Document_And_Entity_Informatio
Document And Entity Information (USD $) | 12 Months Ended |
Dec. 31, 2014 | |
Document And Entity Information [Abstract] | |
Document Type | 10-K |
Amendment Flag | FALSE |
Document Period End Date | 31-Dec-14 |
Document Fiscal Year Focus | 2014 |
Document Fiscal Period Focus | FY |
Entity Registration Name | OLD DOMINION ELECTRIC COOPERATIVE |
Entity Central Index Key | 885568 |
Current Fiscal year End Date | -19 |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | 0 |
Entity Well-known Seasoned Issuer | No |
Entity Public Float | $0 |
Entity Current Reporting Status | No |
Entity Voluntary Filers | Yes |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | |
In Thousands, unless otherwise specified | |||
ASSETS: | |||
Property, plant, and equipment | $1,690,555 | $1,660,548 | [1] |
Less accumulated depreciation | -784,215 | -755,288 | |
Net Property, plant, and equipment | 906,340 | 905,260 | |
Nuclear fuel, at amortized cost | 19,376 | 23,636 | |
Construction work in progress | 171,953 | 36,482 | |
Net Electric Plant | 1,097,669 | 965,378 | |
Investments: | |||
Nuclear decommissioning trust | 145,822 | 134,454 | |
Lease deposits | 99,191 | 96,634 | |
Unrestricted investments and other | 7,049 | 24,896 | |
Total Investments | 252,062 | 255,984 | |
Current Assets: | |||
Cash and cash equivalents | 1,424 | 51,669 | |
Accounts receivable | 8,656 | 12,742 | |
Accounts receivable - deposits | 4,400 | ||
Accounts receivable - members | 83,108 | 88,545 | |
Fuel, materials, and supplies | 64,154 | 49,246 | |
Deferred energy | 19,948 | ||
Prepayments and other | 5,131 | 3,892 | |
Total Current Assets | 182,421 | 210,494 | |
Deferred Charges: | |||
Regulatory assets | 87,987 | 87,983 | |
Other | 18,603 | 10,758 | |
Total Deferred Charges | 106,590 | 98,741 | |
Total Assets | 1,638,742 | 1,530,597 | |
CAPITALIZATION AND LIABILITIES: | |||
Patronage capital | 379,097 | 369,997 | |
Non-controlling interest | 5,687 | 5,691 | |
Total Patronage capital and Non-controlling interest | 384,784 | 375,688 | |
Long-term debt | 721,038 | 749,330 | |
Revolving credit facility | 86,000 | ||
Total Long-term debt and Revolving credit facility | 807,038 | 749,330 | |
Total Capitalization | 1,191,822 | 1,125,018 | |
Current Liabilities: | |||
Long-term debt due within one year | 28,292 | 28,292 | |
Accounts payable | 96,702 | 68,560 | |
Accounts payable - members | 35,217 | 24,998 | |
Accrued expenses | 4,568 | 4,991 | |
Deferred energy | 37,193 | ||
Total Current Liabilities | 164,779 | 164,034 | |
Deferred Credits and Other Liabilities: | |||
Asset retirement obligations | 104,936 | 80,860 | |
Obligations under long-term lease | 84,730 | 79,227 | |
Regulatory liabilities | 78,764 | 76,940 | |
Other | 13,711 | 4,518 | |
Total Deferred Credits and Other Liabilities | 282,141 | 241,545 | |
Commitments and Contingencies | |||
Total Capitalization and Liabilities | $1,638,742 | $1,530,597 | |
[1] | Other includes $6.0 million related to Wildcat Point and $3.1 million for transmission. |
Consolidated_Statements_Of_Rev
Consolidated Statements Of Revenues, Expenses, And Patronage Capital (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Consolidated Statements Of Revenues, Expenses, And Patronage Capital [Abstract] | |||
Operating Revenues | $951,576 | $842,069 | $842,681 |
Operating Expenses: | |||
Fuel | 213,528 | 133,592 | 90,874 |
Purchased power | 518,814 | 463,159 | 471,557 |
Transmission | 75,959 | 66,590 | 66,189 |
Deferred energy | -57,141 | -18,834 | 21,315 |
Operations and maintenance | 49,599 | 41,546 | 42,615 |
Administrative and general | 40,279 | 42,385 | 35,958 |
Depreciation and amortization | 42,049 | 42,346 | 42,012 |
Amortization of regulatory asset/(liability), net | 5,838 | 6,310 | 735 |
Accretion of asset retirement obligations | 3,870 | 3,980 | 3,739 |
Taxes, other than income taxes | 8,256 | 8,405 | 8,542 |
Total Operating Expenses | 901,051 | 789,479 | 783,536 |
Operating Margin | 50,525 | 52,590 | 59,145 |
Other expense, net | -3,086 | -2,562 | -2,224 |
Gain/(loss) on investments, net | 2,269 | -2,156 | |
Investment income | 7,349 | 5,333 | 4,129 |
Interest charges, net | -45,693 | -47,680 | -48,698 |
Income taxes | 1 | -143 | -93 |
Net Margin including Non-controlling interest | 9,096 | 9,807 | 10,103 |
Non-controlling interest | 4 | -234 | -164 |
Net Margin attributable to ODEC | 9,100 | 9,573 | 9,939 |
Patronage Capital - Beginning of Period | 369,997 | 360,424 | 350,485 |
Patronage Capital - End of Period | $379,097 | $369,997 | $360,424 |
Consolidated_Statements_Of_Cas
Consolidated Statements Of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Operating Activities: | |||
Net Margin including Non-controlling interest | $9,096 | $9,807 | $10,103 |
Adjustments to reconcile net margin to net cash provided by operating activities: | |||
Depreciation and amortization | 42,049 | 42,346 | 42,012 |
Other non-cash charges | 17,766 | 18,604 | 14,616 |
Amortization of lease obligations | 5,503 | 5,141 | 4,801 |
Interest on lease deposits | -2,841 | -2,774 | -2,710 |
Change in current assets | -2,224 | -3,060 | -2,861 |
Change in deferred energy | -57,141 | -18,834 | 21,315 |
Change in current liabilities | 9,204 | -20,555 | -32,399 |
Change in regulatory assets and liabilities | -2,467 | -9,004 | -248 |
Change in deferred charges-other and deferred credits and other liabilities-other | -2,096 | -1,564 | -3,319 |
Net Cash Provided by Operating Activities | 16,849 | 20,107 | 51,310 |
Investing Activities: | |||
Purchases of held to maturity securities | -3,931 | -112,454 | -103,420 |
Proceeds from sale of held to maturity securities | 21,746 | 143,605 | 91,278 |
Purchases of available for sale securities | -24,290 | ||
Proceeds from sale of available for sale securities | 24,308 | ||
Increase in other investments | -6,760 | -7,468 | -4,900 |
Electric plant additions | -135,857 | -32,093 | -32,407 |
Net Cash Used for Investing Activities | -124,802 | -8,410 | -49,431 |
Financing Activities: | |||
Issuance of long-term debt | 100,000 | ||
Debt issuance costs | -744 | ||
Payment of long-term debt | -28,292 | -88,827 | -28,292 |
Dividend - non-controlling interest | -7,800 | ||
Draws on revolving credit facility | 387,604 | ||
Repayments on revolving credit facility | -301,604 | ||
Net Cash Provided by (Used for) Financing Activities | 57,708 | 2,629 | -28,292 |
Net Change in Cash and Cash Equivalents | -50,245 | 14,326 | -26,413 |
Cash and Cash Equivalents - Beginning of Year | 51,669 | 37,343 | 63,756 |
Cash and Cash Equivalents - End of Year | $1,424 | $51,669 | $37,343 |
Summary_Of_Significant_Account
Summary Of Significant Accounting Policies | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Summary Of Significant Accounting Policies [Abstract] | ||||||||||
Summary Of Significant Accounting Policies | NOTE 1—Summary of Significant Accounting Policies | |||||||||
General | ||||||||||
The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and 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. During 2013, TEC refunded $7.8 million of equity to its owners in the form of a cash dividend. The assets and liabilities, and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $5.7 million at December 31, 2014 and December 31, 2013. The income taxes reported on our Consolidated Statements of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC. As TEC is 100% owned by our Class A members, its equity is presented as a non-controlling interest in our consolidated financial statements. Our non-controlling, 50% or less, ownership interest in other entities for which we have significant influence is recorded using the equity method of accounting. We have a power sales contract with TEC under which we may sell to TEC power that we do not need to meet the needs of our member distribution cooperatives. TEC then sells this power to the market under market-based rate authority granted by FERC. Additionally, we have a separate contract under which we may purchase natural gas from TEC. TEC does not engage in speculative trading. | ||||||||||
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 eleven Class A members are customer-owned electric distribution cooperatives engaged in the retail sale of power to customers located in Virginia, Delaware, and Maryland. Our sole Class B member, TEC, a taxable corporation, is 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. Our rates are not regulated by the public service commissions of the states in which our member distribution cooperatives operate, but are set periodically by a formula that was accepted for filing by FERC. | ||||||||||
We comply with the Uniform System of Accounts 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 did not have any other comprehensive income for the periods presented. | ||||||||||
Electric Plant | ||||||||||
Electric plant is stated at original cost when first placed in service. Such cost includes contract work, direct labor and materials, allocable overhead, an allowance for borrowed funds used during construction and asset retirement costs. Upon the partial sale or retirement of plant assets, the original asset cost and current disposal costs less sale proceeds, if any, are charged or credited to accumulated depreciation. In accordance with industry practice, no profit or loss is recognized in connection with normal sales and retirements of property units. | ||||||||||
Maintenance and repair costs are expensed as incurred. Replacements and renewals of items considered to be units of property are capitalized to the property accounts. | ||||||||||
Depreciation | ||||||||||
We conduct depreciation studies approximately every five years and our depreciation rates were as follows: | ||||||||||
Depreciation Rates | ||||||||||
Generating Facility | 2014 | 2013 | 2012 | |||||||
Clover | 1.8 | % | 1.8 | % | 1.8 | % | ||||
North Anna | 3.0 | 3.0 | 3.0 | |||||||
Louisa | 3.5 | 3.5 | 3.5 | |||||||
Marsh Run | 3.2 | 3.2 | 3.2 | |||||||
Rock Springs | 3.3 | 3.3 | 3.3 | |||||||
Our last depreciation study was performed in 2011. | ||||||||||
Nuclear Fuel | ||||||||||
Nuclear fuel is amortized on a unit of production basis sufficient to fully amortize the cost of fuel over its estimated service life and is recorded in fuel expense. | ||||||||||
Virginia Power, as operating agent of North Anna, has the sole authority and responsibility to procure nuclear fuel for the facility. Virginia Power advises us that it primarily uses long-term contracts to support North Anna’s nuclear fuel requirements and that worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent upon the market environment. We are not a direct party to any of these procurement contracts and we do not control their terms or duration. Virginia Power advises us that current agreements, inventories, and spot market availability are expected to support North Anna’s current and planned fuel supply needs for the near term and that additional fuel is purchased as required to attempt to ensure optimal cost and inventory levels. | ||||||||||
Under the Nuclear Waste Policy Act of 1982, the DOE is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as North Anna, in accordance with contracts executed with the DOE. The DOE did not begin accepting spent fuel in 1998 as specified in its contract. As a result, Virginia Power sought reimbursement for certain spent nuclear fuel-related costs incurred and in 2012 signed a settlement agreement with the DOE. By mutual agreement of the parties, the settlement agreement is extendable to provide for resolution of damages. The settlement agreement has been extended to provide for periodic payments for damages incurred through December 31, 2016. During 2014 and 2013, we recorded our proportionate share of $0.9 million and $1.8 million, respectively, as a reduction to fuel expense related to the settlement agreement and during 2014, we also recorded a $0.6 million reduction to property, plant, and equipment, as the settlement includes a reimbursement of costs related to fixed assets. At December 31, 2014 and 2013, we had an outstanding receivable of $3.3 million and $3.9 million, respectively. | ||||||||||
Fuel, Materials, and Supplies | ||||||||||
Fuel, materials, and supplies is primarily comprised of fuel and spare parts for our generating assets. Fuel, which consists primarily of coal and No. 2 fuel oil, is recorded at cost. Spare parts for our generating assets are recorded at cost. | ||||||||||
Allowance for Borrowed Funds Used During Construction | ||||||||||
Allowance for borrowed funds used during construction is defined as the net cost of borrowed funds used for construction purposes during the construction period and a reasonable rate on other funds when so used. We capitalize interest on borrowings for significant construction projects. Interest capitalized in 2014, 2013, and 2012, was $0.9 million, $0.2 million, and $1.0 million, respectively. | ||||||||||
Income Taxes | ||||||||||
As a not-for-profit electric cooperative, we are currently exempt from federal income taxation under IRC Section 501(c)(12), and we intend to continue to operate in this manner. Based on our assessment and evaluations of relevant authority, we believe we could sustain treatment as a tax-exempt utility in the event of a challenge of our tax status. Accordingly, no provision for income taxes has been recorded based on ODEC’s operations in the accompanying consolidated financial statements. | ||||||||||
TEC is a taxable corporation and its provision for income taxes was immaterial for the years ended December 31, 2014, 2013, and 2012. | ||||||||||
Operating Revenues | ||||||||||
