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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 September 30, 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  x    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.

 

 

 

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OLD DOMINION ELECTRIC COOPERATIVE

INDEX

 

		Page Number
PART I. Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – September 30, 2011 (Unaudited) and December 31, 2010			3
Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (Unaudited) – Three and Nine Months ended September 30, 2011 and 2010			4
Condensed Consolidated Statements of Cash Flows (Unaudited) – Nine Months Ended September  30, 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 5. Other Information			24
Item 6. Exhibits			25

 

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OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM  1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

 

		September 30, 2011				December 31, 2010
		(in thousands)
		(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment		$	1,635,726			$	1,627,643
Less accumulated depreciation			(687,220	)			(663,871	)
			948,506				963,772
Nuclear fuel, at amortized cost			15,686				20,872
Construction work in progress			39,753				52,760
Net Electric Plant			1,003,945				1,037,404
Investments:
Nuclear decommissioning trust			94,847				97,531
Lease deposits			91,049				89,355
Unrestricted investments and other			10,759				9,711
Total Investments			196,655				196,597
Current Assets:
Cash and cash equivalents			149,502				4,391
Accounts receivable			15,633				23,495
Accounts receivable–deposits			6,400				3,000
Accounts receivable–members			57,859				98,423
Fuel, materials, and supplies			44,379				35,798
Prepayments and other			2,213				3,438
Total Current Assets			275,986				168,545
Deferred Charges:
Regulatory assets			97,095				93,199
Other			11,827				16,690
Total Deferred Charges			108,922				109,889
Total Assets		$	1,585,508			$	1,512,435
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital		$	347,791			$	339,678
Non-controlling interest			13,120				13,166
Total Patronage capital and Non-controlling interest			360,911				352,844
Long-term debt			794,420				449,798
Total Capitalization			1,155,331				802,642
Current Liabilities:
Long-term debt due within one year			28,292				238,917
Revolving credit facilities			—				7,043
Accounts payable			67,838				91,686
Accounts payable–members			59,626				76,458
Interest rate hedge			—				10,944
Accrued expenses			19,955				4,606
Deferred energy			32,493				45,377
Total Current Liabilities			208,204				475,031
Deferred Credits and Other Liabilities:
Asset retirement obligations			70,532				67,876
Obligations under long-term leases			68,164				64,801
Regulatory liabilities			72,895				87,406
Other			10,382				14,679
Total Deferred Credits and Other Liabilities			221,973				234,762
Commitments and Contingencies			—				—
Total Capitalization and Liabilities		$	1,585,508			$	1,512,435

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

 

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES, AND PATRONAGE CAPITAL (UNAUDITED)

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(in thousands)								(in thousands)
Operating Revenues		$	229,909			$	245,430			$	681,056			$	605,150
Operating Expenses:
Fuel			28,573				51,136				90,689				119,388
Purchased power			149,258				155,610				455,542				339,567
Deferred energy			28				(8,308	)			(12,884	)			5,443
Operations and maintenance			12,305				10,546				28,992				28,907
Administrative and general			9,142				9,409				29,092				32,198
Depreciation and amortization			10,382				10,373				31,082				31,050
Amortization of regulatory asset/(liability), net			819				761				3,030				2,460
Accretion of asset retirement obligations			886				841				2,656				2,492
Taxes, other than income taxes			1,917				2,103				6,335				6,413
Total Operating Expenses			213,310				232,471				634,534				567,918
Operating Margin			16,599				12,959				46,522				37,232
Other income (expense), net			(1,865	)			(446	)			(2,412	)			(1,317	)
Investment income			1,060				1,067				3,873				3,414
Interest charges, net			(13,132	)			(10,746	)			(39,928	)			(31,954	)
Income taxes			2				(7	)			12				—
Net Margin including Non-controlling Interest			2,664				2,827				8,067				7,375
Non-controlling Interest			6				(28	)			46				(2	)
Net Margin attributable to ODEC			2,670				2,799				8,113				7,373
Patronage Capital - Beginning of Period			345,121				334,094				339,678				329,520
Patronage Capital - End of Period		$	347,791			$	336,893			$	347,791			$	336,893

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

 

