and $95.0 million of 5.54% First Mortgage Bonds, 2011 Series C due December 1, 2050. The $3.4 million settlement payment related to the interest rate hedge transaction was recorded as a regulatory asset and will be amortized over the life of the long-term debt we issued on April 7, 2011. The proceeds of the issuances will be used to repay our $215.0 million First Mortgage Bonds, 2001 Series A due June 1, 2011 and for general corporate purposes.

Decision not to participate in an additional unit at the North Anna Nuclear Power Station (“North Anna”)

In February 2011, we made the determination not to participate in an additional nuclear-powered generating unit at North Anna as discussed in a press release we issued on February 28, 2011. We are currently working with Virginia Electric and Power Company (“Virginia Power”) on the logistics of our withdrawal as a participant in the project. As of December 31, 2010, we had $21.3 million of construction work in progress related to the potential additional unit at North Anna and had incurred approximately $1.8 million in financing-related costs that were included in deferred charges–other. Through February 2011, we had recorded $23.2 million of construction work in progress related to the potential additional unit at North Anna. As of March 31, 2011, we established a regulatory asset and reclassified the $23.2 million of construction work in progress to the regulatory asset due to the uncertainty of the recovery of these costs from Virginia Power. The $1.8 million in financing-related costs were expensed in the first quarter of 2011 as administrative and general expense. We will continue to incur costs related to the additional unit at North Anna until our withdrawal is finalized. As of March 31, 2011, we have incurred approximately $1.3 million of additional costs since our decision not to participate in the additional unit at North Anna and these costs have been recorded as accounts receivable, as we expect reimbursement from Virginia Power upon the finalization of our withdrawal. These amounts are not expected to have a material impact on our financial position or results of operations due to our ability to collect such amounts through rates charged to our member distribution cooperatives.

 

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7. Subsequent Event

On April 13, 2011, our Board of Directors approved an increase to our fuel factor adjustment rate, resulting in an increase to our total energy rate of approximately 0.6%, effective April 1, 2011. This increase was implemented due to the changes in our realized as well as projected energy costs.

 

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OLD DOMINION ELECTRIC COOPERATIVE

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Caution Regarding Forward-Looking Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward looking statements regarding matters that could have an impact on our business, financial condition, and future operations. These statements, based on our expectations and estimates, are not guarantees of future performance and are subject to risks, uncertainties, and other factors that could cause actual results to differ materially from those expressed in the forward looking statements. These risks, uncertainties, and other factors include, but are not limited to, general business conditions, demand for energy, federal and state legislative and regulatory actions and legal and administrative proceedings, changes in and compliance with environmental laws and policies, general credit and capital market conditions, weather conditions, the cost of commodities used in our industry, and unanticipated changes in operating expenses and capital expenditures. Our actual results may vary materially from those discussed in the forward looking statements as a result of these and other factors. Any forward looking statement speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward looking statement or statements to reflect events or circumstances after the date on which the statement is made even if new information becomes available or other events occur in the future.

Critical Accounting Policies

As of March 31, 2011, there have been no significant changes in our critical accounting policies as disclosed in our 2010 Annual Report on Form 10-K. These policies include the accounting for rate regulation, deferred energy, margin stabilization plan, accounting for asset retirement obligations, and accounting for derivative contracts.

Basis of Presentation

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative (“ODEC” or “we” or “our”) and TEC Trading, Inc. (“TEC”). See Note 2—Notes to Condensed Consolidated Financial Statements in Part 1, Item 1.

Overview

We are a not-for-profit power supply cooperative owned entirely by our eleven Class A member distribution cooperatives and a Class B member, TEC. We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through a portfolio of resources including generating facilities, long-term and short-term physically-delivered forward power purchase contracts, and spot market purchases.

Our financial results for the three months ended March 31, 2011, were significantly impacted by:

 

   

Acquisition of additional service territory by two of our member distribution cooperatives on June 1, 2010;

 

   

Our decision not to participate in an additional nuclear-powered generating unit at the North Anna Nuclear Power Station (“North Anna”); and

 

   

Termination of an interest rate hedge transaction.

Factors Affecting Results

Formulary Rate

Our power sales are comprised of two power products – energy and capacity (also referred to as demand). Energy is the physical electricity delivered through transmission and distribution facilities to customers. We must have sufficient committed energy available to us for delivery to our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy is referred to as capacity.