Our operating revenues are derived from sales to our members and non-members and are recorded when power, including renewable energy credits, is delivered. We sell energy to our Class A members pursuant to long-term wholesale power contracts that we maintain with each of our member distribution cooperatives. These wholesale power contracts obligate each member distribution cooperative to pay us for power furnished in accordance with our rates. For the years ended December 31, 2014, 2013, and 2012, revenue from sales to our member distribution cooperatives, including the sale of renewable energy credits, was $908.0 million, $810.1 million, and $826.8 million, respectively. For the years ended December 31, 2014, 2013, and 2012, the sale of renewable energy credits included in revenue from sales to our member distribution cooperatives was $1.3 million and $1.4 million in 2014 and 2013, respectively, and was immaterial in 2012. See Note 5—Wholesale Power Contracts. | ||||||||||
We sell excess purchased and generated energy, if any, to TEC, our Class B member, or to third parties under FERC market-based rate authority. Sales to TEC consist of sales of excess energy that we do not need to meet the actual needs of our member distribution cooperatives. TEC’s sales to third parties are reflected as non-member revenues; however, in 2014, 2013, and 2012, TEC had no sales to third parties. Excess purchased and generated energy that is not sold to TEC is sold to PJM under its rates for providing energy imbalance service, or to third parties. For the years ended December 31, 2014, 2013, and 2012, energy sales to non-members, including the sale of renewable energy credits, were $43.5 million, $31.9 million, and $15.9 million, respectively. For the years ended December 31, 2014, 2013, and 2012, the sale of renewable energy credits included in energy sales to non-members was $5.9 million, $6.1 million, and $0.5 million, respectively. | ||||||||||
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 credited or charged 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 is 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 “Legal Proceedings” in Part I, Item 3. | ||||||||||
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 PJM members; and | |||||||||
· | 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: | ||||||||||
· | 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 recorded. | |||||||||
· | 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. | |||||||||
For the year ended December 31, 2014, we did not record an adjustment to operating revenues utilizing Margin Stabilization, since the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equaled 19.5% of our actual total interest charges. In accordance with our formula rate, no adjustment is recorded if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, is more than 10% but less than 20% of our actual total interest charges. For the years ended December 31, 2013 and 2012, we recorded a reduction in operating revenues of $9.8 million and $15.0 million, respectively, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges. See “Critical Accounting Policies—Margin Stabilization” above. | ||||||||||
We may revise our budget at any time to the extent that our current budget does not accurately reflect our costs and expenses or estimates of our sales of power. Increases or decreases in our budget automatically amend the energy and/or the demand components of our formula rate, as necessary. The formula rate also permits us to adjust revenues from the member distribution cooperatives to equal our actual total demand costs. We make these adjustments under Margin Stabilization. See “Critical Accounting Policies—Margin Stabilization” above. If at any time our board of directors determines that the formula does not meet all of our costs and expenses, it may adopt a new formula to meet those costs and expenses, subject to any necessary regulatory review and approval. | ||||||||||
Regulatory Assets and Liabilities | ||||||||||
We account for certain revenues and expenses as a rate-regulated entity in accordance with Accounting for Regulated Operations. This allows certain of our revenues and expenses to be deferred at the discretion of our board of directors, which has budgetary and rate setting authority, if it is probable that these amounts will be recovered or returned through our formula rate in future periods. Regulatory assets represent costs that we expect to recover from our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory liabilities represent probable future reductions in our revenues associated with amounts that we expect to return to our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory assets are included in deferred charges and regulatory liabilities are included in deferred credits and other liabilities. Deferred energy, which can be either a regulatory asset or a regulatory liability, is included in current assets or current liabilities, respectively. See “Deferred Energy” below. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses, respectively, concurrent with their recovery through rates. | ||||||||||
Debt Issuance Costs | ||||||||||
Capitalized costs associated with the issuance of long-term debt and the revolving credit facility totaled $6.7 million at December 31, 2014 and 2013, and are included in deferred charges – other. These costs are being amortized using the effective interest method over the life of the respective long-term debt issuances and the revolving credit facility, and are included in interest charges, net. | ||||||||||
Deferred Charges – Other | ||||||||||
Deferred charges – other, includes unamortized debt issuance costs, the deferred rent related to the Wildcat Point operating lease, NYMEX margin mark-to-market asset, and the long-term portion of the prepayment of premiums on an insurance policy related to Wildcat Point. | ||||||||||
Deferred Credits and Other Liabilities – Other | ||||||||||
Deferred credits and other liabilities – other, includes NYMEX margin mark-to-market liability, Wildcat Point retainage, a gain on a long-term lease transaction (see Note 8—Long-term Lease Transaction), DOE decontamination and decommissioning liability, and liabilities associated with benefit plans for certain executives. | ||||||||||
Deferred Energy | ||||||||||
We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. The deferred energy balance represents the net accumulation of any under- or over-collection of energy costs. At December 31, 2014, we had an under-collected deferred energy balance of $19.9 million. At December 31, 2013, we had an over-collected deferred energy balance of $37.2 million. In January 2014, the entire mid-Atlantic region experienced extremely cold weather, which increased our member distribution cooperatives’ customers’ requirements for power as well as increased our purchased power and fuel expenses. As a result, our deferred energy balance changed from an over-collection of energy costs to an under-collection of energy costs. To address the under-collection of energy costs, we increased our total energy rate 11.8% effective April 1, 2014, and an additional 2.4% effective October 1, 2014. Under-collected deferred energy balances will be collected from our member distribution cooperatives in subsequent periods through our formula rate. Over-collected deferred energy balances are refunded to our member distribution cooperatives in subsequent periods. | ||||||||||
Financial Instruments (including Derivatives) | ||||||||||
Investments included in the nuclear decommissioning trust are classified as available for sale, and accordingly, are carried at fair value. Unrealized gains and losses on investments held in the nuclear decommissioning trust are deferred as a regulatory liability or a regulatory asset, respectively, until realized. | ||||||||||
Unrestricted investments and lease deposits in debt securities that we have the positive intent and ability to hold to maturity are classified as held to maturity and are recorded at amortized cost. Non-marketable equity investments in other investments are recorded at cost. Equity securities in other investments are recorded at fair value. See Note 9—Investments. | ||||||||||
We primarily purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution cooperatives. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase derivative contracts qualify for the normal purchases/normal sales exception provided for under Accounting for Derivatives and Hedging. As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the physically-delivered forward contract is delivered. We also purchase natural gas futures generally for three years or less to hedge the price of natural gas for the operation of our combustion turbine facilities. These derivatives do not qualify for the normal purchases/normal sales exception. | ||||||||||
For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we may elect cash flow hedge accounting in accordance with Accounting for Derivatives and Hedging. Accordingly, gains and losses on derivative contracts are deferred into other comprehensive income until the hedged underlying transaction occurs or is no longer likely to occur. We do not have any other comprehensive income for the periods presented. For derivative contracts where hedge accounting is not utilized, or for which ineffectiveness exists, we defer all remaining gains and losses on a net basis as a regulatory asset or regulatory liability, respectively, in accordance with Accounting for Regulated Operations. These amounts are subsequently reclassified as purchased power or fuel expense in our Consolidated Statements of Revenues, Expenses, and Patronage Capital as the power or fuel is delivered and/or the contract settles. There were no contracts for which we have elected cash flow hedge accounting and therefore, there was no hedge ineffectiveness during the years ended December 31, 2014, 2013, or 2012. | ||||||||||
Generally, derivatives are reported at fair value on the Consolidated Balance Sheet in the regulatory assets or regulatory liabilities account and deferred charges–other and deferred credits and other liabilities–other. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. | ||||||||||
Patronage Capital | ||||||||||
We are organized and operate as a cooperative. Patronage capital represents our retained net margins, which have been allocated to our members based upon their respective power purchases in accordance with our bylaws. Any distributions of patronage capital are subject to the discretion of our board of directors and the restrictions contained in our Indenture and our syndicated credit agreement. See Note 11—Long-term Debt for discussion of the restrictions contained in the Indenture. | ||||||||||
Concentrations of Credit Risk | ||||||||||
Financial instruments that potentially subject us to concentrations of credit risk consist of cash equivalents, investments, derivatives, and receivables arising from sales to our members and non-members. Concentrations of credit risk with respect to receivables arising from sales to our member distribution cooperatives as reflected by accounts receivable–members were $83.1 million and $88.5 million, at December 31, 2014 and 2013, respectively. | ||||||||||
Segment | ||||||||||
We are organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis. Our President and CEO serves as our chief operating decision maker who manages and reviews our operating results as one operating, and therefore one reportable, segment. We supply our member distribution cooperatives’ energy and demand requirements through a portfolio of resources including generating facilities, physically-delivered forward power purchase contracts, and spot market energy purchases. | ||||||||||
Cash Equivalents | ||||||||||
For purposes of our Consolidated Statements of Cash Flows, we consider all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. | ||||||||||
Reclassifications | ||||||||||
Certain reclassifications have been made to the prior years’ consolidated financial statements to conform to the current year’s presentation. | ||||||||||
Electric_Plant
Electric Plant | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Electric Plant [Abstract] | |||||||||||||||||||
Electric Plant | |||||||||||||||||||
NOTE 2—Electric Plant | |||||||||||||||||||
Our net electric plant is comprised of the following for 2014: | |||||||||||||||||||
Combustion | |||||||||||||||||||
North | Turbine | Wildcat | |||||||||||||||||
Clover | Anna | Facilities | Point | Other | Total | ||||||||||||||
(in thousands) | |||||||||||||||||||
Property, plant, and equipment | $ | 678,006 | $ | 351,636 | $ | 587,955 | $ | - | $ | 72,958 | $ | 1,690,555 | |||||||
Accumulated depreciation | -352,271 | -190,317 | -218,020 | - | -23,607 | -784,215 | |||||||||||||
Net Property, plant, and equipment | 325,735 | 161,319 | 369,935 | - | 49,351 | 906,340 | |||||||||||||
Nuclear fuel, at amortized cost | - | 19,376 | - | - | - | 19,376 | |||||||||||||
Construction work in progress | 11,364 | 33,580 | - | 115,779 | 11,230 | 171,953 | |||||||||||||
Net Electric Plant | $ | 337,099 | $ | 214,275 | $ | 369,935 | $ | 115,779 | $ | 60,581 | $ | 1,097,669 | |||||||
Our net electric plant is comprised of the following for 2013: | |||||||||||||||||||
Combustion | |||||||||||||||||||
North | Turbine | ||||||||||||||||||
Clover | Anna | Facilities | Other | Total | |||||||||||||||
(in thousands) | |||||||||||||||||||
Property, plant, and equipment (1) | $ | 671,708 | $ | 335,151 | $ | 585,067 | $ | 68,622 | $ | 1,660,548 | |||||||||
Accumulated depreciation | -349,197 | -184,314 | -198,520 | -23,257 | -755,288 | ||||||||||||||
Net Property, plant, and equipment | 322,511 | 150,837 | 386,547 | 45,365 | 905,260 | ||||||||||||||
Nuclear fuel, at amortized cost | - | 23,636 | - | - | 23,636 | ||||||||||||||
Construction work in progress | 6,670 | 20,536 | - | 9,276 | 36,482 | ||||||||||||||
Net Electric Plant | $ | 329,181 | $ | 195,009 | $ | 386,547 | $ | 54,641 | $ | 965,378 | |||||||||
-1 | Other includes $6.0 million related to Wildcat Point and $3.1 million for transmission. | ||||||||||||||||||