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

		Nine Months Ended September 30,
		2011				2010
		(in thousands)
Operating Activities:
Net Margin including Non-controlling Interest		$	8,067			$	7,375
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization			31,082				31,050
Other non-cash charges			8,282				7,737
Amortization of lease obligations			3,363				3,141
Interest on lease deposits			(1,977	)			(1,931	)
Change in current assets			37,670				6,848
Change in deferred energy			(12,884	)			5,443
Change in current liabilities			(25,332	)			78,718
Change in regulatory assets and liabilities			(4,070	)			(10,217	)
Change in deferred charges and credits			3,734				5,262
Net Cash Provided by Operating Activities			47,935				133,426
Financing Activities:
Issuance of long-term debt			350,000				—
Debt issuance costs			(2,342	)			—
Payments of long-term debt			(216,000	)			—
Draws on revolving credit facilities			52,257				85,408
Payments on revolving credit facilities			(59,300	)			(112,362	)
Net Cash Provided by (Used for) Financing Activities			124,615				(26,954	)
Investing Activities:
Purchase of held to maturity securities			(108,121	)			—
Proceeds from held to maturity securities			99,221				—
Proceeds from sale of trading securities			11,089				—
Increase in other investments			(3,287	)			(2,583	)
Electric plant additions			(27,295	)			(65,613	)
Amortization of loss on auction rate securities recorded as a regulatory asset			4,181				—
Gain on investments			(3,227	)			—
Net Cash Used for Investing Activities			(27,439	)			(68,196	)
Net Change in Cash and Cash Equivalents			145,111				38,276
Cash and Cash Equivalents - Beginning of Period			4,391				6,278
Cash and Cash Equivalents - End of Period		$	149,502			$	44,554

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

 

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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 September 30, 2011, our consolidated results of operations for the three and nine months ended September 30, 2011 and 2010, and cash flows for the nine months ended September 30, 2011 and 2010. The consolidated results of operations for the three and nine months ended September 30, 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 consolidated assets were $13.1 million and $13.2 million at September 30, 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.

 

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The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2011, and December 31, 2010:

 

		September 30, 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)		$	94,847			$	94,847			$	—			$	—
Unrestricted investments and other (2)(3)			82				82				—				—
Total Financial Assets		$	94,929			$	94,929			$	—			$	—
Derivatives – gas and power (4)		$	3 ,530			$	3,530			$	—			$	—
Total Financial Liabilities		$	3,530			$	3,530			$	—			$	—

 

		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 5 below.

(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 auction rate securities and preferred stock (“ARS”). As of December 31, 2010, we owned five ARS; during 2011, we sold all five ARS. For additional information, see Note 5 below and Note 10 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

(4)	Derivatives – gas and power represents 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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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:

 

		Nine Months Ended September  30, 2011
		(in thousands)
Balance as of January 1, 2011		$	7,862
Total realized gain:
Included in other income (expense), net			3,227
Purchases, sales, issuances, and settlements			(11,089	)
Transfers out of Level 3			—
Balance as of September 30, 2011		$	—

The realized gain was recorded in other income (expense), net, in our Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital.

 

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 September 30, 2011 Quantity				As of December 31, 2010 Quantity
Natural gas		MMBTU			3,410,000				4,610,000
Purchased power		MWh			—				161,632
Renewable energy credits		REC			—				40,000
Interest rate hedge		US Dollars			—				300,000,000

 

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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 September 30, 2011				As of December 31, 2010
				(in thousands)
Derivatives in an asset position:
Renewable energy credit sales		Prepayments and other		$	—			$	257
Total derivatives in an asset position				$	—			$	257
Derivatives in a liability position:
Natural gas futures contracts		Deferred credits and other liabilities – other		$	3,530			$	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				$	3,530			$	17,848

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

for the Three and Nine Months Ended September 30, 2011 and 2010

 

Derivatives Accounted for Utilizing Regulatory Accounting		Amount of Gain (Loss) Recognized in Regulatory Asset/Liability as of September 30,								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 September 30,								Amount of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income for the Nine Months Ended September 30,
		2011				2010						2011				2010				2011				2010
		(in thousands)										(in thousands)								(in thousands)
Natural gas futures contracts (1)		$	(3,574	)		$	(8,853	)		Fuel/Purchased power		$	(2,435	)		$	(2,164	)		$	(5,989	)		$	(3,604	)
Renewable energy credit sales			—				357			Operating revenues			—				—				—				—
Purchased power contracts			—				—			Purchased power			—				—				539				(365	)
Purchased power – excess sales			—				—			Operating revenues			—				(669	)			—				(669	)
Interest rate hedge			—				(30,392	)		Interest charges, net			—				—				—				—
Total		$	(3,574	)		$	(38,888	)				$	(2,435	)		$	(2,833	)		$	(5,450	)		$	(4,638	)

 

(1)	For 2011, includes $44.5 thousand of loss on natural gas futures contracts designated for October 2011 that were physically sold in September 2011 and the impact on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital has been deferred until October 2011.

