Old Dominion Electric Cooperative 10Q 2014 Q1 Quarterly report

Old Dominion Electric Cooperative 10-Q2014 Q1 Quarterly report

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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 March 31, 2014

¨	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

Alstom		Alstom Power, Inc.
Bear Island		Bear Island Paper WB LLC
Clover		Clover Power Station
CPCN		Certificate of Public Convenience and Necessity
EPC		Engineering, procurement, and construction
FERC		Federal Energy Regulatory Commission
GAAP		Accounting principles generally accepted in the United States
Mitsubishi		Mitsubishi Power Systems Americas, Inc.
MPSC		Maryland Public Service Commission
MW		Megawatt(s)
MWh		Megawatt hour(s)
North Anna		North Anna Nuclear Power Station
ODEC, We, Our		Old Dominion Electric Cooperative
PJM		PJM Interconnection, LLC
REC		Rappahannock Electric Cooperative
RFP		Request for proposal
RTO		Regional transmission organization
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 – March 31, 2014 (unaudited) and December 31, 2013		4

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (unaudited) – Three Months Ended March 31, 2014 and 2013		5

Condensed Consolidated Statements of Cash Flows (unaudited) – Three Months Ended March 31, 2014 and 2013		6

Notes to Condensed Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		13

Item 3. Quantitative and Qualitative Disclosures About Market Risk		21

Item 4. Controls and Procedures		21

PART II. Other Information

Item 1. Legal Proceedings		22

Item 1A. Risk Factors		22

Item 5. Other Information		22

Item 6. Exhibits		23

OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31,			December 31,
	2014			2013
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	1,661,308		$	1,660,548
Less accumulated depreciation		(765,146	)		(755,288	)

		896,162			905,260
Nuclear fuel, at amortized cost		20,231			23,636
Construction work in progress		50,515			36,482

Net Electric Plant		966,908			965,378

Investments:
Nuclear decommissioning trust		137,450			134,454
Lease deposits		97,332			96,634
Unrestricted investments and other		26,702			24,896

Total Investments		261,484			255,984

Current Assets:
Cash and cash equivalents		1,913			51,669
Accounts receivable		10,580			12,742
Accounts receivable–deposits		4,400			4,400
Accounts receivable–members		81,969			88,545
Fuel, materials, and supplies		54,969			49,246
Deferred energy		56,236			—
Prepayments and other		3,498			3,892

Total Current Assets		213,565			210,494

Deferred Charges:
Regulatory assets		86,610			87,983
Other		10,937			10,758

Total Deferred Charges		97,547			98,741

Total Assets	$	1,539,504		$	1,530,597


CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	372,307		$	369,997
Non-controlling interest		5,687			5,691

Total Patronage capital and Non-controlling interest		377,994			375,688
Long-term debt		749,330			749,330

Total Capitalization		1,127,324			1,125,018

Current Liabilities:
Long-term debt due within one year		28,292			28,292
Accounts payable		97,188			68,560
Accounts payable–members		26,432			24,998
Accrued expenses		17,275			4,991
Deferred energy		—			37,193

Total Current Liabilities		169,187			164,034

Deferred Credits and Other Liabilities:
Asset retirement obligations		81,879			80,860
Obligations under long-term lease		80,600			79,227
Regulatory liabilities		76,255			76,940
Other		4,259			4,518

Total Deferred Credits and Other Liabilities		242,993			241,545

Commitments and Contingencies		—			—

Total Capitalization and Liabilities	$	1,539,504		$	1,530,597

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
	March 31,
	2014			2013
	(in thousands)
Operating Revenues	$	265,096		$	220,713


Operating Expenses:
Fuel		115,529			31,452
Purchased power		189,365			148,652
Deferred energy		(93,429	)		(6,750	)
Operations and maintenance		14,546			8,086
Administrative and general		11,362			10,792
Depreciation and amortization		10,506			10,640
Amortization of regulatory asset/(liability), net		1,833			312
Accretion of asset retirement obligations		1,019			995
Taxes, other than income taxes		2,171			2,232

Total Operating Expenses		252,902			206,411

Operating Margin		12,194			14,302
Other expense, net		(713	)		(653	)
Investment income		2,195			658
Interest charges, net		(11,371	)		(11,895	)
Income taxes		1			(5	)

