10-Q

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10-Q 1 d579868d10q.htm 10-Q 10-Q

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 June 30, 2013

¨	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 ¨ No x

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.

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.

GLOSSARY OF TERMS

The following abbreviations or acronyms used in this Form 10-Q are defined below:


Abbreviation or Acronym		Definition
Clover		Clover Power Station
FERC		Federal Energy Regulatory Commission
GAAP		Accounting principles generally accepted in the United States
Indenture		Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated January 1, 2011, of ODEC with Branch Banking and Trust Company, as trustee, as amended and supplemented
MW		Megawatt(s)
MWh		Megawatt hour(s)
NRECA		National Rural Electric Cooperative Association
North Anna		North Anna Nuclear Power Station
ODEC, We, Our		Old Dominion Electric Cooperative
PJM		PJM Interconnection, LLC
TEC		TEC Trading, Inc.
Wildcat Point		Wildcat Point Generation Facility
XBRL		Extensible Business Reporting Language

OLD DOMINION ELECTRIC COOPERATIVE

INDEX


	Page Number
PART I. Financial Information

Item 1. Financial Statements

Condensed Consolidated Balance Sheets – June 30, 2013 (unaudited) and December 31, 2012		4

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (unaudited) – Three and Six Months Ended June 30, 2013 and 2012		5

Condensed Consolidated Statements of Cash Flows (unaudited) – Six Months Ended June 30, 2013 and 2012		6

Notes to Condensed Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		12

Item 3. Quantitative and Qualitative Disclosures About Market Risk		20

Item 4. Controls and Procedures		20

PART II. Other Information

Item 1. Legal Proceedings		21

Item 1A. Risk Factors		21

Item 5. Other Information		21

Item 6. Exhibits		22

OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
	2013			2012
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	1,657,546		$	1,655,705
Less accumulated depreciation		(734,843	)		(721,541	)

		922,703			934,164
Nuclear fuel, at amortized cost		21,174			20,379
Construction work in progress		30,272			36,797

Net Electric Plant		974,149			991,340

Investments:
Nuclear decommissioning trust		120,803			113,280
Lease deposits		95,518			94,145
Unrestricted investments and other		2,477			55,599

Total Investments		218,798			263,024

Current Assets:
Cash and cash equivalents		130,097			37,343
Accounts receivable		3,433			3,564
Accounts receivable–deposits		4,400			4,400
Accounts receivable–members		71,161			86,154
Fuel, materials, and supplies		48,057			59,091
Prepayments and other		1,946			2,556

Total Current Assets		259,094			193,108

Deferred Charges:
Regulatory assets		93,426			87,006
Other		10,215			9,043

Total Deferred Charges		103,641			96,049

Total Assets	$	1,555,682		$	1,543,521

CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	365,156		$	360,424
Non-controlling interest		13,323			13,257

Total Patronage capital and Non-controlling interest		378,479			373,681
Long-term debt		777,622			737,836

Total Capitalization		1,156,101			1,111,517

Current Liabilities:
Long-term debt due within one year		28,292			28,292
Accounts payable		53,144			75,583
Accounts payable–members		41,863			38,585
Accrued expenses		6,206			4,936
Deferred energy		37,997			56,027

Total Current Liabilities		167,502			203,423

Deferred Credits and Other Liabilities:
Asset retirement obligations		78,870			76,880
Obligations under long-term lease		76,655			74,086
Regulatory liabilities		70,922			71,452
Other		5,632			6,163

Total Deferred Credits and Other Liabilities		232,079			228,581

Commitments and Contingencies		—			—

Total Capitalization and Liabilities	$	1,555,682		$	1,543,521

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES, AND PATRONAGE CAPITAL (UNAUDITED)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Operating Revenues	$	187,623		$	198,280		$	408,336		$	420,707

Operating Expenses:
Fuel		30,317			19,263			61,769			46,797
Purchased power		118,007			119,654			266,659			257,198
Deferred energy		(11,280	)		5,989			(18,030	)		15,413
Operations and maintenance		11,774			15,193			19,860			25,456
Administrative and general		10,655			9,863			21,447			18,988
Depreciation and amortization		10,569			10,468			21,209			20,844
Amortization of regulatory asset/(liability), net		1,272			973			1,584			1,717
Accretion of asset retirement obligations		995			940			1,990			1,858
Taxes, other than income taxes		2,184			2,089			4,416			4,223