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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5.	Investments

Investments were as follows at September 30, 2011, and December 31, 2010:

 

Description		Designation		Cost				Gross Unrealized Gains				Gross Unrealized Losses				Fair Value				Carrying Value
		(in thousands)
September 30, 2011
Nuclear decommissioning trust (1)
Debt securities		Available for sale		$	42,160			$	2,399			$	—			$	44,559			$	44,559
Equity securities		Available for sale			51,028				3,770				(4,677	)			50,121				50,121
Cash and other		Available for sale			167				—				—				167				167
Total Nuclear Decommissioning Trust				$	93,355			$	6,169			$	(4,677	)		$	94,847			$	94,847
Lease deposits (2)
Government obligations		Held to maturity		$	91,049			$	9,075			$	—			$	100,124			$	91,049
Total Lease Deposits				$	91,049			$	9,075			$	—			$	100,124			$	91,049
Unrestricted investments
Government obligations		Held to maturity		$	8,900			$	1				—			$	8,901			$	8,900
Total Unrestricted Investments				$	8,900			$	1			$	—			$	8,901			$	8,900
Other
Equity securities		Available for sale		$	94			$	—			$	(12	)		$	82			$	82
Non-marketable equity investments (3)		Equity			1,777				—				—				1,777				1,777
Total Other				$	1,871			$	—			$	(12	)		$	1,859			$	1,859
													Total Carrying Value							$	196,655
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(4)
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 (3)		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 the North Anna Nuclear Power Station (“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)	We believe the carrying value approximates fair value for our equity investments.

(4)

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 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. As of December 31, 2010, we owned five ARS; during 2011, we sold all five ARS.

 

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Our investments by classification at September 30, 2011, and December 31, 2010, were as follows:

 

		September 30, 2011								December 31, 2010
Description		Cost				Carrying Value				Cost				Carrying Value
		(in thousands)
Available for sale		$	93,449			$	94,929			$	97,748			$	105,473
Held to maturity			99,949				99,949				89,355				89,355
Equity			1,777				1,777				1,769				1,769
		$	195,175			$	196,655			$	188,872			$	196,597

Contractual maturities of unrestricted debt securities at September 30, 2011, were as follows:

 

Description		Less than 1 year				1-5 years				5-10 years				More than 10 years						Total
		(in thousands)
Available for Sale		$	—			$	—			$	—					$	—			$	—
Held to Maturity			8,900				—				—						—				8,900
		$	8,900			$	—			$	—					$	—			$	8,900

The contractual maturities of our restricted debt securities related to our nuclear decommissioning trust have not been disclosed because all maturities are prior to the estimated decommissioning date and the contractual maturities of our restricted debt securities related to our lease deposits have not been disclosed because all maturities are concurrent with the transaction maturity date.

 

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. 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. A portion of the proceeds of the issuance was used to repay our $215.0 million 2001 Series A Bonds due June 1, 2011. The remainder of the proceeds will be used 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.

 

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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 September 30, 2011, we have incurred approximately $10.6 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.

North Anna Outage

On August 23, 2011, a magnitude 5.8 earthquake near Mineral, Virginia caused the two reactors at North Anna to shut down immediately, as designed. Virginia Power, the co-owner and operator of North Anna, informs us that some of the earthquake's vibrations briefly exceeded North Anna's licensing design basis at certain frequencies; however, Virginia Power's inspections have shown no significant damage to equipment at the station from the earthquake. The reactors were placed in cold shutdown condition pending completion of the U.S. Nuclear Regulatory Commission (“NRC”) inspection and review. The restart of the two reactors is subject to NRC approval, which Virginia Power believes is likely to occur in the fourth quarter of 2011.

Refund of Spent Fuel Costs

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (“DOE”) is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as North Anna, in accordance with contracts executed with the DOE. The DOE did not begin accepting spent fuel in 1998 as specified in its contract. In 2004, Virginia Power filed a lawsuit seeking recovery of damages in connection with the DOE’s failure to commence accepting spent nuclear fuel from North Anna. A subsequent trial held in 2008 ruled in favor of Virginia Power and the DOE filed an appeal. The government's initial brief in the appeal was filed in June 2010. In the second quarter of 2011, the Federal Appeals Court issued a decision affirming the trial court's damages award. The government did not seek rehearing of the Federal Appeals Court decision or seek review by the U.S. Supreme Court. During the third quarter of 2011, Virginia Power received a settlement amount for spent fuel costs representing certain spent nuclear fuel-related costs incurred through June 30, 2006. Virginia Power then paid ODEC our proportionate share related to North Anna, $7.8 million, which is recorded as a reduction to fuel expense. We currently anticipate that Virginia Power will seek reimbursement for certain spent nuclear fuel-related costs incurred subsequent to June 30, 2006; however, due to the uncertainty of future collection, we have not recorded a receivable.