Net Margin including Non-controlling interest		2,306			2,407
Non-controlling interest		4			(21	)

Net Margin attributable to ODEC		2,310			2,386
Patronage Capital - Beginning of Period		369,997			360,424

Patronage Capital - End of Period	$	372,307		$	362,810

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Three Months Ended
	March 31,
	2014			2013
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	2,306		$	2,407
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		10,506			10,640
Other non-cash charges		4,589			5,602
Amortization of lease obligations		1,372			1,282
Interest on lease deposits		(698	)		(681	)
Change in current assets		3,409			30,136
Change in deferred energy		(93,429	)		(6,750	)
Change in current liabilities		42,346			(2,856	)
Change in regulatory assets and liabilities		(172	)		(1,724	)
Change in deferred charges and credits		(169	)		221

Net Cash (Used for) Provided by Operating Activities		(29,940	)		38,277


Investing Activities:
Purchases of held to maturity securities		(2,000	)		—
Proceeds from sale of held to maturity securities		—			250
Increase in other investments		(1,940	)		(557	)
Electric plant additions		(15,876	)		(5,545	)

Net Cash Used for Investing Activities		(19,816	)		(5,852	)


Financing Activities:

Net Cash Provided by Financing Activities		—			—


Net Change in Cash and Cash Equivalents		(49,756	)		32,425
Cash and Cash Equivalents - Beginning of Period		51,669			37,343

Cash and Cash Equivalents - End of Period	$	1,913		$	69,768

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 March 31, 2014, our consolidated results of operations for the three months ended March 31, 2014 and 2013, and cash flows for the three months ended March 31, 2014 and 2013. The consolidated results of operations for the three months ended March 31, 2014, 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 2013 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 $5.7 million at March 31, 2014 and December 31, 2013. 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. See Note 5–Other–FERC Proceeding Related to Formula Rate below.

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 March 31, 2014 and December 31, 2013:


	March 31, 2014		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⁾⁽²⁾	$	137,450	$	43,713	$	93,737	$	—
Unrestricted investments and other⁽³⁾		175		175		—		—
Derivatives - gas and power⁽⁴⁾		798		798		—		—

Total Financial Assets	$	138,423	$	44,686	$	93,737	$	—


	December 31, 2013		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⁾⁽²⁾	$	134,454	$	42,661	$	91,793	$	—
Unrestricted investments and other⁽³⁾		173		173		—		—
Derivatives - gas and power⁽⁴⁾		412		412		—		—

Total Financial Assets	$	135,039	$	43,246	$	91,793	$	—

⁽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 related to equity securities.

⁽⁴⁾

Derivatives – gas and power represent natural gas futures contracts and purchased power contracts, which are recorded on our Condensed Consolidated Balance Sheet in deferred charges–other, and 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 2013 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 price risk by purchasing power to supply the power requirements of our member distribution cooperatives that are not met by our owned generation. In addition, the purchase of fuel to operate our generating facilities also exposes us to market price risk. To manage this exposure, we utilize derivative instruments. See Note 1 of the Notes to Consolidated Financial Statements in our 2013 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:


Commodity	Unit of Measure	As of March 31, 2014 Quantity		As of December 31, 2013 Quantity
Natural Gas	MMBTU		2,330,000		1,470,000

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


		Fair Value
	Balance Sheet Location	As of March 31, 2014		As of December 31, 2013
		(in thousands)
Derivatives in an asset position:
Natural gas futures contracts	Deferred charges-other	$	798	$	412

Total derivatives in an asset position		$	798	$	412

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Three Months Ended March 31, 2014 and 2013


Derivatives Accounted for Utilizing Regulatory Accounting	Amount of Gain (Loss) Recognized in Regulatory Asset/Liability for Derivatives as of March 31,					Location of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income	Amount of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income for the Three Months Ended March 31,
	2014		2013				2014		2013
	(in thousands)						(in thousands)
Natural gas futures contracts⁽¹⁾	$	810	$	(1,910	)	Fuel	$	39	$	(41	)

Total	$	810	$	(1,910	)		$	39	$	(41	)

⁽¹⁾	As of March 31, 2014 and 2013, includes a regulatory asset of $11,500 and $1.7 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 March 31, 2014 and December 31, 2013:


Description	Designation	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value		Carrying Value
		(in thousands)
March 31, 2014

Nuclear decommissioning trust⁽¹⁾
Debt securities	Available for sale	$	40,665	$	2,505	$	—		$	43,170	$	43,170
Equity securities	Available for sale		64,163		29,574		—			93,737		93,737
Cash and other	Available for sale		543		—		—			543		543

Total Nuclear Decommissioning Trust		$	105,371	$	32,079	$	—		$	137,450	$	137,450


Lease Deposits⁽³⁾
Government obligations	Held to maturity	$	97,332	$	5,713	$	—		$	103,045	$	97,332

Total Lease Deposits		$	97,332	$	5,713	$	—		$	103,045	$	97,332


Unrestricted investments
Government obligations	Held to maturity	$	22,078	$	2	$	(8	)	$	22,072	$	22,078
Debt securities	Held to maturity		2,200		—		(1	)		2,199		2,200

Total Unrestricted Investments		$	24,278	$	2	$	(9	)	$	24,271	$	24,278


Other
Equity securities	Trading	$	131	$	44	$	—		$	175	$	175
Non-marketable equity investments	Equity		2,249		1,770		—			4,019		2,249

Total Other		$	2,380	$	1,814	$	—		$	4,194	$	2,424

											$	261,484

December 31, 2013

Nuclear decommissioning trust⁽¹⁾⁽²⁾
Debt securities	Available for sale	$	40,352	$	1,719	$	—		$	42,071	$	42,071
Equity securities	Available for sale		62,293		29,500		—			91,793		91,793
Cash and other	Available for sale		590		—		—			590		590

Total Nuclear Decommissioning Trust		$	103,235	$	31,219	$	—		$	134,454	$	134,454


Lease Deposits⁽³⁾
Government obligations	Held to maturity	$	96,634	$	5,676	$	—		$	102,310	$	96,634

Total Lease Deposits		$	96,634	$	5,676	$	— ��		$	102,310	$	96,634


Unrestricted investments
Government obligations	Held to maturity	$	20,174	$	1	$	—		$	20,175	$	20,174
Debt securities	Held to maturity		2,200		—		(4	)		2,196		2,200

Total Unrestricted Investments		$	22,374	$	1	$	(4	)	$	22,371	$	22,374


Other
Equity securities	Trading	$	131	$	42	$	—		$	173	$	173
Non-marketable equity investments	Equity		2,349		1,735		—			4,084		2,349

Total Other		$	2,480	$	1,777	$	—		$	4,257	$	2,522

											$	255,984

⁽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 2013 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⁾	In the fourth quarter of 2013 we rebalanced our portfolio in the nuclear decommissioning trust.

⁽³⁾	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 2013 Annual Report on Form 10-K.

Our investments by classification at March 31, 2014 and December 31, 2013, were as follows:


	March 31, 2014				December 31, 2013
Description	Cost		Carrying Value		Cost		Carrying Value
	(in thousands)
Available for sale	$	105,371	$	137,450	$	103,235	$	134,454
Held to maturity		121,610		121,610		119,008		119,008
Equity		2,249		2,249		2,349		2,349
Trading		131		175		131		173

	$	229,361	$	261,484	$	224,723	$	255,984

Contractual maturities of debt securities at March 31, 2014, were as follows:


Description	Less than 1 year		1-5 years		5-10 years		More than 10 years		Total
	(in thousands)
Available for sale⁽¹⁾	$	—	$	—	$	43,170	$	—	$	43,170
Held to maturity		21,830		99,541		239		—		121,610

	$	21,830	$	99,541	$	43,409	$	—	$	164,780

⁽¹⁾	The contractual maturities of available for sale debt securities are measured using the effective duration of the bond fund within the nuclear decommissioning trust.

Other

Margin Stabilization

Margin Stabilization allows us to review our actual demand-related costs of service and demand 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 formula rate allows us to recover and refund amounts utilizing Margin Stabilization. Pursuant to FERC’s acceptance of the revisions to the formula rate as issued in FERC’s December 2, 2013 order (see “FERC Proceeding Related to Formula Rate” below), effective January 1, 2014:

•

At year end, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 20% of our actual total interest charges, our board of directors may approve that, utilizing Margin Stabilization, revenues will be reduced by the amount of such excess margins, or that such excess margins will be retained as an additional equity contribution. For year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 20% of our actual total interest charges, utilizing Margin Stabilization, revenues will be reduced by the amount of such excess margins.