Total Operating Expenses		174,493			184,432			380,904			392,494

Operating Margin		13,130			13,848			27,432			28,213
Other expense, net		(648	)		(559	)		(1,301	)		(1,135	)
Investment income		1,610			1,319			2,268			2,331
Interest charges, net		(11,685	)		(12,134	)		(23,580	)		(24,445	)
Income taxes		(16	)		5			(21	)		10

Net Margin including Non-controlling interest		2,391			2,479			4,798			4,974
Non-controlling interest		(45	)		19			(66	)		40

Net Margin attributable to ODEC		2,346			2,498			4,732			5,014
Patronage Capital - Beginning of Period		362,810			353,001			360,424			350,485

Patronage Capital - End of Period	$	365,156		$	355,499		$	365,156		$	355,499

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Six Months Ended
	June 30,
	2013			2012
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	4,798		$	4,974
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		21,209			20,844
Other non-cash charges		9,778			6,943
Amortization of lease obligations		2,569			2,399
Interest on lease deposits		(1,373	)		(1,343	)
Change in current assets		26,768			(13,269	)
Change in deferred energy		(18,030	)		15,413
Change in current liabilities		(17,891	)		(28,477	)
Change in regulatory assets and liabilities		(12,055	)		(1,137	)
Change in deferred charges and credits		(430	)		(2,813	)

Net Cash Provided by Operating Activities		15,343			3,534

Financing Activities:
Issuance of long-term debt		100,000			—
Debt issuance costs		(744	)		—
Payment of long-term debt		(60,535	)		—

Net Cash Provided by Financing Activities		38,721			—

Investing Activities:
Purchases of held to maturity securities		—			(50,037	)
Proceeds from held to maturity securities		53,117			41,000
Increase in other investments		(2,080	)		(3,090	)
Electric plant additions		(12,347	)		(17,625	)

Net Cash Provided by (Used for) Investing Activities		38,690			(29,752	)

Net Change in Cash and Cash Equivalents		92,754			(26,218	)
Cash and Cash Equivalents - Beginning of Period		37,343			63,756

Cash and Cash Equivalents - End of Period	$	130,097		$	37,538

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

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

General

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. In the opinion of 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 June 30, 2013, our consolidated results of operations for the three and six months ended June 30, 2013 and 2012, and cash flows for the six months ended June 30, 2013 and 2012. The consolidated results of operations for the three and six months ended June 30, 2013, 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 2012 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and 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 customers 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 consolidated assets were $15.0 million and $14.0 million at June 30, 2013 and December 31, 2012, 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 wholly-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 FERC, but are not regulated by the respective public service commissions of the states in which our member distribution cooperatives operate.

We comply with the Uniform System of Accounts as prescribed by FERC. In conformity with 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.

2.	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.

The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and December 31, 2012:


			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	June 30,		Assets		Inputs		Inputs
	2013		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust ⁽¹⁾⁽²⁾	$	120,803	$	36,917	$	83,886	$	—
Unrestricted investments and other ⁽³⁾		150		150		—		—

Total Financial Assets	$	120,953	$	37,067	$	83,886	$	—

Derivatives - gas and power ⁽⁴⁾	$	607	$	607	$	—	$	—

Total Financial Liabilities	$	607	$	607	$	—	$	—


			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	December 31,		Assets		Inputs		Inputs
	2012		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust⁽¹⁾⁽²⁾	$	113,280	$	38,048	$	75,232	$	—
Unrestricted investments and other ⁽³⁾		122		122		—		—

Total Financial Assets	$	113,402	$	38,170	$	75,232	$	—

Derivatives - gas and power ⁽⁴⁾	$	624	$	624	$	—	$	—

Total Financial Liabilities	$	624	$	624	$	—	$	—

⁽¹⁾	For additional information about our nuclear decommissioning trust see Note 4 below.

⁽²⁾

Nuclear decommissioning trust includes investments that are available for sale and classified as Level 2. These Level 2 assets consist of an equity fund that attempts to replicate the return of the S&P 500, an equity fund that invests in small capitalization stocks, and an equity fund that invests in international stocks. The fair values of the investments in the nuclear decommissioning trust have been estimated using the net asset value per share.