Margin Stabilization Plan

On October 11, 2011, our Board of Directors approved the refund of $10.0 million in accordance with our margin stabilization plan, which reduced accounts receivable-members in September 2011. See Note 5 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

 

7.	Subsequent Event

On October 11, 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 4.8%, effective October 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 September 30, 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.

During the third quarter of 2011, two natural disasters occurred. On August 23, 2011, a magnitude 5.8 earthquake near Mineral, Virginia caused the two reactors at the North Anna Nuclear Power Station (“North Anna”) to shut down immediately, as designed. This event resulted in the need for additional purchased power and operations and maintenance expense during the quarter; although the impact was not material to our financial results. There is the possibility that the impact could be material depending upon the length of the unavailability of the units at North Anna. Additionally, on August 27, 2011, our member distribution cooperatives’ service territories were impacted by Hurricane Irene, causing the loss of power for a significant number of our member distribution cooperatives’ customers for up to seven days. This resulted in decreased power requirements during this timeframe.

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). This resulted in an increase in sales volume to our member distribution cooperatives and additional purchased power expense for the nine months ended September 30, 2011, as compared to the same period in 2010.

Fuel expense and purchased power expense are significantly affected by the operations of our owned generation. The availability of North Anna and the economic dispatch of our combustion turbine facilities and the Clover Power Station (“Clover”) resulted in decreased fuel expense and increased purchased power volume for the three and nine months ended September 30, 2011, as compared to the same periods in 2010.

 

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In February 2011, we made the determination not to participate in an additional nuclear-powered generating unit at North Anna and we are currently working with Virginia Electric and Power Company (“Virginia Power”) on the logistics of our withdrawal as a participant in the project. Related to this decision, in 2011, we reclassified the corresponding construction work in progress to a regulatory asset. We are continuing to incur costs related to the additional unit which are recorded as accounts receivable as we expect reimbursement from Virginia Power upon the finalization of our withdrawal.

In the second quarter of 2011, we issued $350.0 million of first mortgage bonds in a private placement. A portion of the proceeds of the issuance was used to repay our $215.0 million 2001 Series A Bonds due June 1, 2011.

Weather affects the demand for electricity. We experienced milder weather during the three months ended September 30, 2011, as compared to the same period in 2010, which resulted in a reduction in our member distribution cooperatives’ customers’ requirements for power.

We have a margin stabilization plan that allows us to review our actual capacity-related costs of service and capacity revenue and adjust revenues from our member distribution cooperatives to meet our financial coverage requirements and accumulate additional equity as approved by our board of directors. Our formulary rate allows us to recover and refund amounts under the margin stabilization plan. On October 11, 2011, our Board of Directors approved the refund of $10.0 million in accordance with our margin stabilization plan, which reduced accounts receivable-members in September 2011. See Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Margin Stabilization Plan in our 2010 Annual Report on Form 10-K.

Factors Affecting Results

Formulary Rate

Our power sales are comprised of two 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 (demand).

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, REC and 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 the acquisition transactions; 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 expired on June 30, 2011.

 

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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 $4.8 million and $11.8 million was recorded for the three and nine months ended September 30, 2011, respectively, and approximately $19.2 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.

Power Supply Resources

We provide power to our members through a combination of our interests in 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 and nine months ended September 30, 2011 and 2010, were as follows:

 

		Three Months Ended September 30,																Nine Months Ended September 30,
		2011								2010								2011								2010
		(in MWh and percentages)																(in MWh and percentages)
Generated:
Clover			635,812				18.5	%			728,055				19.2	%			2,025,415				19.8	%			2,345,630				26.0	%
North Anna			277,078				8.1				410,315				10.8				1,231,386				12.0				1,206,562				13.4
Louisa			65,486				1.9				131,619				3.5				111,835				1.1				237,270				2.6
Marsh Run			74,213				2.2				204,448				5.4				137,963				1.3				355,176				4.0
Rock Springs			83,141				2.4				137,783				3.6				113,357				1.1				192,062				2.1
Distributed Generation			652				—				557				—				863				—				896				—
Total Generated			1,136,382				33.1				1,612,777				42.5				3,620,819				35.3				4,337,596				48.1
Purchased:
Other than renewable			2,237,551				65.1				2,141,809				56.5				6,334,124				61.8				4,561,932				50.6
Renewable (1)			60,626				1.8				38,938				1.0				299,776				2.9				113,370				1.3
Total Purchased			2,298,177				66.9				2,180,747				57.5				6,633,900				64.7				4,675,302				51.9
Total Available Energy			3,434,559				100.0	%			3,793,524				100.0	%			10,254,719				100.0	%			9,012,898				100.0	%