•

At year end and for year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 10% but less than 20% of our actual total interest charges, no adjustment is required.

•

At year end and for year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals less than 10% of our actual total interest charges, utilizing Margin Stabilization, revenues will be increased to produce a net margin attributable to ODEC, excluding any budgeted additional equity contributions, equal to 10% of our actual total interest charges.

As of March 31, 2014 and 2013, we recorded a reduction in operating revenues of $7.0 million and $14.8 million, respectively, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges.

First Quarter 2014 Results and the Impact on Deferred Energy

Deferred energy expense represents the difference between energy revenues, which are based upon energy rates approved by our board, and energy expenses, which are based upon actual energy costs incurred. In the three months ended March 31, 2014, we under-collected energy costs from our member distribution cooperatives by $93.4 million, which was recorded as deferred energy expense. As a result, our deferred energy balance changed from an over-collection of $37.2 million at December 31, 2013, to an under-collection of $56.2 million at March 31, 2014. In the first quarter of 2014, the entire mid-Atlantic region experienced extremely cold weather, which increased our energy sales in MWh to our member distribution cooperatives 10.2% over the expected requirements, and which had a significant effect on our fuel and purchased power costs. As a result, our average energy cost, net of excess energy sales, was $66.85 per MWh as compared to our average energy rate of $42.22 per MWh. The significant increase in our average energy cost was primarily driven by the $84.1 million increase in fuel expense and the $40.7 million increase in purchased power expense. The increase in fuel expense was primarily impacted by the 642.3% increase in the dispatch of our combustion turbine facilities as well as the 278.4% increase in the average cost of fuel for our combustion turbine facilities. The increase in purchased power expense was driven by the 20.6% increase in the average cost of purchased energy and the 8.3% increase in the volume of purchased energy. To address the under-collection of energy costs, we increased our total energy rate 11.8% effective April 1, 2014.

Wildcat Point Generation Facility

On April 23, 2013, we announced our intention to seek approval to develop and construct a 1,000 MW natural gas-fueled generation facility, named Wildcat Point, in Cecil County, Maryland. The development, construction, and operation of Wildcat Point are subject to obtainment of necessary governmental and regulatory approvals and our board’s approval of an EPC contractor. On May 20, 2013, we applied to the MPSC for a CPCN. On March 24, 2014, the MPSC issued a Proposed Order granting the CPCN; the Proposed Order became a Final Order on April 8, 2014. We continue to pursue other necessary permits and contracts related to the development and construction of the facility. We anticipate construction will begin in late 2014, and the facility will become operational in mid-2017.

Wildcat Point will consist of two combustion turbines, two heat recovery steam generators and one steam turbine generator. Mitsubishi will supply the combustion turbines and Alstom will supply the heat recovery steam generators and the steam turbine generator. In the fourth quarter of 2013, we issued an RFP for potential EPC contractors to construct Wildcat Point. We are currently evaluating the responses to the RFP and anticipate recommending an EPC contractor to our board of directors for approval mid-2014. For the three months ended March 31, 2014 and 2013, we expensed $1.8 million and $1.0 million, respectively, of preconstruction costs related to Wildcat Point, which are recorded in administrative and general expense. Through March 31, 2014, we capitalized progress payments for major equipment, emission reduction credits, and land rights totaling $11.8 million, which are recorded in construction work in progress.

FERC Proceeding Related to Formula Rate

On September 30, 2013, we filed with FERC to revise our cost-based formula rate to more closely align our cost recovery from our member distribution cooperatives with the methodologies used by PJM to allocate costs to us. On November 8, 2013, Bear Island, a customer of REC, filed a motion to intervene, protest, and request for hearing. On December 2, 2013, FERC issued its order accepting the proposed revisions for filing to become effective January 1, 2014, subject to refund, and establishing hearing and settlement procedures. We are currently in settlement discussions with Bear Island, the results of which cannot currently be determined.

Recovery of Costs from PJM

We are seeking recovery from PJM of unreimbursed costs totaling approximately $19.0 million which were incurred during the first quarter of 2014 related to the dispatch of our combustion turbine generating facilities. The results of our efforts cannot currently be determined.