⁽³⁾	Unrestricted investments and other includes investments that are available for sale related to equity securities.

⁽⁴⁾

Derivatives – gas and power represent natural gas futures contracts and purchased power contracts, which are recorded on our balance sheet in deferred credits and other liabilities–other. As of June 30, 2013 and December 31, 2012, the amounts represent gas contracts, which are indexed against NYMEX. For additional information about our derivative financial instruments, see Notes 1 and 4 of the Notes to Consolidated Financial Statements in our 2012 Annual Report on Form 10-K.

We did not have any financial assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category.

3.	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 instruments. See Note 1 of the Notes to Consolidated Financial Statements in our 2012 Annual Report on Form 10-K.

Changes in the fair value of our derivative instruments accounted for at fair value are recorded as a regulatory asset or regulatory liability. The change in these accounts is included in the operating activities section of our Condensed Consolidated Statements of Cash Flows.

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


		As of	As of
		June 30, 2013	December 31, 2012
Commodity	Unit of Measure	Quantity	Quantity
Natural gas	MMBTU	1,450,000	650,000

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


		Fair Value
		As of		As of
		June 30,		December 31,
	Balance Sheet Location	2013		2012
		(in thousands)
Derivatives in a liability position:

Natural gas futures contracts	Deferred credits and other liabilities-other	$	607	$	624

Total derivatives in a liability position		$	607	$	624

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Three and Six Months Ended June 30, 2013 and 2012


Derivatives Accounted for Utilizing Regulatory Accounting	Amount of Gain (Loss) Recognized in Regulatory Asset/Liability for Derivatives as of June 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 June 30,						Amount of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income for the Six Months Ended June 30,
	2013			2012				2013			2012			2013			2012
	(in thousands)							(in thousands)						(in thousands)
Natural gas futures contracts ⁽¹⁾	$	(2,314	)	$	(6,775	)	Fuel	$	(687	)	$	(2,079	)	$	(687	)	$	(2,079	)
Purchased power contracts		—			—		Purchased power		—			237			—			(2,736	)

Total	$	(2,314	)	$	(6,775	)		$	(687	)	$	(1,842	)	$	(687	)	$	(4,815	)

⁽¹⁾	As of June 30, 2013 and 2012, includes a regulatory asset of $1.7 million and $4.6 million, respectively, to be recognized in future periods as the result of the contracts being effectively settled.

Our hedging activities expose us to credit-related risks. We use hedging instruments, including forwards, futures, financial transmission rights, and options, to mitigate 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 hedging instruments, 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 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 exceed the prices previously agreed upon with the defaulting counterparty.

4.	Investments

Investments were as follows at June 30, 2013 and December 31, 2012:


Description	Designation	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value		Carrying Value
		(in thousands)
June 30, 2013
Nuclear decommissioning trust ⁽¹⁾
Debt securities	Available for sale	$	34,814	$	1,960	$	—	$	36,774	$	36,774
Equity securities	Available for sale		63,037		20,849		—		83,886		83,886
Cash and other	Available for sale		143		—		—		143		143

Total Nuclear Decommissioning Trust		$	97,994	$	22,809	$	—	$	120,803	$	120,803

Lease Deposits ⁽²⁾
Government obligations	Held to maturity	$	95,518	$	7,158	$	—	$	102,676	$	95,518

Total Lease Deposits		$	95,518	$	7,158	$	—	$	102,676	$	95,518

Unrestricted investments
Debt securities	Held to maturity	$	500	$	—	$	—	$	500	$	500

Total Unrestricted Investments		$	500	$	—	$	—	$	500	$	500

Other
Equity securities	Available for sale	$	129	$	21	$	—	$	150	$	150
Non-marketable equity investments ⁽³⁾	Equity		1,827		—		—		1,827		1,827

Total Other		$	1,956	$	21	$	—	$	1,977	$	1,977

										$	218,798

December 31, 2012
Nuclear decommissioning trust ⁽¹⁾
Debt securities	Available for sale	$	34,342	$	3,473	$	—	$	37,815	$	37,815
Equity securities	Available for sale		61,322		13,910		—		75,232		75,232
Cash and other	Available for sale		233		—		—		233		233