We hold a 50% undivided ownership interest in Clover, a two-unit, 874 MW (net capacity entitlement) coal-fired electric generating facility operated by Virginia Power, which owns the balance of the plant. We are responsible for and must fund half of all additions and operating costs associated with Clover, as well as half of Virginia Power’s administrative and general expenses directly attributable to Clover. Our portion of assets, liabilities, and operating expenses associated with Clover are included in our consolidated financial statements in accordance with proportionate consolidation accounting. At December 31, 2014 and 2013, we had an outstanding accounts payable balance of $11.4 million and $12.7 million, respectively, due to Virginia Power for operation, maintenance, and capital investment at Clover. | |||||||||||||||||||
We hold an 11.6% undivided ownership interest in North Anna, a two-unit, 1,897 MW (net capacity entitlement) nuclear power facility operated by Virginia Power, which owns the balance of the plant. We are responsible for and must fund 11.6% of all post-acquisition date additions and operating costs associated with North Anna, as well as a pro-rata portion of Virginia Power’s administrative and general expenses directly attributable to North Anna. Our portion of assets, liabilities, and operating expenses associated with North Anna are included in our consolidated financial statements in accordance with proportionate consolidation accounting. At December 31, 2014 and 2013, we had an outstanding accounts payable balance of $3.1 million and $4.1 million, respectively, due to Virginia Power for the operation, maintenance, and capital investment at North Anna. | |||||||||||||||||||
We own three combustion turbine facilities that are carried at cost, less accumulated depreciation. We also own distributed generation facilities, which are included in “Other” in the net electric plant table. Additionally, we own approximately 100 miles of transmission lines on the Virginia portion of the Delmarva Peninsula included in “Other,” as well as two 1,100 foot 500 kV transmission lines and a 500 kV substation at our combustion turbine site in Maryland included in “Combustion Turbine Facilities.” | |||||||||||||||||||
Wildcat Point | |||||||||||||||||||
We are currently constructing, and will be the sole owner of, an approximate 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. On April 8, 2014, we received a Final Order granting approval of the CPCN from the MPSC. On June 2, 2014, we selected White Oak Power Constructors as the EPC contractor. Site preparation and engineering activities are in process, and permanent construction began in January 2015. The facility is scheduled to become operational in mid-2017. We currently have a ground lease related to the land associated with Wildcat Point and are currently accounting for it as an operating lease. Once Wildcat Point becomes operational, the lease will be reevaluated and likely will become a capital lease. We currently anticipate that the project cost will be approximately $790.5 million, including capitalized interest, but excluding the lease. To fund a portion of the project cost, on January 15, 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction. See Note 12—Liquidity Resources. | |||||||||||||||||||
Wildcat Point will consist of two combustion turbines, two heat recovery steam generators and one steam turbine generator. Mitsubishi will supply the combustion turbines. Alstom will supply the heat recovery steam generators and the steam turbine generator. Beginning in June 2014, following the approval of the CPCN and our selection of the EPC contractor, we began capitalizing all construction-related costs related to Wildcat Point. Through December 31, 2014, we capitalized construction costs related to Wildcat Point totaling $115.8 million, which are recorded in construction work in progress. In January 2015, we began capitalizing interest with respect to the facility upon commencement of permanent construction. For 2014 and 2013, we expensed $4.5 million and $7.7 million, respectively, of non-capital costs related to Wildcat Point, which are recorded in administrative and general expense. | |||||||||||||||||||
Accounting_For_Asset_Retiremen
Accounting For Asset Retirement And Environmental Obligations | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Accounting For Asset Retirement And Environmental Obligations [Abstract] | ||||
Accounting For Asset Retirement And Environmental Obligations | ||||
NOTE 3—Accounting for Asset Retirement and Environmental Obligations | ||||
We account for our asset retirement obligations in accordance with Accounting for Asset Retirement and Environmental Obligations. This requires that legal obligations associated with the retirement of long-lived assets be recognized at fair value when incurred and capitalized as part of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized asset is depreciated over the useful life of the long-lived asset. | ||||
In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations by using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Our estimated liability could change significantly if actual costs vary from assumptions or if governmental regulations change significantly. | ||||
A significant portion of our asset retirement obligations relate to our share of the future costs to decommission North Anna. At December 31, 2014 and 2013, North Anna’s nuclear decommissioning asset retirement obligation totaled $93.7 million and $72.1 million, respectively. Approximately every four years, a new decommissioning study for North Anna is performed by third-party experts. A new study was performed in 2014, and we adopted it effective December 1, 2014, which resulted in an additional layer related to the asset retirement obligation associated with North Anna. The additional layer resulted in an increase to our asset retirement cost and our asset retirement obligation of $18.0 million. Increased spent fuel costs, including interim storage, insurance premiums, and regulatory and environmental permits and fees, as a result of the DOE delay for acceptance of spent fuel, is the primary driver for the increase in the asset retirement obligation. We are not aware of any events that have occurred since the 2014 study that would materially impact our estimate. We are required to maintain a funded trust to satisfy our future obligation to decommission the North Anna facility. See Note 9—Investments. We are currently evaluating the impact of the 2014 study on the funding status of our nuclear decommissioning trust. | ||||
In 2014, we established two additional asset retirement obligations for Clover ash landfills and also determined that we no longer had an asset retirement obligation for a waste pond for Clover. | ||||
The following represents changes in our asset retirement obligations for the years ended December 31, 2014 and 2013 (in thousands): | ||||
Asset retirement obligations at December 31, 2012 | $ | 76,880 | ||
Accretion expense | 3,980 | |||
Asset retirement obligations at December 31, 2013 | $ | 80,860 | ||
Accretion expense | 3,870 | |||
Increase in asset retirement obligations - new layer | 17,953 | |||
Additional asset retirement obligations, net | 2,253 | |||
Asset retirement obligations at December 31, 2014 | $ | 104,936 | ||
The cash flow estimates for North Anna’s asset retirement obligations are based upon the 20-year life extension which was granted in 2003 and extends the life of Unit 1 to April 1, 2038 and the life of Unit 2 to August 21, 2040. Given the life extension in 2003, the nuclear decommissioning trust was, and currently is, estimated to be adequate to fund North Anna’s asset retirement obligations and no additional funding was, or is, currently required. We ceased collection of decommissioning expense in August 2003 with the approval of FERC. As we are not currently collecting decommissioning expense in our rates, we are deferring the difference between the earnings on the nuclear decommissioning trust and the total asset retirement obligation related depreciation and accretion expense for North Anna as part of our asset retirement obligation regulatory liability. See Note 10—Regulatory Assets and Liabilities. | ||||
Power_Purchase_Agreements
Power Purchase Agreements | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Power Purchase Agreements [Abstract] | |||||
Power Purchase Agreements | NOTE 4—Power Purchase Agreements | ||||
In 2014, 2013, and 2012, our owned generating facilities together furnished approximately 40.2%, 39.4%, and 33.4%, respectively, of our energy requirements. The remaining needs were satisfied through purchases of power in the market from investor owned utilities and power marketers through long-term and short-term physically-delivered forward power purchase contracts. We also purchase power in the spot energy market. This approach to meeting our member distribution cooperatives’ energy requirements is not without risks. To mitigate these risks, we attempt to match our energy purchases with our energy needs to reduce our spot market purchases of energy. Additionally, we utilize policies, procedures, and various hedging instruments to manage our power market price risks. These policies and procedures, developed in consultation with ACES, an energy trading and risk management company, are designed to strike an appropriate balance between minimizing costs and reducing energy cost volatility. At December 31, 2014, we were not required to post collateral with our counterparties. At December 31, 2013, due to changes in energy prices, we were required to post $4.4 million with our counterparties pursuant to contracts we had in place with them. | |||||
Our purchased power costs for 2014, 2013, and 2012 were $518.8 million, $463.2 million, and $471.6 million, respectively. | |||||
As of December 31, 2014, our energy and capacity purchase obligations under the various agreements were as follows: | |||||
Energy and | |||||
Capacity | |||||
Year Ending December 31, | Obligations | ||||
(in millions) | |||||
2015 | $ | 279.8 | |||
2016 | 200.3 | ||||
2017 | 161.5 | ||||
$ | 641.6 | ||||
Wholesale_Power_Contracts
Wholesale Power Contracts | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Wholesale Power Contracts [Abstract] | ||||||||||
Wholesale Power Contracts | NOTE 5—Wholesale Power Contracts | |||||||||
We have a wholesale power contract with each of our eleven member distribution cooperatives. The wholesale power contracts are “all-requirements” contracts. Each contract obligates us to sell and deliver to the member distribution cooperative, and obligates the member distribution cooperative to purchase and receive from us, all power that it requires for the operation of its system, with limited exceptions, to the extent that we have the power and facilities available to do so. These contracts are effective until January 1, 2054 and beyond this date unless either party gives the other at least three years notice of termination. | ||||||||||
The principal exception to the all-requirements obligations of the member distribution cooperatives relates to the ability of our eight mainland Virginia member distribution cooperatives to purchase hydroelectric power allocated to them from SEPA. Purchases under this exception constituted approximately 1.4% of our member distribution cooperatives’ total energy requirements in 2014. | ||||||||||
Two additional limited exceptions to the all-requirements nature of the contract permit the member distribution cooperatives to receive up to the greater of 5.0% of their power requirements or 5 MW from owned generation or other suppliers, and to purchase additional power from other suppliers in limited circumstances following approval by our board of directors. In 2014, our member distribution cooperatives collectively received 8.7 MW under these exceptions. We do not anticipate that this will have a material impact on our financial condition, results of operations, or cash flows. | ||||||||||
Each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract in accordance with our formula rate. The formula rate, which has been filed with and accepted by FERC, is designed to recover our total cost of service and create a firm equity base. More specifically, the formula rate is intended to meet all of our costs, expenses, and financial obligations associated with our ownership, operation, maintenance, repair, replacement, improvement, modification, retirement, and decommissioning of our generating plants, transmission system, or related facilities, services provided to the member distribution cooperatives, and the acquisition and transmission of power or related services, including: | ||||||||||
· | payments of principal and premium, if any, and interest on all indebtedness issued by us (other than payments resulting from the acceleration of the maturity of the indebtedness); | |||||||||
· | any additional cost or expense, imposed or permitted by any regulatory agency; and | |||||||||
· | additional amounts necessary to meet the requirement of any rate covenant with respect to coverage of principal and interest on our indebtedness contained in any indenture or contract with holders of our indebtedness. | |||||||||
The rates established under the wholesale power contracts are designed to enable us to comply with financing, regulatory, and governmental requirements, which apply to us from time to time. | ||||||||||
Revenues from our member distribution cooperatives for the past three years were as follows: | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
(in millions) | ||||||||||
Rappahannock Electric Cooperative | $ | 311.7 | $ | 275.9 | $ | 280.4 | ||||
Shenandoah Valley Electric Cooperative | 172.1 | 150.4 | 152.1 | |||||||
Delaware Electric Cooperative, Inc. | 106.8 | 94.7 | 95.4 | |||||||
Choptank Electric Cooperative, Inc. | 80.2 | 72.1 | 75.9 | |||||||
Southside Electric Cooperative | 70.2 | 64.5 | 66.0 | |||||||
A&N Electric Cooperative | 53.0 | 47.8 | 48.4 | |||||||
Mecklenburg Electric Cooperative | 43.8 | 39.7 | 40.6 | |||||||
Prince George Electric Cooperative | 23.5 | 21.6 | 22.1 | |||||||
Northern Neck Electric Cooperative | 21.3 | 19.5 | 19.7 | |||||||