Short-term Borrowings

We currently maintain a $500.0 million, five-year revolving credit facility to cover our short-term and medium-term funding needs. Commitments under this syndicated credit agreement extend until March 5, 2019, unless earlier terminated in accordance with the agreement. At March 31, 2014 and December 31, 2013, we did not have any borrowings outstanding under this facility. On May 9, 2014, we had a letter of credit related to Wildcat Point in the amount of $51.7 million issued under this facility.

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 March 31, 2014, there have been no significant changes in our critical accounting policies as disclosed in our 2013 Annual Report on Form 10-K. These policies include the accounting for rate regulation, deferred energy, margin stabilization, 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.

In the first quarter of 2014, the entire mid-Atlantic region experienced extremely cold weather, which increased our energy sales in MWh to our member distribution cooperatives 10.2% over the expected requirements, and which had a significant effect on our fuel and purchased power costs. As a result, our average energy cost, net of excess energy sales, was $66.85 per MWh as compared to our average energy rate of $42.22 per MWh. The significant increase in our average energy cost was primarily driven by the $84.1 million increase in fuel expense and the $40.7 million increase in purchased power expense. The increase in fuel expense was primarily impacted by the 642.3% increase in the dispatch of our combustion turbine facilities as well as the 278.4% increase in the average cost of fuel for our combustion turbine facilities. The increase in purchased power expense was driven by the 20.6% increase in the average cost of purchased energy and the 8.3% increase in the volume of purchased energy. In the three months ended March 31, 2014, we under-collected energy costs from our member distribution cooperatives by $93.4 million, which we recorded as deferred energy expense. As a result, our deferred energy balance, which represents the cumulative difference between energy revenues and energy expenses, changed from an over-collection of $37.2 million at December 31, 2013, to an under-collection of $56.2 million at March 31, 2014. To address the under-collection of energy costs, we increased our total energy rate 11.8% effective April 1, 2014. 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 2013 Annual Report on Form 10-K.

Wildcat Point Generation Facility

contractor. On May 20, 2013, we applied to the MPSC for a CPCN. On March 24, 2014, the MPSC issued a Proposed Order granting the CPCN; the Proposed Order became a Final Order on April 8, 2014. We continue to pursue other necessary permits and contracts related to the development and construction of the facility. We anticipate construction will begin in late 2014, and the facility will become operational in mid-2017.

Factors Affecting Results

Formula 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 at any time is referred to as demand.

The rates we charge our member distribution cooperatives for sales of energy and demand are determined by a formula 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 formula 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.

Energy costs, which are primarily variable costs, such as nuclear, coal, and natural gas fuel costs and the energy costs under our power purchase contracts with third parties, are recovered through two separate rates, the base energy rate and the energy adjustment rate. Through December 31, 2013, the base energy rate was a fixed rate that required FERC approval prior to adjustment. To the extent the base energy rate over- or under-collected our energy costs, we refunded or collected the difference through an energy adjustment rate. We reviewed our energy costs at least every six months to determine whether the base energy rate and the current energy adjustment rate together were recovering our actual and anticipated energy costs, and revised the energy adjustment rate accordingly. Effective January 1, 2014, pursuant to FERC’s acceptance of revisions to the formula rate as issued in FERC’s December 2, 2013 order; the base energy rate is no longer a fixed rate that requires FERC approval prior to adjustment. The base energy rate now will be developed annually to collect energy costs as estimated in our budget including amounts in the deferred energy account from the prior year. As of January 1 of each year, the energy adjustment rate will be zero. With board approval, we can revise the energy adjustment rate at any time during the year if it becomes apparent that the combined base energy rate and the current energy adjustment rate are over-collecting or under-collecting our actual and anticipated energy costs. See “FERC Proceeding Related to Formula Rate” in Part II, Item 1 below.