Total Nuclear Decommissioning Trust		$	95,897	$	17,383	$	—	$	113,280	$	113,280

Lease Deposits ⁽²⁾
Government obligations	Held to maturity	$	94,145	$	11,063	$	—	$	105,208	$	94,145

Total Lease Deposits		$	94,145	$	11,063	$	—	$	105,208	$	94,145

Unrestricted investments
Government obligations	Held to maturity	$	51,900	$	8	$	—	$	51,908	$	51,900
Debt securities	Held to maturity		1,750		—		—		1,750		1,750

Total Unrestricted Investments		$	53,650	$	8	$	—	$	53,658	$	53,650

Other
Equity securities	Available for sale	$	113	$	9	$	—	$	122	$	122
Non-marketable equity investments ⁽³⁾	Equity		1,827		—		—		1,827		1,827

Total Other		$	1,940	$	9	$	—	$	1,949	$	1,949

										$	263,024

⁽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 2012 Annual Report on Form 10-K. 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 2012 Annual Report on Form 10-K.

⁽³⁾	We believe the carrying value approximates fair value for our equity investments.

Our investments by classification at June 30, 2013 and December 31, 2012, were as follows:


	June 30, 2013				December 31, 2012
Description	Cost		Carrying Value		Cost		Carrying V alue
	(in thousands)
Available for sale	$	98,123	$	120,953	$	96,010	$	113,402
Held to maturity		96,018		96,018		147,795		147,795
Equity		1,827		1,827		1,827		1,827

	$	195,968	$	218,798	$	245,632	$	263,024

Contractual maturities of unrestricted debt securities at June 30, 2013, 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		500		—		—		—		500

	$	500	$	—	$	—	$	—	$	500

The contractual maturities of our restricted debt securities related to our nuclear decommissioning trust have not been disclosed since all maturities are prior to the estimated decommissioning date nor have we disclosed the contractual maturities of our restricted debt securities related to our lease deposits since all maturities are concurrent with the transaction maturity date.

Other

2002 Series A Bonds

Our 2002 Series A bonds, with an aggregate principal amount of $60.2 million outstanding, were subject to optional redemption by ODEC on or after June 1, 2013. We issued a call notice for the 2002 Series A bonds in the second quarter of 2013 and redeemed these bonds on June 1, 2013. We paid a premium of $0.3 million and had unamortized debt issuance costs of $1.5 million related to these bonds, for a total of $1.8 million. These costs have been deferred as a regulatory asset and will be amortized over the original life of the debt to 2028.

Issuance of 2013 First Mortgage Bonds

On June 28, 2013, we issued $100.0 million of first mortgage bonds in a private placement. The bonds consist of $50.0 million of 4.21% First Mortgage Bonds, 2013 Series A due December 1, 2043 and $50.0 million of 4.36% First Mortgage Bonds, 2013 Series B due December 1, 2053. The bonds were issued under the Indenture. See Note 11 of the Notes to Consolidated Financial Statements in our 2012 Annual Report on Form 10-K.

Seeking Approval to Construct a Natural Gas-fueled Generation Facility

On April 23, 2013, we announced our intention to seek approval to construct a natural gas-fueled generation facility, named the Wildcat Point Generation Facility, in Cecil County, Maryland. We currently anticipate that construction of the facility will begin in late 2014 and it would become operational in mid-2017. On May 20, 2013, we applied to the Maryland Public Service Commission for a Certificate of Public Convenience and Necessity, and we continue to pursue permits and contracts related to the construction of the facility. The development, construction, and operation of Wildcat Point are subject to obtainment of government and regulatory approvals.

Voluntary Prepayment to Defined Benefit Plan

In April 2013, we elected to make a voluntary prepayment of $7.7 million to the NRECA Retirement Security Plan, a noncontributory, defined benefit multiple employer master pension plan. We recorded this prepayment as a regulatory asset which will be amortized over the next ten years beginning January 1, 2013.

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. 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 June 30, 2013, there have been no significant changes in our critical accounting policies as disclosed in our 2012 Annual Report on Form 10-K. These policies include the accounting for rate regulation, deferred energy, margin stabilization plan, accounting for asset retirement and environmental obligations, and accounting for derivatives and hedging.