 

(1)	Related to our contracts from renewable facilities from which we purchase renewable energy credits. ODEC sells these renewable energy credits to our member distribution cooperatives and any remaining renewable energy credits are sold to non-members.

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.

 

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Our generating facilities are under dispatch control of PJM. Typically, nuclear facilities are almost always dispatched and coal-fired facilities and combustion turbine facilities are dispatched based upon economic factors including the market price of energy. The operational availability of Clover for the three and nine months ended September 30, 2011 and 2010, was as follows:

 

		Clover
		Three Months  Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Unit 1			99.7	%			97.3	%			96.6	%			95.5	%
Unit 2			99.4				94.2				94.5				95.0
Combined			99.6	%			95.7	%			95.6	%			95.2	%

The output of Clover and North Anna for the three and nine months ended September 30, 2011 and 2010, as a percentage of the maximum dependable capacity rating of the facilities, was as follows:

 

		Clover																North Anna
		Three Months Ended September 30,								Nine Months Ended September 30,								Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010				2011				2010				2011				2010
Unit 1			67.5	%			74.9	%			72.7	%			81.7	%			57.6	%			74.5	%			86.8	%			91.9	%
Unit 2			66.8				77.8				70.9				83.6				57.5				95.1				87.5				80.5
Combined			67.1	%			76.4	%			71.8	%			82.7	%			57.6	%			84.8	%			87.2	%			86.2	%

The scheduled maintenance outages and unscheduled outages for Clover for the three and nine months ended September 30, 2011 and 2010, were as follows:

 

		Scheduled Outages																Unscheduled Outages
		Three Months Ended September 30,								Nine Months Ended September 30,								Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010				2011				2010				2011				2010
		(in days)								(in days)								(in days)								(in days)
Unit 1			—				—				7.9				8.0				0.3				2.6				1.4				4.4
Unit 2			—				5.2				8.1				13.1				1.1				—				7.7				0.4
Combined			—				5.2				16.0				21.1				1.4				2.6				9.1				4.8

The scheduled maintenance and refueling outages and unscheduled outages for North Anna for the three and nine months ended September 30, 2011 and 2010, were as follows:

 

		Scheduled Outages																Unscheduled Outages
		Three Months Ended September 30,								Nine Months Ended September 30,								Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010				2011				2010				2011				2010
		(in days)								(in days)								(in days)								(in days)
Unit 1			—				19.0				—				19.0				38.4				4.4				38.4				4.4
Unit 2			20.0				—				20.0				36.3				18.4				2.0				18.4				13.0
Combined			20.0				19.0				20.0				55.3				56.8				6.4				56.8				17.4

North Anna units 1 and 2 automatically shut down on August 23, 2011, as a result of a magnitude 5.8 earthquake near Mineral, Virginia. Unit 2 began its scheduled maintenance and refueling outage on September 11, 2011. Virginia Power, the co-owner and operator of North Anna, is awaiting approval from the Nuclear Regulatory Commission to restart both units. For additional information, see “Part 2 Other Information – Item 5 – Other Information” below.

 

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During the three and nine months ended September 30, 2011 and 2010, the operational availability of our Louisa, Marsh Run, and Rock Springs combustion turbine facilities was as follows:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Louisa			96.9	%			96.0	%			97.8	%			98.2	%
Marsh Run			97.1				95.3				97.6				96.7
Rock Springs			99.4				98.1				98.7				95.0

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.