 

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The rates we charge our member distribution cooperatives for sales of energy and capacity are determined by a formulary rate accepted by the Federal Energy Regulatory Commission (“FERC”) which is intended to permit collection of revenues which will equal the sum of:

 

   

all of our costs and expenses;

 

   

20% of our total interest charges; and

 

   

additional equity contributions approved by our board of directors.

The formulary rate has three main components: a demand rate, a base energy rate and a fuel factor adjustment rate. The formulary rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited minor exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval. For further discussion on our formulary rate, see Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results – Formulary Rate in our 2010 Annual Report on Form 10-K.

Member Distribution Cooperatives–Acquisition of Additional Service Territory

On June 1, 2010, two of our member distribution cooperatives, Rappahannock Electric Cooperative (“REC”) and Shenandoah Valley Electric Cooperative (“SVEC”), acquired the distribution assets and right to provide electric distribution services to approximately 102,000 customers (meters) previously owned by The Potomac Edison Company in Virginia (“Potomac Edison”). On December 31, 2010, SVEC sold the distribution assets and rights to provide electric distribution services to approximately 2,500 customers (meters) in West Virginia. We estimate that in the aggregate, REC’s and SVEC’s acquisitions, net of the disposition noted above, will increase our megawatt hour (“MWh”) and megawatt (“MW”) sales to our member distribution cooperatives by approximately 35% to 40% on an annualized basis.

In accordance with the wholesale power contracts between ODEC and its member distribution cooperatives, ODEC is serving the additional power requirements resulting from REC’s and SVEC’s acquisitions. We were not a party to this transaction; however, we assumed power supply contracts previously entered into by Potomac Edison for the service territory to serve the load of these customers. These contracts expire on June 30, 2011. A valuation of these contracts was performed as of June 1, 2010, and the value of the contracts approximated a fair value of zero.

In accordance with our load acquisition policy, we are paying a transition fee to REC and to SVEC that represents a portion of the projected power cost savings related to these acquisitions. The aggregate transition fee totals approximately $66.7 million; approximately $3.2 million was recorded for the three months ended March 31, 2011, and approximately $10.6 million of the $66.7 million has been paid to date. The transition fee is reflected as a credit on the monthly power invoices to REC and SVEC over 48 months as a reduction in sales and is being collected from our member distribution cooperatives through our formulary rate.

 

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Power Supply Resources

We provide power to our members through a combination of our interests in the Clover Power Station (“Clover”), a coal-fired generating facility; North Anna; our three combustion turbine facilities - Louisa, Marsh Run, and Rock Springs; distributed generation facilities; and physically-delivered forward power purchase contracts and spot purchases of power in the open market. Our power supply resources for the three months ended March 31, 2011and 2010, were as follows:

 

     Three Months Ended March 31,  
     2011     2010  
     (in MWh and percentages)  

Generated:

          

Clover

     788,875         22.0      860,424         34.2 

North Anna

     475,314         13.3        429,729         17.1   

Louisa

     11,421         0.3        9,777         0.4   

Marsh Run

     26,613         0.7        12,792         0.5   

Rock Springs

     —           —          1,415         —     

Distributed Generation

     2         —          2         —     
                                  

Total Generated

     1,302,225         36.3        1,314,139         52.2   

Purchased:

          

Other than renewable

     2,147,279         59.8        1,166,842         46.4   

Renewable (1)

     138,544         3.9        34,291         1.4   
                                  

Total Purchased

     2,285,823         63.7        1,201,133         47.8   
                                  

Total Available Energy

     3,588,048         100.0      2,515,272         100.0 
                                  

 

(1) 

Related to our contracts from renewable facilities for which we purchase renewable energy credits.

Generating Facilities

Our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of our baseload generating facilities, Clover and North Anna. Baseload generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as Louisa, Marsh Run and Rock Springs. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility; however, they are more expensive to operate and, as a result, we operate them only when the market price of energy makes their operation economical or when their operation is required by PJM Interconnection, LLC (“PJM”) for system reliability purposes. For further discussion on PJM, see Item 1 Business – Power Supply Resources – PJM in our 2010 Annual Report on Form 10-K. Owners of power plants incur the fixed costs of these facilities whether or not the units operate.