Community Electric Cooperative | 15.3 | 13.9 | 14.1 | |||||||
BARC Electric Cooperative | 10.1 | 10.0 | 12.1 | |||||||
Total | $ | 908.0 | $ | 810.1 | $ | 826.8 | ||||
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Fair Value Measurements [Abstract] | |||||||||||||
Fair Value Measurements | |||||||||||||
NOTE 6—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 December 31, 2014 and 2013: | |||||||||||||
Quoted Prices | |||||||||||||
in Active | Significant | ||||||||||||
Markets for | Other | Significant | |||||||||||
Identical | Observable | Unobservable | |||||||||||
December 31, | Assets | Inputs | Inputs | ||||||||||
2014 | (Level 1) | (Level 2) | (Level 3) | ||||||||||
(in thousands) | |||||||||||||
Nuclear decommissioning trust (1)(2) | $ | 145,822 | $ | 45,573 | $ | 100,249 | $ | - | |||||
Unrestricted investments and other (3) | 198 | - | 198 | - | |||||||||
Total Financial Assets | $ | 146,020 | $ | 45,573 | $ | 100,447 | $ | - | |||||
Derivatives - gas and power (4) | $ | 5,215 | $ | 5,215 | $ | - | $ | - | |||||
Total Financial Liabilities | $ | 5,215 | $ | 5,215 | $ | - | $ | - | |||||
Quoted Prices | |||||||||||||
in Active | Significant | ||||||||||||
Markets for | Other | Significant | |||||||||||
Identical | Observable | Unobservable | |||||||||||
December 31, | Assets | Inputs | Inputs | ||||||||||
2013 | (Level 1) | (Level 2) | (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 9—Investments. | ||||||||||||
-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 which are recorded on our Consolidated Balance Sheet in either deferred charges-other or deferred credits and other liabilities–other, and which are indexed against NYMEX. For additional information about our derivative financial instruments see Note 1—Summary of Significant Accounting Policies. | ||||||||||||
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. | |||||||||||||
Derivatives_And_Hedging
Derivatives And Hedging | 12 Months Ended | ||||||||||||||
Dec. 31, 2014 | |||||||||||||||
Derivatives And Hedging [Abstract] | |||||||||||||||
Derivatives And Hedging | |||||||||||||||
NOTE 7—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—Summary of Significant Accounting Policies. | |||||||||||||||
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 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 | ||||||||||||||
31-Dec-14 | 31-Dec-13 | ||||||||||||||
Commodity | Unit of Measure | Quantity | Quantity | ||||||||||||
Natural Gas | MMBTU | 5,610,000 | 1,470,000 | ||||||||||||
The fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows: | |||||||||||||||
Fair Value | |||||||||||||||
As of | As of | ||||||||||||||
December 31, | December 31, | ||||||||||||||
Balance Sheet Location | 2014 | 2013 | |||||||||||||
(in thousands) | |||||||||||||||
Derivatives in an asset position: | |||||||||||||||
Natural gas futures contracts | Deferred charges-other | $ | - | $ | 412 | ||||||||||
Total derivatives in an asset position | $ | - | $ | 412 | |||||||||||
Derivatives in a liability position: | |||||||||||||||
Natural gas futures contracts | Deferred credits and other liabilities-other | $ | 5,215 | $ | - | ||||||||||
Total derivatives in a liability position | $ | 5,215 | $ | - | |||||||||||
The Effect of Derivative Instruments on the Statements of Revenues, Expenses, and Patronage Capital | |||||||||||||||
for the Years Ended December 31, 2014 and 2013 | |||||||||||||||
Amount of | Amount of Gain | ||||||||||||||
Gain (Loss) | (Loss) Reclassified | ||||||||||||||
Recognized in | Location of Gain | from Regulatory | |||||||||||||
Regulatory | (Loss) Reclassified | Asset/Liability into | |||||||||||||
Derivatives Accounted for | Asset/Liability for | from Regulatory | Income for the | ||||||||||||
Utilizing Regulatory | Derivatives as of | Asset/Liability into | Year Ended | ||||||||||||
Accounting | December 31, | Income | December 31, | ||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
(in thousands) | (in thousands) | ||||||||||||||
Natural gas futures contracts (1) | $ | -5,497 | $ | 419 | Fuel | $ | -1,170 | $ | -3,031 | ||||||
Purchased power contracts - excess sales | - | - | Operating revenues | 90 | - | ||||||||||
Total | $ | -5,497 | $ | 419 | $ | -1,080 | $ | -3,031 | |||||||
-1 | As of December 31, 2014, includes a regulatory liability of $0.3 million and as of December 31, 2013, includes a regulatory asset of $7.0 thousand, to be recognized in future periods as the result of the contracts being effectively settled. | ||||||||||||||
LongTerm_Lease_Transaction
Long-Term Lease Transaction | 12 Months Ended |
Dec. 31, 2014 | |
Long-Term Lease Transaction [Abstract] | |
Long-Term Lease Transaction | |
NOTE 8—Long-term Lease Transaction | |
On March 1, 1996, we entered into a long-term lease transaction with an owner trust for the benefit of an investor. Under the terms of the transaction, we entered into a 48.8 year lease of our interest in Clover Unit 1, valued at $315.0 million, to such owner trust, and immediately after we entered into a 21.8 year lease of the interest back from such owner trust. As a result of the transaction, we recorded a deferred gain of $23.7 million, which is being amortized into income ratably over the 21.8 year operating lease term, as a reduction to depreciation and amortization expense. At December 31, 2014 and 2013, the unamortized portion of the deferred gain was $3.2 million and $4.3 million, respectively. | |
We used a portion of the one-time rental payment of $315.0 million we received to enter into a payment undertaking agreement and to purchase an investment that would provide for substantially all of our periodic rent payments under the leaseback, and the fixed purchase price of the interest in the unit at the end of the term of the leaseback if we were to exercise our option to purchase the interest of the owner trust in the unit at that time. The payment undertaking agreement, which had a balance of $308.5 million at December 31, 2014, is issued by Rabobank, which has senior debt obligations which are currently rated “A+” by S&P and “Aa2” by Moody’s, respectively. The amount of debt considered to be extinguished by in substance defeasance was $308.5 million and $309.7 million, at December 31, 2014 and 2013, respectively. | |
At the end of the term of the leaseback, we have three options: (1) retain possession of the interest in the unit by paying a fixed purchase price to the owner trust, (2) return possession of the interest to the owner trust and arrange for an acceptable third-party to enter into a power purchase agreement with the owner trust, or (3) return possession of the interest and pay a termination amount to the owner trust. | |
Investments
Investments | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||
Investments [Abstract] | ||||||||||||||||||
Investments | NOTE 9—Investments | |||||||||||||||||
Investments were as follows at December 31, 2014 and 2013: | ||||||||||||||||||
Gross | Gross | |||||||||||||||||
Unrealized | Unrealized | Fair | Carrying | |||||||||||||||
Description | Designation | Cost | Gains | Losses | Value | Value | ||||||||||||
(in thousands) | ||||||||||||||||||
31-Dec-14 | ||||||||||||||||||
Nuclear decommissioning trust (1) | ||||||||||||||||||
Debt securities | Available for sale | $ | 41,654 | $ | 3,516 | $ | - | $ | 45,170 | $ | 45,170 | |||||||
Equity securities | Available for sale | 68,259 | 31,990 | - | 100,249 | 100,249 | ||||||||||||
Cash and other | Available for sale | 403 | - | - | 403 | 403 | ||||||||||||
Total Nuclear Decommissioning Trust | $ | 110,316 | $ | 35,506 | $ | - | $ | 145,822 | $ | 145,822 | ||||||||
Lease Deposits (2) | ||||||||||||||||||
Government obligations | Held to maturity | $ | 99,191 | $ | 5,569 | $ | - | $ | 104,760 | $ | 99,191 | |||||||
Total Lease Deposits | $ | 99,191 | $ | 5,569 | $ | - | $ | 104,760 | $ | 99,191 | ||||||||
Unrestricted investments | ||||||||||||||||||
Government obligations | Held to maturity | $ | 2,005 | $ | - | $ | - | $ | 2,005 | $ | 2,005 | |||||||
Debt securities | Held to maturity | 2,636 | - | -18 | 2,618 | 2,636 | ||||||||||||
Total Unrestricted Investments | $ | 4,641 | $ | - | $ | -18 | $ | 4,623 | $ | 4,641 | ||||||||
Other | ||||||||||||||||||
Equity securities | Trading | $ | 151 | $ | 47 | $ | - | $ | 198 | $ | 198 | |||||||
Non-marketable equity investments | Equity | 2,210 | 1,821 | - | 4,031 | 2,210 | ||||||||||||
Total Other | $ | 2,361 | $ | 1,868 | $ | - | $ | 4,229 | $ | 2,408 | ||||||||
$ | 252,062 | |||||||||||||||||
31-Dec-13 | ||||||||||||||||||
Nuclear decommissioning trust (1) | ||||||||||||||||||
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 (2) | ||||||||||||||||||
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—Accounting for Asset Retirement and Environmental Obligations. Unrealized gains and losses related to assets held in the nuclear decommissioning trust are deferred as a regulatory asset or liability, respectively. | |||||||||||||||||
-2 | Investments in lease deposits are restricted for the use of funding our future lease obligations. See Note 8—Long-term Lease Transaction. | |||||||||||||||||
Our investments by classification at December 31, 2014 and 2013, were as follows: | ||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||
Carrying | Carrying | |||||||||||||||||
Description | Cost | Value | Cost | Value | ||||||||||||||
(in thousands) | ||||||||||||||||||
Available for sale | $ | 110,316 | $ | 145,822 | $ | 103,235 | $ | 134,454 | ||||||||||
Held to maturity | 103,832 | 103,832 | 119,008 | 119,008 | ||||||||||||||
Equity | 2,210 | 2,210 | 2,349 | 2,349 | ||||||||||||||
Trading | 151 | 198 | 131 | 173 | ||||||||||||||
$ | 216,509 | $ | 252,062 | $ | 224,723 | $ | 255,984 | |||||||||||
Contractual maturities of debt securities at December 31, 2014, were as follows: | ||||||||||||||||||
Less than | More than | |||||||||||||||||
Description | 1 year | 1-5 years | 5-10 years | 10 years | Total | |||||||||||||
(in thousands) | ||||||||||||||||||
Available for sale (1) | $ | - | $ | - | $ | 45,170 | $ | - | $ | 45,170 | ||||||||
Held to maturity | 519 | 103,233 | 80 | - | 103,832 | |||||||||||||
$ | 519 | $ | 103,233 | $ | 45,250 | $ | - | $ | 149,002 | |||||||||
(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. | ||||||||||||||||||
Regulatory_Assets_And_Liabilit
Regulatory Assets And Liabilities | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Regulatory Assets And Liabilities [Abstract] | ||||||
Regulatory Assets And Liabilities | ||||||
NOTE 10—Regulatory Assets and Liabilities | ||||||
In accordance with Accounting for Regulated Operations, we record regulatory assets and liabilities that result from our ratemaking. Our regulatory assets and liabilities at December 31, 2014 and 2013, were as follows: | ||||||
December 31, | ||||||
2014 | 2013 | |||||
(in thousands) | ||||||
Regulatory Assets: | ||||||
Unamortized losses on reacquired debt | $ | 15,571 | $ | 17,435 | ||
Deferred asset retirement costs | 346 | 363 | ||||
NOVEC contract termination fee | 34,256 | 36,703 | ||||
Loan acquisition fee | 671 | 894 | ||||
Interest rate hedge | 2,710 | 2,879 | ||||
North Anna Unit 3 | 22,748 | 22,748 | ||||
Voluntary prepayment to NRECA Retirement Security Plan | 6,188 | 6,961 | ||||
Deferred net unrealized losses on derivative instruments | 5,497 | - | ||||
Total Regulatory Assets | $ | 87,987 | $ | 87,983 | ||
Regulatory Assets included in Current Assets: | ||||||
Deferred energy | $ | 19,948 | $ | - | ||
Regulatory Liabilities: | ||||||
North Anna asset retirement obligation deferral | $ | 42,733 | $ | 39,581 | ||
Norfolk Southern settlement | - | 5,136 | ||||
North Anna nuclear decommissioning trust unrealized gain | 35,506 | 31,220 | ||||
Unamortized gains on reacquired debt | 525 | 584 | ||||
Deferred net unrealized gains on derivative instruments | - | 419 | ||||
Total Regulatory Liabilities | $ | 78,764 | $ | 76,940 | ||
Regulatory Liabilities included in Current Liabilities: | ||||||
Deferred energy | $ | - | $ | 37,193 | ||
The regulatory assets will be recognized as expenses concurrent with their recovery through rates and the regulatory liabilities will be recognized as a reduction to expenses concurrent with their return through rates. | ||||||
Regulatory assets included in deferred charges are detailed as follows: | ||||||
· | Unamortized losses on reacquired debt are the costs we incurred to purchase our outstanding indebtedness prior to its scheduled retirement. These losses are amortized over the life of the original indebtedness and will be fully amortized in 2023. | |||||
· | Deferred asset retirement costs reflect the cumulative effect of a change in accounting principle for the Clover and distributed generation facilities as a result of the adoption of Accounting for Asset Retirement and Environmental Obligations. These costs will be fully amortized in 2034. | |||||
· | NOVEC contract termination fee reflects the amount allocated to the contract value of the payment to NOVEC in 2008 as part of the termination agreement. The wholesale power contract with NOVEC was scheduled to expire in 2028, thus the contract termination fee will be amortized ratably through 2028 through amortization of regulatory asset/(liability), net. | |||||
· | Loan acquisition fee reflects the one-time fee we paid to the investor to facilitate the acquisition of the $33.0 million loan related to the lease of Clover Unit 1. This fee will be amortized ratably over the remaining life of the lease and will be fully amortized in 2018. | |||||
· | Interest rate hedge. To mitigate a portion of our exposure to fluctuations in long-term interest rates related to the debt we issued in 2011, we entered into an interest rate hedge. This will be amortized over the life of the 2011 debt and will be fully amortized in 2050. | |||||