Demand costs, which are primarily fixed costs, such as depreciation expense, interest expense, administrative and general expenses, capacity costs under power purchase contracts with third parties, transmission costs, and our margin requirements and additional equity contributions approved by our board of directors are recovered through our demand rates. The formula rate allows us to change the actual demand rates we charge as our demand-related costs change, without FERC approval, with the exception of decommissioning cost, which is a fixed number in the formula rate that requires FERC approval prior to any adjustment. FERC approval is also needed to change account classifications currently in the formula or to add accounts not otherwise included in the current formula. Additionally, depreciation studies are required to be filed with FERC for its approval if they would result in a change in our depreciation rates. Through December 31, 2013, we collected our total demand costs through a single demand rate. Effective January 1, 2014, pursuant to FERC’s acceptance of the revisions to the formula rate as issued in FERC’s December 2, 2013 order, we now collect our total demand costs through the following three separate rates.

•

Transmission service rate – designed to collect transmission-related and distribution-related costs

•

RTO capacity service rate – a proxy rate based on capacity prices in PJM which PJM allocates to ODEC and all other RTO members

•

Remaining owned capacity service rate – recovers all remaining demand costs not billed and/or recovered under the transmission service and RTO capacity service rates

As stated above, our margin requirements and additional equity contributions approved by our board of directors are recovered through our demand rates. We establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges plus additional equity contributions approved by our board of directors. Through December 31, 2013, utilizing Margin Stabilization, we adjusted our operating revenues to reflect actual demand costs incurred, including a net margin attributable to ODEC equal to 20% of actual interest charges plus additional equity contributions approved by our board of directors. Effective January 1, 2014:

•

Weather

Weather is one factor that affects the demand for electricity. 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 and cooling degree data is compiled utilizing various weather stations. Weather stations can be added or changed during the year, which may result in updates to previously reported data. The heating degree days and cooling degree days for the three months ended March 31, 2014 and 2013, were as follows:


	Three Months Ended March 31,				% Change
	2014		2013		% Change
Heating degree days		2,431		2,147		13.2
Cooling degree days		—		—		—

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 market energy purchases. Our energy supply resources for the three months ended March 31, 2014 and 2013, were as follows:


	Three Months Ended March 31,
	2014					2013
	(in MWh and percentages)
Generated:					��
Clover		686,752	17.2	%			749,831	20.8	%
North Anna		485,317	12.2				491,204	13.7
Louisa		121,369	3.0				17,420	0.5
Marsh Run		170,606	4.3				25,537	0.7
Rock Springs		26,875	0.7				—	—
Distributed Generation		1,939	—				23	—

Total Generated		1,492,858	37.4				1,284,015	35.7
Purchased:
Other than renewable:
Long-term and short term		1,879,230	47.1				1,735,653	48.3
Spot market		381,025	9.5				335,321	9.3

Total Other than renewable		2,260,255	56.6				2,070,974	57.6

Renewable⁽¹⁾		240,454	6.0				238,987	6.7

Total Purchased		2,500,709	62.6				2,309,961	64.3

Total Available Energy		3,993,567	100.0	%			3,593,976	100.0	%

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 2013 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, and to meet reliability requirements. The operational availability of our owned generating resources for the three months ended March 31, 2014 and 2013, was as follows:


	Three Months Ended March 31,
	2014			2013
Clover		78.9	%		100.0	%
North Anna		99.3			100.0
Louisa		99.5			99.1
Marsh Run		99.7			98.2
Rock Springs		98.8			96.1

The output of Clover and North Anna for the three months ended March 31, 2014 and 2013 as a percentage of maximum dependable capacity rating of the facilities was as follows:


	Three Months Ended March 31,
	2014			2013
Clover		73.4	%		80.2	%
North Anna		102.4			103.7

The scheduled and unscheduled outages for Clover and North Anna for the three months ended March 31, 2014 and 2013 were as follows:


	Clover Three Months Ended March 31,				North Anna Three Months Ended March 31,
	2014		2013		2014		2013
	(in days)				(in days)
Scheduled		31.0		—		—		—
Unscheduled		6.9		—		1.3		—

Total		37.9		—		1.3		—

Sales to Member Distribution Cooperatives

Revenues from sales to our member distribution cooperatives are a function of our formula rate for sales of power and sales of renewable energy credits to our member distribution cooperatives, and our member distribution cooperatives’ customers’ requirements for power. Our formula rate is based on our cost of service in meeting these requirements. See “Factors Affecting Results—Formula 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 intercompany balances are eliminated in consolidation. TEC’s sales to third parties are reflected as non-member revenues; however, in 2014 and 2013, TEC had no sales to third parties.