Our generating facilities are under dispatch control of PJM. Typically, nuclear facilities are almost always dispatched and coal-fired facilities are dispatched based upon economic factors including the market price of energy. The operational availability of Clover for the three months ended March 31, 2011 and 2010, was as follows:

 

     Clover
Three Months  Ended
March 31,
 
     2011     2010  

Unit 1

     100.0      99.5 

Unit 2

     96.3        99.9   

Combined

     98.2        99.7   

 

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The output of Clover and North Anna for the three months ended March 31, 2011 and 2010, as a percentage of the maximum net dependable capacity rating of the facilities, was as follows:

 

     Clover     North Anna  
     Three Months Ended
March 31,
    Three Months Ended
March 31,
 
     2011     2010     2011     2010  

Unit 1

     86.1     91.8     101.5     101.4

Unit 2

     82.5        91.6        102.7        88.6   

Combined

     84.3        91.7        102.1        95.0   

The scheduled maintenance outages and unscheduled outages for Clover for the three months ended March 31, 2011 and 2010, were as follows:

 

     Scheduled Outages      Unscheduled Outages  
     Three Months Ended
March 31,
     Three Months Ended
March 31,
 
     2011      2010      2011      2010  
     (in days)      (in days)  

Unit 1

     —           —           —           0.1   

Unit 2

     —           —           3.4         0.4   
                                   

Combined

     —           —           3.4         0.5   
                                   

The scheduled maintenance and refueling outages and unscheduled outages for North Anna for the three months ended March 31, 2011 and 2010, were as follows:

 

     Scheduled Outages      Unscheduled Outages  
     Three Months Ended
March  31,
     Three Months Ended
March  31,
 
     2011      2010      2011      2010  
     (in days)      (in days)  

Unit 1

     —           —           —           —     

Unit 2

     —           11.0         —           —     
                                   

Combined

     —           11.0         —           —     
                                   

During the three months ended March 31, 2011 and 2010, the operational availability of our Louisa, Marsh Run, and Rock Springs combustion turbine facilities was as follows:

 

     Three Months Ended
March 31,
 
     2011     2010  

Louisa

     98.2     100.0

Marsh Run

     96.1        100.0   

Rock Springs

     100.0        99.1   

Sales to Member Distribution Cooperatives

Revenues from sales to our member distribution cooperatives are a function of our formulary rate for sales of power to our member distribution cooperatives and our member distribution cooperatives’ consumers’ requirements for power. Our formulary rate is based on our cost of service in meeting these requirements. See “—Factors Affecting Results—Formulary Rate.”

Sales to TEC

In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which ODEC is the primary beneficiary. The financial statements of TEC are consolidated and the inter-company balances are eliminated in consolidation. TEC’s sales to third parties are reflected as non-member revenues.

 

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Sales to Non-Members

Sales to non-members consist of sales of excess purchased and generated energy. We primarily sell excess energy to PJM at the prevailing market price at the time of sale. Excess energy is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, as well as changes in market conditions.

Results of Operations

Operating Revenues

Our operating revenues are derived from power sales to our member distribution cooperatives and non-members. Our operating revenues by type of purchaser for the three months ended March 31, 2011 and 2010, were as follows:

 

     Three Months Ended
March 31,
 
     2011      2010  
     (in thousands)  

Revenues from sales to:

     

Member distribution cooperatives

     

Base energy revenues

   $ 59,390       $ 44,213   

Fuel factor adjustment revenues

     87,570         68,996   
                 

Total energy revenues

     146,960         113,209   

Demand (capacity) revenues

     78,971         61,827   
                 

Total revenues from sales to member distribution cooperatives

     225,931         175,036   

Non-members

     6,164         621   
                 

Total operating revenues

   $ 232,095       $ 175,657   
                 

Average costs to member distribution cooperatives (per MWh)

   $ 67.44       $ 70.70   

Our energy sales in megawatt hours (“MWh”) to our member distribution cooperatives and non-members for the three months ended March 31, 2011 and 2010, were as follows:

 

     Energy and Demand
Sales Volume
Three Months Ended
March 31,
 
     2011      2010  
     (in MWh)  

Energy sales to:

     

Member distribution cooperatives

     3,350,082         2,475,681   

Non-members

     175,901         19,404   
                 

Total energy sales

     3,525,983         2,495,085   
                 
     (in MW)  

Demand sales to Member distribution cooperatives

     6,642         4,821   
                 

In 2011, our energy sales in MWh and demand sales in MW to our member distribution cooperatives were 35.3% and 37.8% higher, respectively, as compared to 2010, primarily as a result of the service territory acquisition by two of our member distribution cooperatives as of June 1, 2010. The additional service territory increased our energy and demand sales to our member distribution cooperatives approximately 34.5% and 35.1%, respectively, in 2011.