Basis of Presentation

The accompanying financial statements reflect the consolidated accounts of ODEC and TEC. See Note 1—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’ energy and demand requirements through a portfolio of resources including generating facilities, long-term and short-term physically-delivered forward power purchase contracts, and spot market purchases. We also supply the transmission services necessary to deliver this power to our member distribution cooperatives.

Weather is one factor that affects the demand for electricity. We experienced more typical weather during the six months ended June 30, 2013, as compared to the same period in 2012, when we experienced milder than normal weather. This resulted in an increase in our member distribution cooperatives’ customers’ requirements for power.

Deferred energy expense represents the difference between energy revenues and energy expenses. In the three and six months ended June 30, 2013, we under-collected energy costs from our member distribution cooperatives; however, our cumulative deferred energy balance remains an over-collection. Over-collected energy costs appear as a liability on our Condensed Consolidated Balance Sheet and will be refunded to our member distribution cooperatives in subsequent periods through our formulary rate. For further discussion on deferred energy, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Deferred Energy” in Item 7 of our 2012 Annual Report on Form 10-K.

Fuel expense is affected by the operational availability and dispatch of our owned generation by PJM. Fuel expense increased for the three and six months ended June 30, 2013, as compared to the same periods in 2012, due to increased operational availability and dispatch of Clover.

On June 1, 2013, we redeemed our 2002 Series A bonds, with an aggregate principal amount of $60.2 million. On June 28, 2013, we issued $100.0 million of first mortgage bonds in a private placement. The bonds consist of $50.0 million of 4.21% First Mortgage Bonds, 2013 Series A due December 1, 2043; and $50.0 million of 4.36% First Mortgage Bonds, 2013 Series B due December 1, 2053.

Factors Affecting Results

Formulary Rate

Our power sales are comprised of two power products – energy and 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 demand.

The rates we charge our member distribution cooperatives for sales of energy and demand are determined by a formulary rate accepted by 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 base energy rate, an energy adjustment rate, and a demand 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 expect to incur without seeking FERC approval. For further discussion on our formulary rate, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formulary Rate” in Item 7 of our 2012 Annual Report on Form 10-K.

Weather

Weather is one factor that affects the demand for electricity. Relatively higher or lower temperatures tend to increase the demand for energy to use air conditioning and heating systems, respectively. Mild weather generally reduces the demand because heating and air conditioning systems are operated less. Weather also plays a role in the price of market energy through its effects on the market prices for fuel, particularly natural gas. Heating degree days are a measurement tool used to quantify the need to utilize heat for a building, and cooling degree days are a measurement tool used to quantify the need to utilize cooling for a building. The heating degree days and cooling degree days for the three and six months ended June 30, 2013 and 2012, were as follows:


	Three Months Ended June 30,				%			Six Months Ended June 30,				%
	2013		2012		Change			2013		2012		Change
Heating degree days		117.6		152.3		(22.8	)		2,264.1		1,663.0		36.1
Cooling degree days		282.4		359.9		(21.5	)		282.4		359.9		(21.5	)

Power Supply Resources

We provide power to our members through a combination of our interests in Clover, a coal-fired generating facility; North Anna, a nuclear power station; 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 energy in the open market. Our energy supply resources for the three and six months ended June 30, 2013 and 2012, were as follows:


	Three Months Ended June 30,								Six Months Ended June 30,
	2013				2012				2013				2012
	(in MWh and percentages)								(in MWh and percentages)
Generated:
Clover		694,721	24.6	%		373,838	13.4	%		1,444,552	22.5	%		1,081,149	17.8	%
North Anna		356,918	12.7			402,941	14.4			848,122	13.2			829,059	13.7
Louisa		20,148	0.7			18,473	0.7			37,568	0.6			31,946	0.5
Marsh Run		38,947	1.4			30,819	1.1			64,484	1.0			61,510	1.0
Rock Springs		15,461	0.5			18,574	0.7			15,461	0.3			18,574	0.3
Distributed Generation		11	—			170	—			34	—			173	—

Total Generated		1,126,206	39.9			844,815	30.3			2,410,221	37.6			2,022,411	33.3

Purchased:
Other than renewable		1,506,088	53.4			1,848,678	66.3			3,577,062	55.7			3,805,900	62.6
Renewable ⁽¹⁾		189,097	6.7			96,340	3.4			428,084	6.7			248,682	4.1