Sales to Non-members

Sales to non-members consist of sales of excess purchased and generated energy and sales of renewable energy credits. 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, and changes in market conditions. Renewable energy credits that are not sold to our member distribution cooperatives are sold to non-members.

Results of Operations

Operating Revenues

Our operating revenues are derived from sales of power and renewable energy credits to our member distribution cooperatives and non-members. Our operating revenues by type of purchaser for the three months ended March 31, 2014 and 2013, were as follows:


	Three Months Ended March 31,
	2014		2013
	(in thousands)
Revenues from sales to:
Member distribution cooperatives
Energy revenues⁽¹⁾	$	160,184	$	141,819
Demand revenues		82,133		73,983

Total revenues from sales to member distribution cooperatives		242,317		215,802
Non-members⁽²⁾		22,779		4,911

Total operating revenues	$	265,096	$	220,713


Average cost of energy to member distribution cooperatives (per MWh)	$	42.22	$	40.90
Average cost of demand to member distribution cooperatives (per MWh)		21.65		21.33

Average total cost to member distribution cooperatives (per MWh)	$	63.87	$	62.23

⁽¹⁾	Includes sales of renewable energy credits that were immaterial for 2014 and zero for 2013.

⁽²⁾	Includes sales of renewable energy credits of $0.5 million and $1.2 million for 2014 and 2013, respectively.

Our energy sales in MWh to our member distribution cooperatives and non-members for the three months ended March 31, 2014 and 2013, were as follows:


	Three Months Ended March 31,
	2014		2013
	(in MWh)
Energy sales to:
Member distribution cooperatives		3,793,594		3,467,547
Non-members		169,863		102,693

Total energy sales		3,963,457		3,570,240

Our energy sales in MWh to our member distribution cooperatives for the three months ended March 31, 2014, were 9.4% higher as compared to the same period in 2013. In the first quarter of 2014, the entire mid-Atlantic region experienced extremely cold weather.

Our energy sales in MWh to non-members for the three months ended March 31, 2014, were 65.4% higher as compared to the same period in 2013, as the result of an increase in the volume of excess purchased and generated energy.

Total revenues from sales to our member distribution cooperatives for the three months ended March 31, 2014, increased $26.5 million, or 12.3%, as compared to the same period in 2013, primarily due to net increases in our total energy rate. Our average cost of energy to member distribution cooperatives per MWh increased 3.2% for the three months ended March 31, 2014, as compared to the same period in 2013.

The average total cost to member distribution cooperatives is affected by changes in our revenues as well as sales volumes. Our average total cost to member distribution cooperatives per MWh was 2.6% higher for the three months ended March 31, 2014, as compared to the same period in 2013, primarily as a result of net increases in our total energy rate.

The following table summarizes the changes to our total energy rate which were implemented to address the differences in our realized as well as projected energy costs:


Effective Date of Rate Change	% Change
April 1, 2013		(2.4	)
October 1, 2013		4.7
January 1, 2014		0.5
April 1, 2014		11.8

Non-member revenue for the three months ended March 31, 2014, increased $17.9 million, or 363.8%, as compared to the same period in 2013. For the three months ended March 31, 2014, there was a 180.4% increase in the average price as well as a 65.4% increase in the volume of excess energy sales.

Operating Expenses

The following is a summary of the components of our operating expenses for the three months ended March 31, 2014 and 2013:


	Three Months Ended March 31,
	2014			2013
	(in thousands)
Fuel	$	115,529		$	31,452
Purchased power		189,365			148,652
Deferred energy		(93,429	)		(6,750	)
Operations and maintenance		14,546			8,086
Administrative and general		11,362			10,792
Depreciation and amortization		10,506			10,640
Amortization of regulatory asset/(liability), net		1,833			312
Accretion of asset retirement obligations		1,019			995
Taxes, other than income taxes		2,171			2,232

Total Operating Expenses	$	252,902		$	206,411

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 the energy portion of our purchased power expense, fuel expense, and the variable portion of operations and maintenance expense. Our demand costs generally are fixed and include the fixed portion of operations and maintenance expense, 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—Formula Rate” above.

Total operating expenses increased $46.5 million, or 22.5%, for the three months ended March 31, 2014, as compared to the same period in 2013, primarily due to increases in fuel, purchased power, and operations and maintenance expenses, substantially offset by the decrease in deferred energy.