In 2011, our energy sales in MWh to non-members were 806.5% higher as compared to 2010. Sales to non-members consist of sales of excess purchased and generated energy.

In 2011, total revenues from sales to our member distribution cooperatives increased $50.9 million, or 29.1%, as compared to 2010. The increase in total revenues is related to the additional service territory, partially offset by a 4.1% decrease in our total energy rate (our total energy rate includes our base energy rate and our fuel factor adjustment rate).

 

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In 2011, the capacity costs we incurred, and thus the capacity-related revenues we reflected, were 27.7% higher as compared to 2010, primarily due an increase in the amount of capacity we purchased. The increased amount of purchased capacity was primarily related to the additional service territory.

In 2011, our average cost per MWh to member distribution cooperatives decreased $3.26 per MWh, or 4.6%, as compared to 2010, as a result of the decrease in our total energy rate and a greater increase in the MWh volume as compared to the increase in demand revenues.

Non-member revenue increased $5.5 million, or 892.6%, in 2011 as compared to 2010 due to an 806.5% increase in the volume of excess energy sales and an increase in the average price.

Operating Expenses

The following is a summary of the components of our operating expenses for the three months ended March 31, 2011 and 2010:

 

     Three Months Ended
March 31,
 
     2011     2010  
     (in thousands)  

Fuel

   $ 35,215      $ 28,423   

Purchased power

     161,259        91,524   

Deferred energy

     (11,562     8,071   

Operations and maintenance

     8,276        8,898   

Administrative and general

     10,030        12,605   

Depreciation, amortization and decommissioning

     10,331        10,334   

Amortization of regulatory asset/(liability), net

     1,084        967   

Accretion of asset retirement obligations

     885        809   

Taxes, other than income taxes

     2,227        2,081   
                

Total Operating Expenses

   $ 217,745      $ 163,712   
                

Our operating expenses are comprised of the costs that we incur to generate and purchase power to meet the needs of our member distribution cooperatives, and the costs associated with any sales of power to non-members. Our energy costs generally are variable and include fuel expense as well as the energy portion of our purchased power expense. Our capacity or demand costs generally are fixed and include depreciation, amortization, and decommissioning expenses, as well as the capacity portion of our purchased power expense. Additionally, all non-operating expenses and income items, including interest charges and investment income, are components of our capacity costs. See “Factors Affecting Results—Formulary Rate.”

In 2011, total operating expenses increased $54.0 million, or 33.0%, as compared to 2010, primarily due to increases in purchased power and fuel expenses partially offset by the decrease in deferred energy expense.

 

   

Purchased power expense, which includes the cost of purchased energy and capacity, increased $69.7 million, or 76.2%, due to a 90.3% increase in the volume of purchased power primarily due to the acquisition of the additional service territory partially offset by a 7.4% decrease in the average cost of purchased power.

 

   

Fuel expense increased $6.8 million, or 23.9%, primarily due to the increase in the average price of natural gas and coal.

 

   

Deferred energy expense decreased $19.6 million, or 243.3%. During 2011, we under-collected $11.6 million in energy costs; whereas in 2010, we over-collected $8.1 million in energy costs. Our deferred energy balance was a net over-collection of energy costs of $45.4 million at December 31, 2010, as compared to a net over-collection of energy costs of $33.8 million at March 31, 2011.

 

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Other Items

Amortization of Loss on Auction Rate Securities Recorded as a Regulatory Asset

As of December 31, 2010, we had an unrealized loss of $5.6 million related to the decline in the fair value of five securities, all of which were originally issued as auction rate securities and one of which has converted to preferred stock (“ARS”), which was recorded as a regulatory asset in accordance with Accounting for Regulated Operations. In 2011, we amortized $1.4 million of this regulatory asset which was recorded as loss on investments. See “Liquidity and Capital Resources—Auction Rate Securities and Related Preferred Stock” below.

Gain on Investment

In 2011, we had a gain of $0.2 million related to the increase in the fair value of the ARS which was recorded as gain on investments. See “Liquidity and Capital Resources—Auction Rate Securities and Related Preferred Stock” below.

Investment Income

Investment income increased in 2011 by $0.1 million, or 6.9%, primarily due to slightly higher investment balances.