· | North Anna Unit 3. In February 2011, we made the determination not to participate in North Anna Unit 3 and on December 16, 2011, we finalized our withdrawal as a participant in the project and transferred our interest to Virginia Power. Related to this decision, in 2011 we reclassified the corresponding construction work in progress to a regulatory asset. Reimbursement of costs recorded in the regulatory asset to us by Virginia Power is subject to the VSCC approval. We cannot currently estimate if or when Virginia Power will seek approval from the VSCC. If these costs are not determined to be collectible from Virginia Power, we will begin amortizing our regulatory asset and collect these costs from our member distribution cooperatives through our formula rate. | |||||
· | Voluntary prepayment to NRECA Retirement Security 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 fully amortized in 2022. | |||||
· | Deferred net unrealized losses on derivative instruments will be matched and recognized in the same period the expense is incurred for the hedged item. | |||||
Regulatory assets included in current assets are detailed as follows: | ||||||
· | Deferred energy balance represents the net accumulation of under-collection of energy costs. We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Under-collected deferred energy balances are charged to our members in subsequent periods. | |||||
Regulatory liabilities included in deferred credits and other liabilities are detailed as follows: | ||||||
· | North Anna asset retirement obligation deferral is the cumulative effect of change in accounting principle as a result of the adoption of Accounting for Asset Retirement and Environmental Obligations plus the deferral of subsequent activity primarily related to accretion expense offset by interest income on the nuclear decommissioning trust. | |||||
· | Norfolk Southern settlement reflects the difference in the amount previously accrued and the actual settlement amount. This balance was fully amortized as of the end of May 2014 as a reduction of fuel expense. | |||||
· | North Anna nuclear decommissioning trust unrealized gain reflects the unrealized gain on the investments in the nuclear decommissioning trust. | |||||
· | Unamortized gains on reacquired debt are the gains we recognized when we purchased our outstanding indebtedness prior to its scheduled retirement. These gains are amortized over the life of the original indebtedness and will be fully amortized in 2023. | |||||
· | Deferred net unrealized gains on derivative instruments will be matched and recognized in the same period the expense is incurred for the hedged item. | |||||
Regulatory liabilities included in current liabilities are detailed as follows: | ||||||
· | Deferred energy balance represents the net accumulation of over-collection of energy costs. We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Over-collected deferred energy balances are credited to our members in subsequent periods. | |||||
LongTerm_Debt
Long-Term Debt | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Long-Term Debt [Abstract] | |||||||||
Long-Term Debt | NOTE 11—Long-term Debt | ||||||||
Long-term debt consists of the following: | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(in thousands) | |||||||||
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due | $ | 50,000 | $ | 50,000 | |||||
2043 at an interest rate of 4.21% | |||||||||
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due | 50,000 | 50,000 | |||||||
2053 at an interest rate of 4.36% | |||||||||
$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due | |||||||||
2040 at an interest rate of 4.83% | 78,000 | 81,000 | |||||||
$165,000,000 principal amount of First Mortgage Bonds, 2011 Series B due | |||||||||
2040 at an interest rate of 5.54% | 165,000 | 165,000 | |||||||
$95,000,000 principal amount of First Mortgage Bonds, 2011 Series C due | |||||||||
2050 at an interest rate of 5.54% | 85,500 | 87,875 | |||||||
$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an | |||||||||
interest rate of 5.676% | 145,830 | 156,247 | |||||||
$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an | |||||||||
interest rate of 6.21% | 175,000 | 187,500 | |||||||
749,330 | 777,622 | ||||||||
Current maturities | -28,292 | -28,292 | |||||||
$ | 721,038 | $ | 749,330 | ||||||
At December 31, 2014 and 2013, deferred gains and losses on reacquired debt totaled a net loss of approximately $15.0 million and $16.9 million, respectively. Deferred gains and losses on reacquired debt are deferred under regulatory accounting. See Note 10—Regulatory Assets and Liabilities. | |||||||||
Maturities of long-term debt for the next five years and thereafter are as follows: | |||||||||
Year Ending December 31, | (in thousands) | ||||||||
2015 | $ | 28,292 | |||||||
2016 | 28,292 | ||||||||
2017 | 28,292 | ||||||||
2018 | 28,292 | ||||||||
2019 | 28,292 | ||||||||
2020 and thereafter | 607,870 | ||||||||
$ | 749,330 | ||||||||
The aggregate fair value of long-term debt was $847.7 million and $846.4 million at December 31, 2014 and 2013, respectively, based on current market prices. For debt issues that are not quoted on an exchange, interest rates currently available to us for issuance of debt with similar terms and remaining maturities are used to estimate fair value. | |||||||||
All of our long-term debt is issued under our Indenture. Substantially all of our real property and tangible personal property and some of our intangible personal property are pledged as collateral under the Indenture. Under the Indenture, we may not make any distribution, including a dividend or payment or retirement of patronage capital, to our members if an event of default exists under the Indenture. Otherwise, we may make a distribution to our members if (1) after the distribution, our patronage capital as of the end of the most recent fiscal quarter would be equal to or greater than 20% of our total long-term debt and patronage capital, or (2) all of our distributions for the year in which the distribution is to be made do not exceed 5% of the patronage capital as of the end of the most recent fiscal year. For this purpose, patronage capital and total long-term debt do not include any earnings retained in any of our subsidiaries or affiliates or the debt of any of our subsidiaries or affiliates. | |||||||||
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. | |||||||||
On June 28, 2013, we issued $100.0 million of first mortgage bonds in a private placement transaction. The issuance consisted 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. | |||||||||
On January 15, 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction. The issuance consisted of $260.0 million of 4.46% First Mortgage Bonds, 2015 Series A due December 1, 2044 and $72.0 million of 4.56% First Mortgage Bonds, 2015 Series B due December 1, 2053. | |||||||||
Additionally, we maintain a five-year revolving credit facility. See Note 12—Liquidity Resources. | |||||||||
Liquidity_Resources
Liquidity Resources | 12 Months Ended |
Dec. 31, 2014 | |
Liquidity Resources [Abstract] | |
Liquidity Resources | NOTE 12—Liquidity Resources |
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. At December 31, 2014, we had $86.0 million in borrowings outstanding under this facility at an interest rate of 1.5%. Additionally, at December 31, 2014, we had a letter of credit in the amount of $10.0 million outstanding. We did not have any borrowings or letters of credit outstanding under this facility at December 31, 2013; however, the interest rate on any borrowings would have been 1.1%. | |
In February 2015, we utilized funds from the January 2015 private placement transaction to repay amounts outstanding under our revolving credit facility. As of March 10, 2015, we did not have any outstanding borrowings under the revolving credit facility; however, we anticipate that we will borrow under this facility in the future. | |
On March 12, 2014, we amended and extended our $500.0 million, five-year revolving credit agreement with CoBank, ACB, Wells Fargo Securities, LLC, Merrill Lynch, Pierce Fenner & Smith Incorporated, J.P. Morgan Securities LLC, and PNC Capital Markets LLC as joint lead arrangers; CoBank, ACB, as syndication agent; Wells Fargo Bank, National Association, as administrative agent and swingline lender; and Bank of America, N.A., JPMorgan Chase Bank, N.A., and PNC Bank, N.A. as documentation agents. Commitments under the credit agreement now extend until March 5, 2019, unless earlier terminated in accordance with the agreement. | |
Borrowings under the credit agreement that are based on Eurodollar rates bear interest at LIBOR plus a margin ranging from 0.90% to 1.5%, depending on our credit ratings. Borrowings not based on Eurodollar rates, including swingline borrowings, bear interest at the highest of (1) the federal funds effective rate plus 0.5%, (2) the prime commercial lending rate of the administrative agent, and (3) the daily LIBOR for a one-month interest period plus 1.0%, plus in each case a margin ranging from 0.0% to 0.5%. Additionally, we are also responsible for customary unused commitment fees, an administrative agent fee and letter of credit fees. | |
The credit agreement contains customary conditions to borrowing or the issuance of letters of credit, representations and warranties, and covenants. The credit agreement obligates us to maintain a debt to capitalization ratio of no more than 0.85 to 1.00 and to maintain a margins for interest ratio of no less than 1.10 times interest charges (calculated in accordance with our secured indenture as currently in effect). We are in compliance with the credit agreement. Obligations under the credit agreement may be accelerated following, among other things, (1) the failure to pay outstanding principal when due or other amounts, including interest, within five days after the due date, (2) a material misrepresentation, (3) a cross-payment default or cross-acceleration under specified indebtedness, (4) failure by us to perform any obligation relating to the credit agreement following, in some cases, specified cure periods, (5) bankruptcy or insolvency events, (6) invalidity of the credit agreement and related loan documentation or our assertion of invalidity, and (7) a failure by our member distribution cooperatives to pay amounts in excess of an agreed threshold owing to us beyond a specified cure period. | |
We maintain a policy which allows our member distribution cooperatives to prepay or extend payment on their monthly power bills. Under this policy, we pay interest on prepayment balances at a blended investment and short-term borrowing rate, and we charge interest on extended payment balances at a blended prepayment and short-term borrowing rate. Amounts prepaid by our member distribution cooperatives are included in accounts payable-members and totaled $35.2 million and $15.2 million at December 31, 2014 and 2013, respectively. Amounts extended by our member distribution cooperatives are included in accounts receivable-members and were zero at December 31, 2014, and totaled $10.8 million at December 31, 2013. | |
Employee_Benefits
Employee Benefits | 12 Months Ended |
Dec. 31, 2014 | |
Employee Benefits [Abstract] | |
Employee Benefits | NOTE 13—Employee Benefits |
Substantially all of our employees participate in the NRECA Retirement Security Plan, a noncontributory, defined benefit multiple employer master pension plan. The legal name of the plan is the NRECA Retirement Security Plan; the employer identification number is 53–0116145, and the plan number is 333. Plan information is available publicly through the annual Form 5500, including attachments. The plan year is January 1 through December 31. In total, the NRECA Retirement Security Plan was over 80% funded on January 1, 2014 and 2013, based on the PPA funding target and PPA actuarial value of assets on those dates. The cost of the plan is funded annually by payments to NRECA to ensure that annuities in amounts established by the plan will be available to individual participants upon their retirement. We also participate in a pension restoration plan, which is intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit from the Retirement Security Plan because of the IRC limitations. Our required contribution to the NRECA Retirement Security Plan and the pension restoration plan totaled $2.9 million in each of the years 2014, 2013, and 2012, respectively. In each of these years, our contributions represented less than 5% of the total contributions made to the plan by all participating employers. In 2013, we elected to make a voluntary prepayment of $7.7 million to the NRECA Retirement Security Plan and recorded this payment as a regulatory asset which will be fully amortized in 2022. There has been no funding improvement plan or rehabilitation plan implemented nor is one pending, and we did not pay a surcharge to the plan for 2014. Pension expense, inclusive of administrative fees, was $3.3 million, $3.0 million, and $3.0 million for 2014, 2013, and 2012, respectively. Pension expense for 2014 and 2013 includes $0.8 million related to the amortization of the voluntary prepayment regulatory asset. | |
We have also elected to participate in a defined contribution 401(k) retirement plan administered by TransAmerica Retirement Solutions. We match up to the first 2% of each participant’s base salary. Our matching contributions were $224,000, $206,000, and $204,000, in 2014, 2013, and 2012, respectively. | |
Other
Other | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Other [Abstract] | ||||
Other | NOTE 14—Other | |||
Recovery of Costs from PJM | ||||
On June 23, 2014, we filed a petition at FERC seeking recovery from PJM of approximately $14.9 million of unreimbursed costs, which were incurred during the first quarter of 2014 related to the dispatch of our combustion turbine generating facilities. The results of our petition cannot currently be determined and we have not recorded a receivable related to this matter. | ||||
Clean Power Plan | ||||