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 and nine months ended September 30, 2011 and 2010, were as follows:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(in thousands)								(in thousands)
Revenues from sales to:
Member distribution cooperatives
Base energy revenues		$	57,004			$	59,128			$	164,772			$	144,653
Fuel factor adjustment revenues			86,500				87,194				246,760				216,879
Total energy revenues			143,504				146,322				411,532				361,532
Demand (capacity) revenues			79,130				74,867				238,038				202,775
Total revenues from sales to member distribution cooperatives			222,634				221,189				649,570				564,307
Non-members			7,275				24,241				31,486				40,843
Total operating revenues		$	229,909			$	245,430			$	681,056			$	605,150
Average costs to member distribution cooperatives (per MWh)		$	67.97			$	66.31			$	69.26			$	69.38

 

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Our energy sales in megawatt hours (“MWh”) and demand sales in megawatts (“MW”) to our member distribution cooperatives and non-members for the three and nine months ended September 30, 2011 and 2010, were as follows:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(in MWh)								(in MWh)
Energy sales to:
Member distribution cooperatives			3,275,609				3,335,713				9,379,184				8,133,170
Non-members			158,453				417,672				753,117				782,119
Total energy sales			3,434,062				3,753,385				10,132,301				8,915,289
		(in MW)								(in MW)
Demand sales to Member distribution cooperatives			6,455				6,906				18,884				16,322

Our energy sales in MWh to our member distribution cooperatives for the three and nine months ended September 30, 2011, were 1.8% lower and 15.3% higher, respectively, as compared to the same periods in 2010. For the three months ended September 30, 2011, energy sales were lower primarily due to milder weather and were also impacted by our member distribution cooperatives’ outages related to Hurricane Irene. For the nine months ended September 30, 2011, energy sales were higher primarily as a result of the service territory acquisition by two of our member distribution cooperatives as of June 1, 2010. The service territory acquisition increased our energy sales to our member distribution cooperatives approximately 15.6% for the nine months ended September 30, 2011, as compared to the same period in 2010.

Our demand sales in MW to our member distribution cooperatives for the three and nine months ended September 30, 2011, were 6.5% lower and 15.7% higher, respectively, as compared to the same periods in 2010. For the three months ended September 30, 2011, demand sales were lower due to milder weather. For the nine months ended September 30, 2011, demand sales were higher as a result of the additional service territory which increased our demand sales to our member distribution cooperatives approximately 15.7% for the nine months ended September 30, 2011, as compared to the same period in 2010.

Our energy sales in MWh to non-members were 62.1% and 3.7% lower, for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010. Sales to non-members consist of sales of excess purchased and generated energy.

Total revenues from sales to our member distribution cooperatives increased $1.4 million, or 0.7%, and $85.3 million, or 15.1%, for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010. The increase in total revenues for the nine months ended September 30, 2011, is primarily related to the additional service territory.

Our average cost per MWh to member distribution cooperatives increased $1.66 per MWh, or 2.5%, for the three months ended September 30, 2011 as compared to the same period in 2010, primarily related to the increase in demand revenues and the decrease in MWh volume, which resulted in a higher average cost per MWh. Our average cost per MWh to member distribution cooperatives was relatively flat for the nine months ended September 30, 2011, as compared to the same period in 2010.

Non-member revenue decreased $17.0 million, or 70.0%, and $9.4 million, or 22.9%, for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010 due to the decrease in the volume of excess energy sales and the decrease in the average price.

 

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Operating Expenses

The following is a summary of the components of our operating expenses for the three and nine months ended September 30, 2011 and 2010:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(in thousands)								(in thousands)
Fuel		$	28,573			$	51,136			$	90,689			$	119,388
Purchased power			149,258				155,610				455,542				339,567
Deferred energy			28				(8,308	)			(12,884	)			5,443
Operations and maintenance			12,305				10,546				28,992				28,907
Administrative and general			9,142				9,409				29,092				32,198
Depreciation and amortization			10,382				10,373				31,082				31,050
Amortization of regulatory asset/(liability), net			819				761				3,030				2,460
Accretion of asset retirement obligations			886				841				2,656				2,492
Taxes other than income taxes			1,917				2,103				6,335				6,413
Total Operating Expenses		$	213,310			$	232,471			$	634,534			$	567,918

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.”

Total operating expenses decreased $19.2 million, or 8.2%, for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to decreases in fuel expense and purchased power expense partially offset by the increase in deferred energy expense.

 

•

Fuel expense decreased $22.6 million, or 44.1%, for the three months ended September 30, 2011, as compared to the same period in 2010, primarily due to the decrease in the economic dispatch of our combustion turbine facilities and a $7.8 million refund of spent fuel costs associated with North Anna. See Note 6–Notes to Condensed Consolidated Financial Statements in Part 1, Item 1.

 

•

Purchased power expense, which includes the cost of purchased energy, capacity, and transmission, decreased $6.4 million, or 4.1%, for the three months ended September 30, 2011, primarily due to a 9.0% decrease in the average cost of purchased power, partially offset by a 5.4% increase in the volume of purchased energy necessitated by the decrease in energy supplied by our owned generation.