Interest Charges, Net

The primary factors affecting our interest charges, net are scheduled payments of principal on our indebtedness, interest related to the Norfolk Southern Railway Company (“Norfolk Southern”) settlement, interest charges related to our credit facilities, and capitalized interest. We settled our dispute with Norfolk Southern in 2009. The major components of interest charges, net for the three months ended March 31, 2011 and 2010, were as follows:

 

     Three Months Ended
March 31,
 
     2011     2010  
     (in thousands)  

Interest expense on long-term debt

   $ (11,248   $ (11,579

Interest charges related to Norfolk Southern

     —          1,261   

Other

     (692     (632
                

Total Interest Charges

     (11,940     (10,950

Allowance for borrowed funds used during construction

     245        312   
                

Interest Charges, net

   $ (11,695   $ (10,638
                

In 2011, interest charges, net increased $1.1 million, or 9.9%, as compared to 2010. In 2010, interest charges, net were lower due to the amortization of the regulatory liability related to settlement of our dispute with Norfolk Southern. This was fully amortized by December 31, 2010.

Net Margin

In 2011, our net margin, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, increased $0.2 million, or 9.0%, as compared to 2010 due to higher interest charges.

Financial Condition

The principal changes in our financial condition from December 31, 2010 to March 31, 2011, were caused by decreases in long-term debt due within one year (offset by increases in long-term debt), accounts receivable–members, accounts payable, accounts payable–members, construction work in progress, accounts receivable, deferred energy, and interest rate hedge, partially offset by increases in long-term debt, accrued expenses and regulatory assets.

 

   

Long-term debt due within one year decreased $216.0 million primarily due to the reclassification of the $215.0 million maturity of our 2001 Series A Bonds on June 1, 2011 from long-term debt due within one year to long-term debt. On April 7, 2011, we issued $350.0 million of debt which will provide funding to repay the maturing debt.

 

   

Accounts receivable–members decreased $53.9 million as a result of lower sales to members in March 2011 as compared to December 2010 and a $3.7 million decrease in member extension balances.

 

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Accounts payable decreased $40.2 million due to decreased natural gas and purchased power requirements in March 2011 as compared to December 2010.

 

   

Accounts payable–members decreased $26.9 million due to the $16.2 million decrease in member prepayments and the $10.7 million decrease in the margin stabilization adjustment as compared to December 2010.

 

   

Accounts receivable decreased $20.2 million related to decreased sales of excess power to non-members in March 2011 as compared to December 2010.

 

   

Construction work in progress decreased $19.7 million due to the reclassification of $23.2 million of costs, of which $1.9 million was incurred in 2011, to a regulatory asset. See “Decision not to participate in an additional unit at North Anna” below.

 

   

Deferred energy decreased $11.6 million as a result of the under-collection of our energy costs in 2011.

 

   

Interest rate hedge decreased $10.9 million. On January 21, 2011, we terminated our interest rate hedge in accordance with the terms of the transaction. See “Liquidity and Capital Resources–Interest Rate Hedge” below.

 

   

Accrued expenses increased $12.2 million primarily as a result of increased interest payable related to our long-term debt.

 

   

Regulatory assets increased $9.8 million as a result of the establishment of a $23.2 million regulatory asset to recover construction work in progress we incurred prior to our decision not to participate in the development and ownership of the additional nuclear unit at North Anna, partially offset by the decrease of $10.9 million related to the termination of the interest rate hedge transaction. See “Liquidity and Capital Resources–Interest Rate Hedge” below.

Decision Not to Participate in an Additional Unit at North Anna

In February 2011, we made the determination not to participate in an additional nuclear-powered generating unit at North Anna as discussed in a press release we issued on February 28, 2011. We are currently working with Virginia Electric and Power Company (“Virginia Power”) on the logistics of our withdrawal as a participant in the project. As of December 31, 2010, we had $21.3 million of construction work in progress related to the potential additional unit at North Anna and had incurred approximately $1.8 million in financing-related costs that were included in deferred charges–other. Through February 2011, we had recorded $23.2 million of construction work in progress related to the potential additional unit at North Anna. As of March 31, 2011, we established a regulatory asset and reclassified the $23.2 million of construction work in progress to the regulatory asset due to the uncertainty of the recovery of these costs from Virginia Power. The $1.8 million in financing-related costs were expensed in the first quarter of 2011 as administrative and general expense. We will continue to incur costs related to the additional unit at North Anna until our withdrawal is finalized. As of March 31, 2011, we have incurred approximately $1.3 million of additional costs since our decision not to participate in the additional unit at North Anna and these costs have been recorded as accounts receivable, as we expect reimbursement from Virginia Power upon the finalization of our withdrawal. These amounts are not expected to have a material impact on our financial position or results of operations due to our ability to collect such amounts through rates charged to our member distribution cooperatives.