Total Purchased		1,695,185	60.1			1,945,018	69.7			4,005,146	62.4			4,054,582	66.7

Total Available Energy		2,821,391	100.0	%		2,789,833	100.0	%		6,415,367	100.0	%		6,076,993	100.0	%

⁽¹⁾	Related to our contracts from renewable facilities from which we purchase renewable energy credits. We sell these renewable energy credits to our member distribution cooperatives and 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, are dispatched only when the market price of energy makes their operation economical or when their operation is required by PJM for system reliability purposes. For further discussion on PJM, see “Business—Power Supply Resources—PJM” in Item 1 of our 2012 Annual Report on Form 10-K. Owners of power plants incur the fixed costs of these facilities whether or not the units operate.

As previously mentioned, our generating facilities are under dispatch control of PJM. Typically, nuclear facilities are almost always dispatched and coal-fired and combustion turbine facilities are dispatched based upon economic factors including the market price of energy. The operational availability of our owned generating resources for the three and six months ended June 30, 2013 and 2012, was as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Clover		91.4	%		56.0	%		95.7	%		77.2	%
North Anna		74.7			83.2			87.3			85.6
Louisa		99.3			99.4			99.2			99.4
Marsh Run		99.9			99.8			99.1			99.8
Rock Springs		100.0			99.8			98.1			94.4

The output of Clover and North Anna for the three and six months ended June 30, 2013 and 2012 as a percentage of maximum dependable capacity rating of the facilities was as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Clover		73.6	%		40.2	%		76.9	%		57.7	%
North Anna		74.6			84.3			89.0			87.5

The scheduled and unscheduled outages for Clover and North Anna for the three and six months ended June 30, 2013 and 2012, were as follows:


	Clover								North Anna
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012		2013		2012		2013		2012
	(in days)								(in days)
Scheduled		15.7		61.0		15.7		62.0		32.5		15.0		32.5		36.0
Unscheduled		—		19.1		—		22.0		14.1		15.2		14.1		15.9

Total		15.7		80.1		15.7		84.0		46.6		30.2		46.6		51.9

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’ customers’ requirements for power. Our formulary rate is based on our cost of service in meeting these requirements. See “Factors Affecting Results—Formulary Rate” above.

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; however, in 2013 and 2012, TEC had no sales to third parties.

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. Sales to non-members also include the sale of renewable energy credits that are not sold to our member distribution cooperatives.

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 six months ended June 30, 2013 and 2012, were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Revenues from sales to:
Member distribution cooperatives
Base energy revenues	$	46,526	$	46,573	$	107,206	$	100,022
Energy adjustment revenues		59,614		70,936		140,753		158,731

Total energy revenues		106,140		117,509		247,959		258,753
Demand (capacity) revenues		74,979		77,865		148,962		153,655

Total revenues from sales to member distribution cooperatives		181,119		195,374		396,921		412,408
Non-members		6,504		2,906		11,415		8,299

Total operating revenues	$	187,623	$	198,280	$	408,336	$	420,707

Average cost of energy to member distribution cooperatives (per MWh)	$	39.88	$	43.74	$	40.46	$	44.90
Average cost of demand to member distribution cooperatives (per MWh)		28.18		28.98		24.30		26.66

Average total cost to member distribution cooperatives (per MWh)	$	68.06	$	72.72	$	64.76	$	71.56

Our energy sales in MWh to our member distribution cooperatives and non-members, and demand sales in MW to our member distribution cooperatives for the three and six months ended June 30, 2013 and 2012, were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in MWh)				(in MWh)
Energy sales to:
Member distribution cooperatives		2,661,125		2,686,657		6,128,672		5,762,923
Non-members		163,434		96,392		266,127		283,491

Total energy sales		2,824,559		2,783,049		6,394,799		6,046,414


	(in MW)				(in MW)
Demand sales to Member distribution cooperatives		5,461		5,638		12,299		12,088

Our energy sales in MWh and demand sales in MW are driven by our member distribution cooperatives requirements for power. For the three months ended June 30, 2013, MWh and MW sales were 1.0% and 3.1% lower, respectively, as compared to the same period in 2012. For the six months ended June 30, 2013, MWh and MW sales were 6.3% and 1.7% higher, respectively, as compared to the same period in 2012. In 2012, we experienced milder than normal weather.