On June 2, 2014, the EPA proposed emission guidelines for CO2 from existing electric utility generating units under 111(d) of the CAA. This proposal, referred to as the Clean Power Plan, requires that each state develop, submit, and implement a plan to achieve the interim and final state-specific goals detailed in the rulemaking. The EPA proposal has defined the following four areas of focus which the states are to utilize to meet the proposed goals: | ||||
· | increase efficiency of existing fossil-fuel plants; | |||
· | increase dispatch of existing natural gas combined-cycle units; | |||
· | utilize and expand the use of zero-emitting generation (additional renewables and nuclear); and | |||
· | increase demand-side energy efficiency. | |||
Public hearings on the CPP were held by the EPA on July 29 – August 1, 2014, and the EPA expects to finalize the rule in the summer of 2015. There are a number of legal challenges related to the CPP, including whether or not the EPA can finalize standards for existing plants under Section 111(d) until standards are finalized for new plants under Section 111(b). We will continue to follow this rulemaking in order to determine potential impacts related to our existing facilities. Due to the general nature of the guidelines and the lack of specifics regarding state implementation, we cannot predict whether the final rules relating to the guidelines will have a material impact on our results of operations or financial condition. | ||||
Supplemental_Cash_Flows_Inform
Supplemental Cash Flows Information | 12 Months Ended |
Dec. 31, 2014 | |
Supplemental Cash Flows Information [Abstract] | |
Supplemental Cash Flows Information | NOTE 15—Supplemental Cash Flows Information |
Cash paid for interest, net of amounts capitalized, in 2014, 2013, and 2012, was $43.1 million, $44.3 million, and $45.4 million, respectively. Cash paid for income taxes was immaterial in 2014, 2013, and 2012. | |
Commitments_And_Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2014 | |
Commitments And Contingencies [Abstract] | |
Commitments And Contingencies | |
NOTE 16—Commitments and Contingencies | |
Environmental | |
We are subject to federal, state, and local laws and regulations and permits designed to both protect human health and the environment and to regulate the emission, discharge, or release of pollutants into the environment. We believe we are in material compliance with all current requirements of such environmental laws and regulations and permits. However, as with all electric utilities, the operation of our generating units could be affected by future environmental regulations. Capital expenditures and increased operating costs required to comply with any future regulations could be significant. | |
Insurance | |
The Price-Anderson Amendments Act of 1988 provides the public up to $13.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Owners of nuclear facilities could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. Virginia Power, the co-owner of North Anna, is responsible for operating North Anna. Under several of the nuclear insurance policies procured by Virginia Power to which we are a party, we are subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance companies. | |
As a joint owner of North Anna, we are a party to the insurance policies that Virginia Power procures to limit the risk of loss associated with a possible nuclear incident at the station, as well as policies regarding general liability and property coverage. All policies are administered by Virginia Power, which charges us for our proportionate share of the costs. | |
Our share of the maximum retrospective premium assessments for the coverage assessments described above is estimated to be a maximum of $32.6 million at December 31, 2014. | |
Selected_Quarterly_Financial_D
Selected Quarterly Financial Data | 12 Months Ended | ||||||||||||||
Dec. 31, 2014 | |||||||||||||||
Selected Quarterly Financial Data [Abstract] | |||||||||||||||
Selected Quarterly Financial Data | NOTE 17—Selected Quarterly Financial Data (Unaudited) | ||||||||||||||
A summary of the quarterly results of operations for the years 2014 and 2013 follows. Amounts reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods. Results for the interim periods may fluctuate as a result of weather conditions, changes in rates, and other factors. | |||||||||||||||
First | Second | Third | Fourth | ||||||||||||
Quarter | Quarter | Quarter | Quarter | Total | |||||||||||
(in thousands) | |||||||||||||||
Statement of Operations Data | |||||||||||||||
2014 | |||||||||||||||
Operating Revenues | $ | 265,096 | $ | 217,331 | $ | 233,904 | $ | 235,245 | $ | 951,576 | |||||
Operating Margin | 12,194 | 13,121 | 13,015 | 12,195 | 50,525 | ||||||||||
Net Margin attributable to ODEC | 2,310 | 2,330 | 2,349 | 2,111 | 9,100 | ||||||||||
2013 | |||||||||||||||
Operating Revenues | $ | 220,713 | $ | 187,623 | $ | 220,393 | $ | 213,340 | $ | 842,069 | |||||
Operating Margin | 14,302 | 13,130 | 14,010 | 11,148 | 52,590 | ||||||||||
Net Margin attributable to ODEC | 2,386 | 2,346 | 2,448 | 2,393 | 9,573 | ||||||||||
Summary_Of_Significant_Account1
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Summary Of Significant Accounting Policies [Abstract] | ||||||||||
General | General | |||||||||
The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and 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. During 2013, TEC refunded $7.8 million of equity to its owners in the form of a cash dividend. The assets and liabilities, and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $5.7 million at December 31, 2014 and December 31, 2013. The income taxes reported on our Consolidated Statements of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC. As TEC is 100% owned by our Class A members, its equity is presented as a non-controlling interest in our consolidated financial statements. Our non-controlling, 50% or less, ownership interest in other entities for which we have significant influence is recorded using the equity method of accounting. We have a power sales contract with TEC under which we may sell to TEC power that we do not need to meet the needs of our member distribution cooperatives. TEC then sells this power to the market under market-based rate authority granted by FERC. Additionally, we have a separate contract under which we may purchase natural gas from TEC. TEC does not engage in speculative trading. | ||||||||||
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 eleven Class A members are customer-owned electric distribution cooperatives engaged in the retail sale of power to customers located in Virginia, Delaware, and Maryland. Our sole Class B member, TEC, a taxable corporation, is 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. Our rates are not regulated by the public service commissions of the states in which our member distribution cooperatives operate, but are set periodically by a formula that was accepted for filing by FERC. | ||||||||||
We comply with the Uniform System of Accounts 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 did not have any other comprehensive income for the periods presented. | ||||||||||
Electric Plant | Electric Plant | |||||||||
Electric plant is stated at original cost when first placed in service. Such cost includes contract work, direct labor and materials, allocable overhead, an allowance for borrowed funds used during construction and asset retirement costs. Upon the partial sale or retirement of plant assets, the original asset cost and current disposal costs less sale proceeds, if any, are charged or credited to accumulated depreciation. In accordance with industry practice, no profit or loss is recognized in connection with normal sales and retirements of property units. | ||||||||||
Maintenance and repair costs are expensed as incurred. Replacements and renewals of items considered to be units of property are capitalized to the property accounts. | ||||||||||
Depreciation | Depreciation | |||||||||
We conduct depreciation studies approximately every five years and our depreciation rates were as follows: | ||||||||||
Depreciation Rates | ||||||||||
Generating Facility | 2014 | 2013 | 2012 | |||||||
Clover | 1.8 | % | 1.8 | % | 1.8 | % | ||||
North Anna | 3.0 | 3.0 | 3.0 | |||||||
Louisa | 3.5 | 3.5 | 3.5 | |||||||
Marsh Run | 3.2 | 3.2 | 3.2 | |||||||
Rock Springs | 3.3 | 3.3 | 3.3 | |||||||
Nuclear Fuel | ||||||||||
Our last depreciation study was performed in 2011. | ||||||||||
Nuclear Fuel | ||||||||||
Nuclear fuel is amortized on a unit of production basis sufficient to fully amortize the cost of fuel over its estimated service life and is recorded in fuel expense. | ||||||||||
Virginia Power, as operating agent of North Anna, has the sole authority and responsibility to procure nuclear fuel for the facility. Virginia Power advises us that it primarily uses long-term contracts to support North Anna’s nuclear fuel requirements and that worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent upon the market environment. We are not a direct party to any of these procurement contracts and we do not control their terms or duration. Virginia Power advises us that current agreements, inventories, and spot market availability are expected to support North Anna’s current and planned fuel supply needs for the near term and that additional fuel is purchased as required to attempt to ensure optimal cost and inventory levels. | ||||||||||
Under the Nuclear Waste Policy Act of 1982, the DOE is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as North Anna, in accordance with contracts executed with the DOE. The DOE did not begin accepting spent fuel in 1998 as specified in its contract. As a result, Virginia Power sought reimbursement for certain spent nuclear fuel-related costs incurred and in 2012 signed a settlement agreement with the DOE. By mutual agreement of the parties, the settlement agreement is extendable to provide for resolution of damages. The settlement agreement has been extended to provide for periodic payments for damages incurred through December 31, 2016. During 2014 and 2013, we recorded our proportionate share of $0.9 million and $1.8 million, respectively, as a reduction to fuel expense related to the settlement agreement and during 2014, we also recorded a $0.6 million reduction to property, plant, and equipment, as the settlement includes a reimbursement of costs related to fixed assets. At December 31, 2014 and 2013, we had an outstanding receivable of $3.3 million and $3.9 million, respectively. | ||||||||||
Fuel, Materials, And Supplies | Fuel, Materials, and Supplies | |||||||||
Fuel, materials, and supplies is primarily comprised of fuel and spare parts for our generating assets. Fuel, which consists primarily of coal and No. 2 fuel oil, is recorded at cost. Spare parts for our generating assets are recorded at cost. | ||||||||||
Allowance For Borrowed Funds Used During Construction | Allowance for Borrowed Funds Used During Construction | |||||||||
Allowance for borrowed funds used during construction is defined as the net cost of borrowed funds used for construction purposes during the construction period and a reasonable rate on other funds when so used. We capitalize interest on borrowings for significant construction projects. Interest capitalized in 2014, 2013, and 2012, was $0.9 million, $0.2 million, and $1.0 million, respectively. | ||||||||||
Income Taxes | Income Taxes | |||||||||
As a not-for-profit electric cooperative, we are currently exempt from federal income taxation under IRC Section 501(c)(12), and we intend to continue to operate in this manner. Based on our assessment and evaluations of relevant authority, we believe we could sustain treatment as a tax-exempt utility in the event of a challenge of our tax status. Accordingly, no provision for income taxes has been recorded based on ODEC’s operations in the accompanying consolidated financial statements. | ||||||||||
TEC is a taxable corporation and its provision for income taxes was immaterial for the years ended December 31, 2014, 2013, and 2012. | ||||||||||
Operating Revenues | Operating Revenues | |||||||||
Our operating revenues are derived from sales to our members and non-members and are recorded when power, including renewable energy credits, is delivered. We sell energy to our Class A members pursuant to long-term wholesale power contracts that we maintain with each of our member distribution cooperatives. These wholesale power contracts obligate each member distribution cooperative to pay us for power furnished in accordance with our rates. For the years ended December 31, 2014, 2013, and 2012, revenue from sales to our member distribution cooperatives, including the sale of renewable energy credits, was $908.0 million, $810.1 million, and $826.8 million, respectively. For the years ended December 31, 2014, 2013, and 2012, the sale of renewable energy credits included in revenue from sales to our member distribution cooperatives was $1.3 million and $1.4 million in 2014 and 2013, respectively, and was immaterial in 2012. See Note 5—Wholesale Power Contracts. | ||||||||||
We sell excess purchased and generated energy, if any, to TEC, our Class B member, or to third parties under FERC market-based rate authority. Sales to TEC consist of sales of excess energy that we do not need to meet the actual needs of our member distribution cooperatives. TEC’s sales to third parties are reflected as non-member revenues; however, in 2014, 2013, and 2012, TEC had no sales to third parties. Excess purchased and generated energy that is not sold to TEC is sold to PJM under its rates for providing energy imbalance service, or to third parties. For the years ended December 31, 2014, 2013, and 2012, energy sales to non-members, including the sale of renewable energy credits, were $43.5 million, $31.9 million, and $15.9 million, respectively. For the years ended December 31, 2014, 2013, and 2012, the sale of renewable energy credits included in energy sales to non-members was $5.9 million, $6.1 million, and $0.5 million, respectively. | ||||||||||
Formula Rate | Formula Rate | |||||||||