Liquidity and Capital Resources

Sources

Cash generated by our operations and periodically, borrowings under our credit facilities provide our sources of liquidity and capital. In the past, we have also issued long-term indebtedness in the capital markets.

Operations

Historically, our operating cash flows generally have been sufficient to meet our short- and long-term capital expenditures related to our existing generating facilities, our debt service requirements, and our ordinary business operations. During the first three months of 2011 and 2010, our operating activities provided cash flows of $22.8 million and $40.6 million, respectively. Operating activities in 2011 were primarily impacted by the following:

 

   

Current assets changed $72.4 million primarily due to the $53.9 million decrease in accounts receivable–members and the $20.2 million decrease in accounts receivable.

 

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Current liabilities changed by $54.9 million primarily due to the $40.2 million decrease in accounts payable and the $26.9 million decrease in accounts payable–members, partially offset by the $12.2 million increase in accrued expenses.

Auction Rate Securities and Related Preferred Stock

As of March 31, 2011 and December 31, 2010, we had $16.8 million of principal invested in ARS. The estimated fair value of our ARS was $8.1 million and $7.9 million as of March 31, 2011 and December 31, 2010, respectively.

ARS pay variable rates of interest which reset periodically in connection with the auction to purchase or sell the securities. Generally, the periodic auctions provide owners of ARS the opportunity to liquidate their investment at par value. In the event auctions are not fully subscribed, which auction agents describe as failed auctions, these securities are typically illiquid, as is the case with our ARS.

In the absence of liquidity provided by auctions, we rely on a third party to establish the estimated fair values of our ARS. The estimated fair values of our ARS are determined with a valuation model that utilizes expected cash flow streams, assessments of credit quality, discount rates, and overall credit market liquidity, among other things.

The following represents changes in our ARS for the three months ended March 31, 2011:

 

     Principal      Fair
Value
     Regulatory
Asset (3)(4)
    Realized
Loss
     Unrealized
Gain
 
     (in thousands)  

ARS at December 31, 2010 (1)

   $ 16,820       $ 7,862       $ 5,575      $ —         $ —     

Change in fair value (2)

     —           207         —          —           (207

Amortization of regulatory asset (3)(4)

     —           —           (1,394     1,394         —     
                                           

ARS at March 31, 2011 (1)(2)(3)

   $ 16,820       $ 8,069       $ 4,181      $ 1,394       $ (207
                                           

 

(1) 

Recorded on our Condensed Consolidated Balance Sheet in investments–unrestricted investments and other, and classified as available for sale at December 31, 2010 and as trading securities at March 31, 2011.

(2) 

Beginning in 2011, the change in fair value is recorded in other expense, net in our Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital.

(3) 

Recorded as realized loss in other expense, net in our Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital.

(4) 

Amortization of regulatory asset began in 2010 and the remaining balance of the regulatory asset will be amortized and recorded as a realized loss in 2011.

We accounted for the difference between the principal of our ARS and the estimated fair value of our ARS as a regulatory asset in accordance with Accounting for Regulated Operations through 2010. In 2010, we began amortizing the regulatory asset which resulted in a recognized loss of $3.4 million. The remaining balance in the regulatory asset, $5.6 million, will be amortized in 2011 and $1.4 million was amortized during the three months ended March 31, 2011. Beginning in 2011, we classified the ARS as trading securities and began recording the change in fair value in other expense, net in our Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital. The estimated fair value of our ARS are included in investments–unrestricted investments and other on our Consolidated Balance Sheet and are classified as trading securities.

Credit Facilities

In addition to liquidity from our operating activities, we currently maintain a total of $410.0 million in unsecured committed credit facilities to cover our short-term and medium-term funding needs. At March 31, 2011, we did not have any short-term borrowings outstanding and at December 31, 2010, we had $7.0 million of short-term borrowings outstanding. We expect that we will renew the majority of these credit facilities as they expire.