Our energy sales in MWh to non-members for the three months ended June 30, 2013, were 69.6% higher, whereas for the six months ended June 30, 2013, they were 6.1% lower, as compared to the same periods in 2012. Sales to non-members consist of sales of excess purchased and generated energy and renewable energy credits.

Total revenues from sales to our member distribution cooperatives for the three and six months ended June 30, 2013, decreased $14.3 million, or 7.3%, and $15.5 million, or 3.8%, respectively, as compared to the same periods in 2012. Our average cost of energy to member distribution cooperatives per MWh decreased 8.8% and 9.9% for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012, primarily due to decreases in our energy adjustment rate.

The average total cost to member distribution cooperatives is affected by changes in the revenue dollars as well as the sales volumes. Our average total cost to member distribution cooperatives per MWh for the three and six months ended June 30, 2013, decreased $4.66 per MWh, or 6.4%, and $6.80 per MWh, or 9.5%, respectively, as compared to the same periods in 2012, primarily as a result of decreases in our total energy rate. Additionally, capacity related revenues for the six months ended June 30, 2013, decreased 3.1%, while our MWh volume increased 6.3%, resulting in a lower average cost of demand on a per MWh basis.

The following table summarizes the changes to our total energy rate as a result of changes to our energy adjustment rate due to the continued reduction in our realized as well as projected energy costs:


Effective Date of Rate Change	% Change
April 1, 2012		(4.6	)
October 1, 2012		(6.8	)
April 1, 2013		(2.4	)

Non-member revenue for the three and six months ended June 30, 2013, increased $3.6 million, or 123.8%, and $3.1 million, or 37.5%, respectively, as compared to the same periods in 2012. For the three months ended June 30, 2013, there was a 69.6% increase in the volume of excess energy sales as well as an increase in the average price. For the six months ended June 30, 2013, the increase in the average price was slightly offset by the 6.1% decrease in volume of excess energy sales.

Operating Expenses

The following is a summary of the components of our operating expenses for the three and six months ended June 30, 2013 and 2012:


	Three Months Ended June 30,					Six Months Ended June 30,
	2013			2012		2013			2012
	(in thousands)					(in thousands)
Fuel	$	30,317		$	19,263	$	61,769		$	46,797
Purchased power		118,007			119,654		266,659			257,198
Deferred energy		(11,280	)		5,989		(18,030	)		15,413
Operations and maintenance		11,774			15,193		19,860			25,456
Administrative and general		10,655			9,863		21,447			18,988
Depreciation and amortization		10,569			10,468		21,209			20,844
Amortization of regulatory asset/(liability), net		1,272			973		1,584			1,717
Accretion of asset retirement obligations		995			940		1,990			1,858
Taxes, other than income taxes		2,184			2,089		4,416			4,223

Total Operating Expenses	$	174,493		$	184,432	$	380,904		$	392,494

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 demand costs generally are fixed and include operations and maintenance, administrative and general, and depreciation and amortization expenses, as well as the capacity portion of our purchased power expense. Additionally, all non-operating expenses and income items, including interest charges, net and investment income, are components of our demand costs. See “Factors Affecting Results—Formulary Rate” above.

Total operating expenses decreased $9.9 million, or 5.4%, and $11.6 million, or 3.0%, for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012, primarily due to decreases in deferred energy and operations and maintenance expenses partially offset by an increase in fuel expense.

•

Deferred energy expense decreased $17.3 million and $33.4 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. For the three and six months ended June 30, 2013, we under-collected $11.3 million and $18.0 million, respectively, in energy costs; whereas for the same periods in 2012, we over-collected $6.0 million and $15.4 million, respectively, in energy costs. Our deferred energy balance was a net over-collection of energy costs of $56.0 million at December 31, 2012, as compared to a net over-collection of energy costs of $38.0 million at June 30, 2013.

•

Operations and maintenance expense decreased $3.4 million, or 22.5%, and $5.6 million, or 22.0%, for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. There were more outages at Clover in 2012 as compared to 2013.

•

Fuel expense increased $11.1 million, or 57.4%, and $15.0 million, or 32.0%, for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The increase for the three and six months was primarily due to the increased operational availability and dispatch of Clover.