Regulatory Assets And Liabilities | 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 credited or charged 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 is 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 “Legal Proceedings” in Part I, Item 3. | ||||||||||
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 PJM members; and | |||||||||
· | 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: | ||||||||||
· | 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 recorded. | |||||||||
· | 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. | |||||||||
For the year ended December 31, 2014, we did not record an adjustment to operating revenues utilizing Margin Stabilization, since the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equaled 19.5% of our actual total interest charges. In accordance with our formula rate, no adjustment is recorded if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, is more than 10% but less than 20% of our actual total interest charges. For the years ended December 31, 2013 and 2012, we recorded a reduction in operating revenues of $9.8 million and $15.0 million, respectively, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges. See “Critical Accounting Policies—Margin Stabilization” above. | ||||||||||
We may revise our budget at any time to the extent that our current budget does not accurately reflect our costs and expenses or estimates of our sales of power. Increases or decreases in our budget automatically amend the energy and/or the demand components of our formula rate, as necessary. The formula rate also permits us to adjust revenues from the member distribution cooperatives to equal our actual total demand costs. We make these adjustments under Margin Stabilization. See “Critical Accounting Policies—Margin Stabilization” above. If at any time our board of directors determines that the formula does not meet all of our costs and expenses, it may adopt a new formula to meet those costs and expenses, subject to any necessary regulatory review and approval. | ||||||||||
Regulatory Assets and Liabilities | ||||||||||
We account for certain revenues and expenses as a rate-regulated entity in accordance with Accounting for Regulated Operations. This allows certain of our revenues and expenses to be deferred at the discretion of our board of directors, which has budgetary and rate setting authority, if it is probable that these amounts will be recovered or returned through our formula rate in future periods. Regulatory assets represent costs that we expect to recover from our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory liabilities represent probable future reductions in our revenues associated with amounts that we expect to return to our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory assets are included in deferred charges and regulatory liabilities are included in deferred credits and other liabilities. Deferred energy, which can be either a regulatory asset or a regulatory liability, is included in current assets or current liabilities, respectively. See “Deferred Energy” below. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses, respectively, concurrent with their recovery through rates. | ||||||||||
Debt Issuance Costs | Debt Issuance Costs | |||||||||
Capitalized costs associated with the issuance of long-term debt and the revolving credit facility totaled $6.7 million at December 31, 2014 and 2013, and are included in deferred charges – other. These costs are being amortized using the effective interest method over the life of the respective long-term debt issuances and the revolving credit facility, and are included in interest charges, net. | ||||||||||
Deferred Charges - Other | Deferred Charges – Other | |||||||||
Deferred charges – other, includes unamortized debt issuance costs, the deferred rent related to the Wildcat Point operating lease, NYMEX margin mark-to-market asset, and the long-term portion of the prepayment of premiums on an insurance policy related to Wildcat Point. | ||||||||||
Deferred Credits And Other Liabilities | Deferred Credits and Other Liabilities – Other | |||||||||
Deferred credits and other liabilities – other, includes NYMEX margin mark-to-market liability, Wildcat Point retainage, a gain on a long-term lease transaction (see Note 8—Long-term Lease Transaction), DOE decontamination and decommissioning liability, and liabilities associated with benefit plans for certain executives. | ||||||||||
Deferred Energy | Deferred Energy | |||||||||
We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. The deferred energy balance represents the net accumulation of any under- or over-collection of energy costs. At December 31, 2014, we had an under-collected deferred energy balance of $19.9 million. At December 31, 2013, we had an over-collected deferred energy balance of $37.2 million. In January 2014, the entire mid-Atlantic region experienced extremely cold weather, which increased our member distribution cooperatives’ customers’ requirements for power as well as increased our purchased power and fuel expenses. As a result, our deferred energy balance changed from an over-collection of energy costs to an under-collection of energy costs. To address the under-collection of energy costs, we increased our total energy rate 11.8% effective April 1, 2014, and an additional 2.4% effective October 1, 2014. Under-collected deferred energy balances will be collected from our member distribution cooperatives in subsequent periods through our formula rate. Over-collected deferred energy balances are refunded to our member distribution cooperatives in subsequent periods. | ||||||||||
Financial Instruments (Including Derivatives) | Financial Instruments (including Derivatives) | |||||||||
Investments included in the nuclear decommissioning trust are classified as available for sale, and accordingly, are carried at fair value. Unrealized gains and losses on investments held in the nuclear decommissioning trust are deferred as a regulatory liability or a regulatory asset, respectively, until realized. | ||||||||||
Unrestricted investments and lease deposits in debt securities that we have the positive intent and ability to hold to maturity are classified as held to maturity and are recorded at amortized cost. Non-marketable equity investments in other investments are recorded at cost. Equity securities in other investments are recorded at fair value. See Note 9—Investments. | ||||||||||
We primarily purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution cooperatives. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase derivative contracts qualify for the normal purchases/normal sales exception provided for under Accounting for Derivatives and Hedging. As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the physically-delivered forward contract is delivered. We also purchase natural gas futures generally for three years or less to hedge the price of natural gas for the operation of our combustion turbine facilities. These derivatives do not qualify for the normal purchases/normal sales exception. | ||||||||||
For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we may elect cash flow hedge accounting in accordance with Accounting for Derivatives and Hedging. Accordingly, gains and losses on derivative contracts are deferred into other comprehensive income until the hedged underlying transaction occurs or is no longer likely to occur. We do not have any other comprehensive income for the periods presented. For derivative contracts where hedge accounting is not utilized, or for which ineffectiveness exists, we defer all remaining gains and losses on a net basis as a regulatory asset or regulatory liability, respectively, in accordance with Accounting for Regulated Operations. These amounts are subsequently reclassified as purchased power or fuel expense in our Consolidated Statements of Revenues, Expenses, and Patronage Capital as the power or fuel is delivered and/or the contract settles. There were no contracts for which we have elected cash flow hedge accounting and therefore, there was no hedge ineffectiveness during the years ended December 31, 2014, 2013, or 2012. | ||||||||||
Generally, derivatives are reported at fair value on the Consolidated Balance Sheet in the regulatory assets or regulatory liabilities account and deferred charges–other and deferred credits and other liabilities–other. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. | ||||||||||
Patronage Capital | Patronage Capital | |||||||||
We are organized and operate as a cooperative. Patronage capital represents our retained net margins, which have been allocated to our members based upon their respective power purchases in accordance with our bylaws. Any distributions of patronage capital are subject to the discretion of our board of directors and the restrictions contained in our Indenture and our syndicated credit agreement. See Note 11—Long-term Debt for discussion of the restrictions contained in the Indenture. | ||||||||||
Concentrations Of Credit Risk | Concentrations of Credit Risk | |||||||||
Financial instruments that potentially subject us to concentrations of credit risk consist of cash equivalents, investments, derivatives, and receivables arising from sales to our members and non-members. Concentrations of credit risk with respect to receivables arising from sales to our member distribution cooperatives as reflected by accounts receivable–members were $83.1 million and $88.5 million, at December 31, 2014 and 2013, respectively. | ||||||||||
Segment | Segment | |||||||||
We are organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis. Our President and CEO serves as our chief operating decision maker who manages and reviews our operating results as one operating, and therefore one reportable, segment. We supply our member distribution cooperatives’ energy and demand requirements through a portfolio of resources including generating facilities, physically-delivered forward power purchase contracts, and spot market energy purchases. | ||||||||||
Cash Equivalents | Cash Equivalents | |||||||||
For purposes of our Consolidated Statements of Cash Flows, we consider all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. | ||||||||||
Reclassifications | Reclassifications | |||||||||
Certain reclassifications have been made to the prior years’ consolidated financial statements to conform to the current year’s presentation. | ||||||||||
Summary_Of_Significant_Account2
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Summary Of Significant Accounting Policies [Abstract] | ||||||||||
Schedule Of Depreciation Rates | ||||||||||
Depreciation Rates | ||||||||||
Generating Facility | 2014 | 2013 | 2012 | |||||||
Clover | 1.8 | % | 1.8 | % | 1.8 | % | ||||
North Anna | 3.0 | 3.0 | 3.0 | |||||||
Louisa | 3.5 | 3.5 | 3.5 | |||||||
Marsh Run | 3.2 | 3.2 | 3.2 | |||||||
Rock Springs | 3.3 | 3.3 | 3.3 | |||||||
Electric_Plant_Tables
Electric Plant (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Electric Plant [Abstract] | |||||||||||||||||||
Schedule Of Public Utility Property, Plant, And Equipment | Our net electric plant is comprised of the following for 2014: | ||||||||||||||||||
Combustion | |||||||||||||||||||
North | Turbine | Wildcat | |||||||||||||||||
Clover | Anna | Facilities | Point | Other | Total | ||||||||||||||
(in thousands) | |||||||||||||||||||
Property, plant, and equipment | $ | 678,006 | $ | 351,636 | $ | 587,955 | $ | - | $ | 72,958 | $ | 1,690,555 | |||||||
Accumulated depreciation | -352,271 | -190,317 | -218,020 | - | -23,607 | -784,215 | |||||||||||||
Net Property, plant, and equipment | 325,735 | 161,319 | 369,935 | - | 49,351 | 906,340 | |||||||||||||
Nuclear fuel, at amortized cost | - | 19,376 | - | - | - | 19,376 | |||||||||||||
Construction work in progress | 11,364 | 33,580 | - | 115,779 | 11,230 | 171,953 | |||||||||||||
Net Electric Plant | $ | 337,099 | $ | 214,275 | $ | 369,935 | $ | 115,779 | $ | 60,581 | $ | 1,097,669 | |||||||
Our net electric plant is comprised of the following for 2013: | |||||||||||||||||||
Combustion | |||||||||||||||||||
North | Turbine | ||||||||||||||||||
Clover | Anna | Facilities | Other | Total | |||||||||||||||
(in thousands) | |||||||||||||||||||
Property, plant, and equipment (1) | $ | 671,708 | $ | 335,151 | $ | 585,067 | $ | 68,622 | $ | 1,660,548 | |||||||||
Accumulated depreciation | -349,197 | -184,314 | -198,520 | -23,257 | -755,288 | ||||||||||||||
Net Property, plant, and equipment | 322,511 | 150,837 | 386,547 | 45,365 | 905,260 | ||||||||||||||
Nuclear fuel, at amortized cost | - | 23,636 | - | - | 23,636 | ||||||||||||||
Construction work in progress | 6,670 | 20,536 | - | 9,276 | 36,482 | ||||||||||||||
Net Electric Plant | $ | 329,181 | $ | 195,009 | $ | 386,547 | $ | 54,641 | $ | 965,378 | |||||||||
-1 | Other includes $6.0 million related to Wildcat Point and $3.1 million for transmission. | ||||||||||||||||||
Accounting_For_Asset_Retiremen1
Accounting For Asset Retirement And Environmental Obligations (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Accounting For Asset Retirement And Environmental Obligations [Abstract] | ||||
Schedule Of Changes In Asset Retirement Obligations | ||||
Asset retirement obligations at December 31, 2012 | $ | 76,880 | ||
Accretion expense | 3,980 | |||
Asset retirement obligations at December 31, 2013 | $ | 80,860 | ||
Accretion expense | 3,870 | |||
Increase in asset retirement obligations - new layer | 17,953 | |||
Additional asset retirement obligations, net | 2,253 | |||
Asset retirement obligations at December 31, 2014 | $ | 104,936 | ||
Power_Purchase_Agreements_Tabl
Power Purchase Agreements (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Power Purchase Agreements [Abstract] | |||||
Schedule Of Energy And Capacity Purchase Commitments | |||||
Energy and | |||||
Capacity | |||||
Year Ending December 31, | Obligations | ||||
(in millions) | |||||
2015 | $ | 279.8 | |||
2016 | 200.3 | ||||
2017 | 161.5 | ||||