 

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As of March 31, 2011, our credit facilities were as follows:

 

Lender

   Amount     

Expiration Date

     (in millions)       

Branch Banking and Trust Company

   $ 25.0       May 31, 2011 (1)

National Rural Utilities Cooperative Finance Corp.

     75.0       April 15, 2012

JPMorgan Chase Bank, National Association

     70.0       June 1, 2012

Wells Fargo Bank, N.A.

     70.0       August 31, 2012

CoBank, ACB

     100.0       June 18, 2013

Bank of America, N.A.

     70.0       November 5, 2013
           
   $ 410.0      
           

 

(1) 

We are currently in the process of renewing this facility.

Financings

We fund the portion of our capital expenditures that we are not able to supply from operations through financings in the debt capital markets. Since 1983, these capital expenditures have consisted primarily of the costs related to the acquisition of our interest in North Anna, our share of the costs to construct Clover, and the development and construction of our three combustion turbine facilities. In the second quarter of 2011, we issued $350.0 million of long-term debt to refinance the $215.0 million of Series A Bonds due June 1, 2011 and for general corporate purposes.

On January 24, 2011, our Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, was terminated as the result of the redemption of $1.0 million of outstanding obligations issued prior to September 1, 2001. Following the redemption of these obligations, the Amended and Restated Indenture, dated as of September 1, 2001 (the “2001 Indenture”), became effective.

On January 26, 2011, we entered into the Second Amended and Restated Indenture of Mortgage and Deed of Trust (the “New Indenture”) with Branch Banking and Trust Company, as trustee, and terminated the 2001 Indenture. The New Indenture subjects substantially all of our real property and tangible personal property and some of our intangible personal property to a lien in favor of the trustee. The obligations outstanding under the New Indenture are secured equally and ratably with all of our other obligations issued under the indenture, including pre-existing obligations issued under the indenture, as previously in effect.

Uses

Our uses of liquidity and capital relate to funding our working capital needs, investment activities and financing activities. Substantially all of our investment activities relate to capital expenditures in connection with our generating facilities. We expect that cash flows from our operations, our existing credit facilities, and potential long-term borrowings will be sufficient to meet our currently anticipated operational and capital requirements.

Interest Rate Hedge

We are exposed to fluctuations in long-term interest rates related to the issuance of long-term debt and the refinancing of our $215.0 million 2001 Series A Bonds. To mitigate a portion of this exposure, on May 14, 2010, we entered into an interest rate hedge. At December 31, 2010, the fair value of this interest rate hedge was a $10.9 million liability, which was recorded as a current liability on our balance sheet. On January 21, 2011, we terminated the interest rate hedge in accordance with the terms of the transaction, resulting in a settlement payment of $3.4 million, the fair value of the hedge as of that date. The settlement payment will be amortized over the life of the long-term debt we issued on April 7, 2011.

 

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ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the first quarter of 2011.

ITEM 4. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, our management, including the President and Chief Executive Officer, and Senior Vice President and Chief Financial Officer conducted an evaluation of the effectiveness of our disclosure controls and procedures. Based upon that evaluation, the President and Chief Executive Officer, and Senior Vice President and Chief Financial Officer concluded that our disclosure controls and procedures are effective in ensuring that all material information required to be filed in this report has been made known to them in a timely matter. We have established a Disclosure Assessment Committee comprised of members from senior and middle management to assist in this evaluation. There have been no material changes in our internal controls over financial reporting or in other factors that could significantly affect such controls during the past fiscal quarter.

 

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OLD DOMINION ELECTRIC COOPERATIVE

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Other Matters

Other than legal proceedings arising out of the ordinary course of business, which management believes will not have a material adverse impact on our results of operations or financial condition, there is no other litigation pending or threatened against us.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in Part I, Item 1A of our 2010 Annual Report on Form 10-K, which could affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

 

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ITEM 6. EXHIBITS

 

31.1    Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)
31.2    Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)
32.1    Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350
32.2    Certification of the Chief Financial Officer pursuant to 18 U.S.C. § 1350

 

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

  OLD DOMINION ELECTRIC COOPERATIVE
  Registrant
Date: May 11, 2011  

/s/ Robert L. Kees

  Robert L. Kees
  Senior Vice President and Chief Financial Officer
  (Principal financial officer)

 

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EXHIBIT INDEX

 

Exhibit
Number

  

Description of Exhibit

31.1    Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)
31.2    Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)
32.1    Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350
32.2    Certification of the Chief Financial Officer pursuant to 18 U.S.C. § 1350

 

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