Other Items

Investment Income

Investment income increased for the three months ended June 30, 2013, by $0.3 million, or 22.1%, as compared to the same period in 2012, primarily due to higher income earned on our nuclear decommissioning trust. Investment income was relatively flat for the six months ended June 30, 2013, as compared to the same period in 2012.

Interest Charges, Net

The major components of interest charges, net for the three and six months ended June 30, 2013 and 2012, were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)						(in thousands)
Interest expense on long-term debt	$	(11,516	)	$	(12,151	)	$	(23,244	)	$	(24,292	)
Other		(220	)		(330	)		(419	)		(766	)

Total Interest Charges		(11,736	)		(12,481	)		(23,663	)		(25,058	)
Allowance for borrowed funds used during construction		51			347			83			613

Interest Charges, net	$	(11,685	)	$	(12,134	)	$	(23,580	)	$	(24,445	)

Interest expense on long-term debt decreased for the three and six months ended June 30, 2013, by $0.6 million, or 5.2%, and $1.0 million, or 4.3%, respectively, as compared to the same periods in 2012, primarily due to the redemption of our $60.2 million 2002 Series A bonds and scheduled principal payments.

Net Margin Attributable to ODEC

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 for the three and six months ended June 30, 2013, by $0.2 million, or 6.1%, and $0.3 million, or 5.6%, respectively, as compared to the same periods in 2012.

Financial Condition

The principal changes in our financial condition from December 31, 2012 to June 30, 2013, were caused by an increase in long-term debt, substantially offset by decreases in accounts payable, deferred energy, accounts receivable–members, and fuel, materials, and supplies.

•

Long-term debt increased $39.8 million as a result of the issuance of $100.0 million of first mortgage bonds on June 28, 2013, partially offset by the redemption of $60.2 million 2002 Series A bonds on June 1, 2013.

•

Accounts payable decreased $22.4 million primarily due to the decrease in the amounts due to Virginia Electric and Power Company in connection with our ownership interests in Clover and North Anna.

•

Deferred energy decreased $18.0 million as a result of the under-collection of our energy costs in 2013.

•

Accounts receivable–members decreased $15.0 million due to decreases in member power bill extensions as well as sales to member distribution cooperatives in June 2013 as compared to December 2012.

•

Fuel, materials, and supplies decreased $11.0 million due to the decrease in coal inventory related to a planned coal inventory reduction at Clover.

Liquidity and Capital Resources

Sources

Cash generated by our operations, periodic borrowings under our credit facility, and occasional issuances of long-term indebtedness provide our sources of liquidity and capital.

Operations

During the first six months of 2013 and 2012, our operating activities provided cash flows of $15.3 million and $3.5 million, respectively. Operating activities in 2013 were primarily impacted by the following:

•

Current assets changed $26.8 million primarily due to the $15.0 million decrease in accounts receivable–members and the $11.0 million decrease in fuel, materials, and supplies.

•

Deferred energy changed $18.0 million due to the under-collection of energy costs in 2013.

•

Current liabilities changed $17.9 million primarily due to the $22.4 million decrease in accounts payable.

•

Regulatory assets and liabilities changed $12.1 million substantially due to the establishment of a regulatory asset related to the voluntary prepayment of $7.7 million to the NRECA Retirement Security Plan, a noncontributory, defined benefit multiple employer master pension plan. We recorded this prepayment as a regulatory asset which will be amortized over the next ten years beginning January 1, 2013.

Credit Facility

We currently maintain a $500.0 million, five-year revolving credit facility to cover our short-term and medium-term funding needs. At June 30, 2013 and December 31, 2012, we did not have any borrowings outstanding under this facility.

Financings

We fund the portion of our capital expenditures that we are not able to fund from operations through financings in the debt capital markets. These capital expenditures consist primarily of the costs related to the development, construction, acquisition, or improvement of our owned generating facilities.

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 syndicated credit facility, and potential long-term borrowings will be sufficient to meet our currently anticipated operational and capital requirements.

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the second quarter of 2013.

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.

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 2012 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

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

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: August 8, 2013						/s/ Robert L. Kees
						Robert L. Kees
						Senior Vice President and Chief Financial Officer
						(Principal financial officer)

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

Larger accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company