 

•

Deferred energy expense increased $8.3 million, or 100.3% for the three months ended September 30, 2011, as compared to the same period in 2010. For the three months ended September 30, 2011, we over-collected $28.0 thousand in energy costs as compared to an under-collection of $8.3 million in 2010.

Total operating expenses increased $66.6 million, or 11.7%, for the nine months ended September 30, 2011, as compared to the same period in 2010, primarily due to increases in purchased power expense partially offset by decreases in fuel expense and deferred energy expense.

 

•

Purchased power expense increased $116.0 million, or 34.2%, for the nine months ended September 30, 2011, primarily due to a 41.9% increase in the volume of purchased energy for the nine months ended September 30, 2011, as compared to the same period in 2010, primarily due to the acquisition of the additional service territory and a decrease in energy supplied by our owned generation, partially offset by a 5.5% decrease in the average cost of purchased power.

 

•

Fuel expense decreased $28.7 million, or 24.0%, for the nine months ended September 30, 2011, as compared to the same period in 2010, primarily due to the decrease in the economic dispatch of our combustion turbine facilities and Clover and a $7.8 million refund of spent fuel costs associated with North Anna.

 

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•

Deferred energy expense decreased $18.3 million, or 336.7% for the nine months ended September 30, 2011, as compared to the same period in 2010. For the nine months ended September 30, 2011, we under-collected $12.9 million in energy costs; whereas for the same period in 2010, we over-collected $5.4 million in energy costs. Our deferred energy balance was a net over-collection of energy costs of $32.5 million at September 30, 2011, as compared to a net over-collection of energy costs of $45.4 million at December 31, 2010.

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 had converted to preferred stock (“ARS”), which was recorded as a regulatory asset in accordance with Accounting for Regulated Operations. For the three and nine months ended September 30, 2011, we amortized $1.4 million and $4.2 million, respectively, 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 Investments

For the three and nine months ended September 30, 2011, we recognized a gain of $4.5 thousand and $3.2 million, respectively, as a result of the sale of our five 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 was relatively flat for the three months ended September 30, 2011, as compared to the same period in 2010, and increased $0.5 million, or 13.4%, for the nine months ended September 30, 2011, as compared to the same period in 2010, primarily due to income earned on our nuclear decommissioning trust.

Interest Charges, Net

The primary factors affecting our interest charges, net, are issuances of indebtedness, 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 a dispute with Norfolk Southern in 2009. The major components of interest charges, net for the three and nine months ended September 30, 2011 and 2010, were as follows:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
		(in thousands)								(in thousands)
Interest expense on long-term debt		$	(12,530	)		$	(11,604	)		$	(38,303	)		$	(34,771	)
Interest charges related to Norfolk Southern			—				1,261				—				3,784
Other			(819	)			(861	)			(2,261	)			(2,153	)
Total Interest Charges			(13,349	)			(11,204	)			(40,564	)			(33,140	)
Allowance for borrowed funds used during construction			217				458				636				1,186
Interest Charges, net		$	(13,132	)		$	(10,746	)		$	(39,928	)		$	(31,954	)

Interest expense on long-term debt increased $0.9 million, or 8.0%, and $3.5 million, or 10.2%, for the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010, primarily due to the issuance of $350.0 million of debt in the second quarter of 2011. See “Liquidity and Capital Resources—Financings” below. In 2010, interest charges, net, were lower primarily due to the amortization of the regulatory liability related to settlement of a dispute with Norfolk Southern. This was fully amortized by December 31, 2010.

Net Margin Attributable to ODEC

Our net margin attributable to ODEC, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, decreased $0.1 million, or 4.6%, and increased $0.7 million, or 10.0%, for

 

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the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010 due to higher interest charges. There were no additional equity contributions in 2011. The three and nine months ended September 30, 2010 included $0.5 million and $0.7 million, respectively, of additional equity contributions.

Financial Condition

The principal changes in our financial condition from December 31, 2010 to September 30, 2011, were caused by the increases in long-term debt (offset by the decrease in long-term due within one year) and accrued expenses and decreases in accounts receivable–members, accounts payable, accounts payable–members, regulatory liabilities, construction work in progress, deferred energy, and interest rate hedge.

 

•

Long-term debt increased $344.6 million. On April 7, 2011, we issued $350.0 million of debt which provided funding to repay the $215.0 million maturity of our 2001 Series A Bonds on June 1, 2011. Long-term debt due within one year decreased $210.6 million primarily due to the maturing debt.