•

Fuel expense increased $84.1 million, or 267.3%. This increase was primarily driven by the 642.3% increase in the dispatch of our combustion turbine facilities as well as the 278.4% increase in the average cost of fuel for our combustion turbine facilities.

•

Purchased power expense, which includes the cost of purchased energy, capacity, and transmission, increased $40.7 million, or 27.4%. The average cost of purchased energy increased 20.6% and the volume of purchased energy increased 8.3%.

•

Operations and maintenance expense increased $6.5 million, or 79.9%, primarily due to a scheduled maintenance outage at Clover.

•

Deferred energy expense decreased $86.7 million. For the three months ended March 31, 2014 and 2013, we under-collected energy costs by $93.4 million and $6.8 million, respectively. Deferred energy expense represents the difference between energy revenues and energy expenses.

Other Items

Investment Income

Investment income increased for the three months ended March 31, 2014, by $1.5 million, or 233.6%, as compared to the same period in 2013, primarily due to higher income earned on our nuclear decommissioning trust.

Interest Charges, Net

The major components of interest charges, net for the three months ended March 31, 2014 and 2013, were as follows:


	Three Months Ended March 31,
	2014			2013
	(in thousands)
Interest expense on long-term debt	$	(11,370	)	$	(11,728	)
Other		(180	)		(199	)

Total Interest Charges		(11,550	)		(11,927	)
Allowance for borrowed funds used during construction		179			32

Interest Charges, net	$	(11,371	)	$	(11,895	)

Interest charges, net decreased $0.5 million, or 4.4% for the three months ended March 31, 2014, as compared to the same period in 2013, primarily due to the decrease in interest expense on long-term debt which was primarily the result of 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, was relatively flat for the three months ended March 31, 2014, as compared to the same period in 2013.

Financial Condition

The principal changes in our financial condition from December 31, 2013 to March 31, 2014, were caused by the change in deferred energy, the decrease in accounts receivable–members, and increases in accounts payable, accrued expenses, and fuel, materials, and supplies.

•

Deferred energy changed $93.4 million as a result of the under-collection of our energy costs in 2014. The deferred energy balance changed from a $37.2 million liability (over-collection) at December 31, 2013 to a $56.2 million asset (under-collection) at March 31, 2014.

•

Accounts receivable–members decreased $6.6 million due to the decrease in sales in March 2014 as compared to December 2013.

•

Accounts payable increased $28.6 million due to the increase in purchased power and natural gas purchases in March 2014 as compared to December 2013.

•

Accrued expenses increased $12.3 million primarily as a result of accrued interest on long-term debt.

•

Fuel, materials, and supplies increased $5.7 million due to the increase in fuel oil for our combustion turbine facilities and renewable energy credits.

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 three months of 2014, our operating activities used cash flows of $29.9 million and during the first three months of 2013, our operating activities provided cash flows of $38.3 million. Operating activities in 2014 were primarily impacted by the following:

•

Deferred energy changed $93.4 million due to the under-collection of energy costs in 2014. To address our under-collected deferred energy balance, we increased our total energy rate 11.8% effective April 1, 2014.

•

Current liabilities changed $42.3 million primarily due to the $28.6 million increase in accounts payable and the $12.3 million increase in accrued liabilities.

Credit Facility

Financings

We fund the portion of our capital expenditures that we are not able to fund from operations through borrowings under our revolving credit facility and 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 flow from our operations, borrowings under our revolving credit facility, and financings in the debt capital markets will be sufficient to meet our currently anticipated future 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 first quarter of 2014.

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

FERC Proceeding Related to Formula Rate

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 2013 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

Recovery of Costs from PJM

ITEM 6.

EXHIBITS


10.1		First amendment to credit agreement, dated as of March 12, 2014, among Old Dominion Electric Cooperative, the lenders, party thereto, the Issuing lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender.

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: May 9, 2014				/s/ Robert L. Kees
				Robert L. Kees
				Senior Vice President and Chief Financial Officer
				(Principal financial officer)

EXHIBIT INDEX


Exhibit Number		Description of Exhibit

10.1		First amendment to credit agreement, dated as of March 12, 2014, among Old Dominion Electric Cooperative, the lenders, party thereto, the Issuing lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender.

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Good

Larger accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company