 

•

Accrued expenses increased $15.3 million primarily due to increased accrued interest.

 

•

Accounts receivable–members decreased $40.6 million as a result of lower sales to members in September 2011 as compared to December 2010 and a $10.0 million refund in accordance with our margin stabilization plan, which was recorded as a reduction of accounts receivable-members.

 

•

Accounts payable decreased $23.8 million due to decreased purchased power requirements in September 2011 as compared to December 2010.

 

•

Accounts payable–members decreased $16.8 million primarily due to the change in the margin stabilization balance. At September 30, 2011, the balance under our margin stabilization plan was $8.6 million, net of the $10.0 million refund which occurred in the third quarter of 2011, as compared to the $22.5 million balance at December 31, 2010.

 

•

Regulatory liabilities decreased $14.5 million. The regulatory liability related to the Norfolk Southern settlement decreased $9.2 million as a result of the amortization as a reduction of fuel expense. The regulatory liability related to the North Anna nuclear decommissioning trust unrealized gain decreased $6.2 million. For additional information, see Note 10 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

 

•

Construction work in progress decreased $13.0 million primarily 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. This is partially offset by the $9.9 million increase in construction work in progress related to nuclear fuel.

 

•

Deferred energy decreased $12.9 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.

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 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 September 30, 2011, we have incurred approximately $10.6 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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Liquidity and Capital Resources

Sources

Cash generated by our operations and periodically, borrowings under our credit facilities as well as the occasional issuance of long-term indebtedness in the capital markets, provide our sources of liquidity and capital.

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 nine months of 2011 and 2010, our operating activities provided cash flows of $47.9 million and $133.4 million, respectively. Operating activities in 2011 were primarily impacted by the following:

 

•

Current assets changed $37.7 million primarily due to the $40.6 million decrease in accounts receivable–members and the $7.9 million decrease in accounts receivable partially offset by the $8.6 million increase in fuel, materials, and supplies and the $3.4 million increase in accounts receivable–deposits.

 

•

Current liabilities changed $25.3 million primarily due to the $23.8 million decrease in accounts payable and the $16.8 million decrease in accounts payable–members, partially offset by the $15.3 million increase in accrued expenses.

 

•

Deferred energy decreased $12.9 million due to the under-collection of energy costs in 2011.

Auction Rate Securities and Related Preferred Stock

As of December 31, 2010, we owned five ARS with an estimated fair value of $7.9 million. During 2011, we sold all five of the ARS for $11.1 million, and recognized a gain of $3.2 million.

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 fully amortized in 2011; $1.4 million and $4.2 million was amortized during the three and nine months ended September 30, 2011, respectively.

Credit Facilities

In addition to liquidity from our operating activities, we currently maintain a total of $460.0 million in unsecured committed credit facilities to cover our short-term and medium-term funding needs. At September 30, 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 to maintain similar levels of liquidity in the future.

As of September 30, 2011, our credit facilities were as follows:

 

Lender		Amount				Expiration Date
		(in millions)
Bank of America, N.A.		$	70.0			November 5, 2013
Branch Banking and Trust Company			50.0			May 31, 2013
CoBank, ACB			100.0			June 18, 2013
JPMorgan Chase Bank, National Association			70.0			June 1, 2013
National Rural Utilities Cooperative Finance Corp.			75.0			April 15, 2012
PNC Bank, National Association			25.0			August 4, 2013
Wells Fargo Bank, N.A.			70.0			August 31, 2012
		$	460.0

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.

 

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In the second quarter of 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. A portion of the proceeds of the issuance was used to repay our $215.0 million 2001 Series A Bonds due June 1, 2011. The remainder of the proceeds is being used for general corporate purposes.

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. 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the third 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.

ITEM 5. OTHER INFORMATION

On August 23, 2011, a magnitude 5.8 earthquake near Mineral, Virginia caused the two reactors at North Anna to shut down immediately, as designed. Virginia Power, the co-owner and operator of North Anna, informs us that some of the earthquake’s vibrations briefly exceeded North Anna’s licensing design basis at certain frequencies; however, Virginia Power’s inspections have shown no significant damage to equipment at the station from the earthquake. The reactors were placed in cold shutdown condition pending completion of NRC inspection and review. The restart of the two reactors is subject to NRC approval, which Virginia Power believes is likely to occur in the fourth quarter of 2011.

 

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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
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

 

*

XBRL (“Extensible Business Reporting Language”) information is furnished and not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

 

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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: November 10, 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
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

 

*

XBRL (“Extensible Business Reporting Language”) information is furnished and not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

 

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