$ | 641.6 | ||||
Wholesale_Power_Contracts_Tabl
Wholesale Power Contracts (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Wholesale Power Contracts [Abstract] | ||||||||||
Schedule Of Revenues From Member Distribution Cooperatives | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
(in millions) | ||||||||||
Rappahannock Electric Cooperative | $ | 311.7 | $ | 275.9 | $ | 280.4 | ||||
Shenandoah Valley Electric Cooperative | 172.1 | 150.4 | 152.1 | |||||||
Delaware Electric Cooperative, Inc. | 106.8 | 94.7 | 95.4 | |||||||
Choptank Electric Cooperative, Inc. | 80.2 | 72.1 | 75.9 | |||||||
Southside Electric Cooperative | 70.2 | 64.5 | 66.0 | |||||||
A&N Electric Cooperative | 53.0 | 47.8 | 48.4 | |||||||
Mecklenburg Electric Cooperative | 43.8 | 39.7 | 40.6 | |||||||
Prince George Electric Cooperative | 23.5 | 21.6 | 22.1 | |||||||
Northern Neck Electric Cooperative | 21.3 | 19.5 | 19.7 | |||||||
Community Electric Cooperative | 15.3 | 13.9 | 14.1 | |||||||
BARC Electric Cooperative | 10.1 | 10.0 | 12.1 | |||||||
Total | $ | 908.0 | $ | 810.1 | $ | 826.8 | ||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Fair Value Measurements [Abstract] | |||||||||||||
Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis | |||||||||||||
Quoted Prices | |||||||||||||
in Active | Significant | ||||||||||||
Markets for | Other | Significant | |||||||||||
Identical | Observable | Unobservable | |||||||||||
December 31, | Assets | Inputs | Inputs | ||||||||||
2014 | (Level 1) | (Level 2) | (Level 3) | ||||||||||
(in thousands) | |||||||||||||
Nuclear decommissioning trust (1)(2) | $ | 145,822 | $ | 45,573 | $ | 100,249 | $ | - | |||||
Unrestricted investments and other (3) | 198 | - | 198 | - | |||||||||
Total Financial Assets | $ | 146,020 | $ | 45,573 | $ | 100,447 | $ | - | |||||
Derivatives - gas and power (4) | $ | 5,215 | $ | 5,215 | $ | - | $ | - | |||||
Total Financial Liabilities | $ | 5,215 | $ | 5,215 | $ | - | $ | - | |||||
Quoted Prices | |||||||||||||
in Active | Significant | ||||||||||||
Markets for | Other | Significant | |||||||||||
Identical | Observable | Unobservable | |||||||||||
December 31, | Assets | Inputs | Inputs | ||||||||||
2013 | (Level 1) | (Level 2) | (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 9—Investments. | ||||||||||||
-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 which are recorded on our Consolidated Balance Sheet in either deferred charges-other or deferred credits and other liabilities–other, and which are indexed against NYMEX. For additional information about our derivative financial instruments see Note 1—Summary of Significant Accounting Policies. | ||||||||||||
Derivatives_And_Hedging_Tables
Derivatives And Hedging (Tables) | 12 Months Ended | ||||||||||||||
Dec. 31, 2014 | |||||||||||||||
Derivatives And Hedging [Abstract] | |||||||||||||||
Schedule Of Outstanding Derivative Instruments | |||||||||||||||
As of | As of | ||||||||||||||
31-Dec-14 | 31-Dec-13 | ||||||||||||||
Commodity | Unit of Measure | Quantity | Quantity | ||||||||||||
Natural Gas | MMBTU | 5,610,000 | 1,470,000 | ||||||||||||
Schedule Of Fair Value Of Derivative Instruments | |||||||||||||||
Fair Value | |||||||||||||||
As of | As of | ||||||||||||||
December 31, | December 31, | ||||||||||||||
Balance Sheet Location | 2014 | 2013 | |||||||||||||
(in thousands) | |||||||||||||||
Derivatives in an asset position: | |||||||||||||||
Natural gas futures contracts | Deferred charges-other | $ | - | $ | 412 | ||||||||||
Total derivatives in an asset position | $ | - | $ | 412 | |||||||||||
Derivatives in a liability position: | |||||||||||||||
Natural gas futures contracts | Deferred credits and other liabilities-other | $ | 5,215 | $ | - | ||||||||||
Total derivatives in a liability position | $ | 5,215 | $ | - | |||||||||||
Schedule Of Derivative Instruments On The Statement Of Revenues, Expenses, And Patronage Capital | |||||||||||||||
Amount of | Amount of Gain | ||||||||||||||
Gain (Loss) | (Loss) Reclassified | ||||||||||||||
Recognized in | Location of Gain | from Regulatory | |||||||||||||
Regulatory | (Loss) Reclassified | Asset/Liability into | |||||||||||||
Derivatives Accounted for | Asset/Liability for | from Regulatory | Income for the | ||||||||||||
Utilizing Regulatory | Derivatives as of | Asset/Liability into | Year Ended | ||||||||||||
Accounting | December 31, | Income | December 31, | ||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
(in thousands) | (in thousands) | ||||||||||||||
Natural gas futures contracts (1) | $ | -5,497 | $ | 419 | Fuel | $ | -1,170 | $ | -3,031 | ||||||
Purchased power contracts - excess sales | - | - | Operating revenues | 90 | - | ||||||||||
Total | $ | -5,497 | $ | 419 | $ | -1,080 | $ | -3,031 | |||||||
-1 | As of December 31, 2014, includes a regulatory liability of $0.3 million and as of December 31, 2013, includes a regulatory asset of $7.0 thousand, to be recognized in future periods as the result of the contracts being effectively settled. | ||||||||||||||
Investments_Tables
Investments (Tables) | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||
Investments [Abstract] | ||||||||||||||||||
Schedule Of Investments | ||||||||||||||||||
Gross | Gross | |||||||||||||||||
Unrealized | Unrealized | Fair | Carrying | |||||||||||||||
Description | Designation | Cost | Gains | Losses | Value | Value | ||||||||||||
(in thousands) | ||||||||||||||||||
31-Dec-14 | ||||||||||||||||||
Nuclear decommissioning trust (1) | ||||||||||||||||||
Debt securities | Available for sale | $ | 41,654 | $ | 3,516 | $ | - | $ | 45,170 | $ | 45,170 | |||||||
Equity securities | Available for sale | 68,259 | 31,990 | - | 100,249 | 100,249 | ||||||||||||
Cash and other | Available for sale | 403 | - | - | 403 | 403 | ||||||||||||
Total Nuclear Decommissioning Trust | $ | 110,316 | $ | 35,506 | $ | - | $ | 145,822 | $ | 145,822 | ||||||||
Lease Deposits (2) | ||||||||||||||||||
Government obligations | Held to maturity | $ | 99,191 | $ | 5,569 | $ | - | $ | 104,760 | $ | 99,191 | |||||||
Total Lease Deposits | $ | 99,191 | $ | 5,569 | $ | - | $ | 104,760 | $ | 99,191 | ||||||||
Unrestricted investments | ||||||||||||||||||
Government obligations | Held to maturity | $ | 2,005 | $ | - | $ | - | $ | 2,005 | $ | 2,005 | |||||||
Debt securities | Held to maturity | 2,636 | - | -18 | 2,618 | 2,636 | ||||||||||||
Total Unrestricted Investments | $ | 4,641 | $ | - | $ | -18 | $ | 4,623 | $ | 4,641 | ||||||||
Other | ||||||||||||||||||
Equity securities | Trading | $ | 151 | $ | 47 | $ | - | $ | 198 | $ | 198 | |||||||
Non-marketable equity investments | Equity | 2,210 | 1,821 | - | 4,031 | 2,210 | ||||||||||||
Total Other | $ | 2,361 | $ | 1,868 | $ | - | $ | 4,229 | $ | 2,408 | ||||||||
$ | 252,062 | |||||||||||||||||
31-Dec-13 | ||||||||||||||||||
Nuclear decommissioning trust (1) | ||||||||||||||||||
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 (2) | ||||||||||||||||||
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—Accounting for Asset Retirement and Environmental Obligations. Unrealized gains and losses related to assets held in the nuclear decommissioning trust are deferred as a regulatory asset or liability, respectively. | |||||||||||||||||
-2 | Investments in lease deposits are restricted for the use of funding our future lease obligations. See Note 8—Long-term Lease Transaction. | |||||||||||||||||
Schedule Of Investments By Classification | ||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||
Carrying | Carrying | |||||||||||||||||
Description | Cost | Value | Cost | Value | ||||||||||||||
(in thousands) | ||||||||||||||||||
Available for sale | $ | 110,316 | $ | 145,822 | $ | 103,235 | $ | 134,454 | ||||||||||
Held to maturity | 103,832 | 103,832 | 119,008 | 119,008 | ||||||||||||||
Equity | 2,210 | 2,210 | 2,349 | 2,349 | ||||||||||||||
Trading | 151 | 198 | 131 | 173 | ||||||||||||||
$ | 216,509 | $ | 252,062 | $ | 224,723 | $ | 255,984 | |||||||||||
Schedule Of Contractual Maturities Of Debt Securities | ||||||||||||||||||
Less than | More than | |||||||||||||||||
Description | 1 year | 1-5 years | 5-10 years | 10 years | Total | |||||||||||||
(in thousands) | ||||||||||||||||||
Available for sale (1) | $ | - | $ | - | $ | 45,170 | $ | - | $ | 45,170 | ||||||||
Held to maturity | 519 | 103,233 | 80 | - | 103,832 | |||||||||||||
$ | 519 | $ | 103,233 | $ | 45,250 | $ | - | $ | 149,002 | |||||||||
(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. | ||||||||||||||||||
Regulatory_Assets_And_Liabilit1
Regulatory Assets And Liabilities (Tables) | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Regulatory Assets And Liabilities [Abstract] | ||||||
Schedule Of Regulatory Assets And Liabilities | ||||||
December 31, | ||||||
2014 | 2013 | |||||
(in thousands) | ||||||
Regulatory Assets: | ||||||
Unamortized losses on reacquired debt | $ | 15,571 | $ | 17,435 | ||
Deferred asset retirement costs | 346 | 363 | ||||
NOVEC contract termination fee | 34,256 | 36,703 | ||||
Loan acquisition fee | 671 | 894 | ||||
Interest rate hedge | 2,710 | 2,879 | ||||
North Anna Unit 3 | 22,748 | 22,748 | ||||
Voluntary prepayment to NRECA Retirement Security Plan | 6,188 | 6,961 | ||||
Deferred net unrealized losses on derivative instruments | 5,497 | - | ||||
Total Regulatory Assets | $ | 87,987 | $ | 87,983 | ||
Regulatory Assets included in Current Assets: | ||||||
Deferred energy | $ | 19,948 | $ | - | ||
Regulatory Liabilities: | ||||||
North Anna asset retirement obligation deferral | $ | 42,733 | $ | 39,581 | ||
Norfolk Southern settlement | - | 5,136 | ||||
North Anna nuclear decommissioning trust unrealized gain | 35,506 | 31,220 | ||||
Unamortized gains on reacquired debt | 525 | 584 | ||||
Deferred net unrealized gains on derivative instruments | - | 419 | ||||
Total Regulatory Liabilities | $ | 78,764 | $ | 76,940 | ||
Regulatory Liabilities included in Current Liabilities: | ||||||
Deferred energy | $ | - | $ | 37,193 | ||
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Long-Term Debt [Abstract] | |||||||||
Schedule Of Long-Term Debt | |||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
(in thousands) | |||||||||
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due | $ | 50,000 | $ | 50,000 | |||||
2043 at an interest rate of 4.21% | |||||||||
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due | 50,000 | 50,000 | |||||||
2053 at an interest rate of 4.36% | |||||||||
$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due | |||||||||
2040 at an interest rate of 4.83% | 78,000 | 81,000 | |||||||
$165,000,000 principal amount of First Mortgage Bonds, 2011 Series B due | |||||||||
2040 at an interest rate of 5.54% | 165,000 | 165,000 | |||||||
$95,000,000 principal amount of First Mortgage Bonds, 2011 Series C due | |||||||||
2050 at an interest rate of 5.54% | 85,500 | 87,875 | |||||||
$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an | |||||||||
interest rate of 5.676% | 145,830 | 156,247 | |||||||
$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an | |||||||||
interest rate of 6.21% | 175,000 | 187,500 | |||||||
749,330 | 777,622 | ||||||||
Current maturities | -28,292 | -28,292 | |||||||
$ | 721,038 | $ | 749,330 | ||||||
Schedule Of Maturities Of Long-Term Debt | |||||||||
Year Ending December 31, | (in thousands) | ||||||||
2015 | $ | 28,292 | |||||||
2016 | 28,292 | ||||||||
2017 | 28,292 | ||||||||
2018 | 28,292 | ||||||||
2019 | 28,292 | ||||||||
2020 and thereafter | 607,870 | ||||||||
$ | 749,330 | ||||||||
Selected_Quarterly_Financial_D1
Selected Quarterly Financial Data (Tables) | 12 Months Ended | ||||||||||||||
Dec. 31, 2014 | |||||||||||||||
Selected Quarterly Financial Data [Abstract] | |||||||||||||||
Schedule Of Quarterly Financial Information | |||||||||||||||
First | Second | Third | Fourth | ||||||||||||
Quarter | Quarter | Quarter | Quarter | Total | |||||||||||
(in thousands) | |||||||||||||||
Statement of Operations Data | |||||||||||||||
2014 | |||||||||||||||
Operating Revenues | $ | 265,096 | $ | 217,331 | $ | 233,904 | $ | 235,245 | $ | 951,576 | |||||
Operating Margin | 12,194 | 13,121 | 13,015 | 12,195 | 50,525 | ||||||||||
Net Margin attributable to ODEC | 2,310 | 2,330 | 2,349 | 2,111 | 9,100 | ||||||||||
2013 | |||||||||||||||
Operating Revenues | $ | 220,713 | $ | 187,623 | $ | 220,393 | $ | 213,340 | $ | 842,069 | |||||
Operating Margin | 14,302 | 13,130 | 14,010 | 11,148 | 52,590 | ||||||||||
Net Margin attributable to ODEC | 2,386 | 2,346 | 2,448 | 2,393 | 9,573 | ||||||||||
Summary_Of_Significant_Account3
Summary Of Significant Accounting Policies (Narrative) (Details) (USD $) | 0 Months Ended | 12 Months Ended | |||
Oct. 01, 2014 | Apr. 01, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
item | |||||
Significant Accounting Policies [Line Items] | |||||
Reimbursement of nuclear fuel costs receivable | $3,300,000 | $3,900,000 | |||
Interest Costs Capitalized | 900,000 | 200,000 | 1,000,000 | ||
Member energy sales | 908,000,000 | 810,100,000 | 826,800,000 | ||
Renewable energy credit sales to member | 1,300,000 | 1,400,000 | |||
Non-member energy sales | 43,500,000 | 31,900,000 | 15,900,000 | ||
Renewable energy credit sales to non-members | 5,900,000 | 6,100,000 | 500,000 | ||
Number of power products for sale | 2 | ||||
Percentage of actual total interest charges | 19.50% | ||||
Adjustments under Margin Stabilization | 9,800,000 | 15,000,000 | |||
Capitalized costs associated with the issuance of debt | 6,700,000 | 6,700,000 | |||
Unamortized portion of the deferred gain | 3,200,000 | 4,300,000 | |||
Deferred energy under-collection | 19,948,000 | ||||
Deferred energy over-collection | 37,193,000 | ||||
Increase in total energy rate | 2.40% | 11.80% | |||
Accounts receivable - members | 83,108,000 | 88,545,000 | |||
TEC [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Refunded equity | 7,800,000 | ||||
Consolidated net assets | 5,700,000 | 5,700,000 | |||
Percentage of interest owned in subsidiary by our Class A members | 100.00% | ||||
Non-member energy sales | 0 | 0 | 0 | ||
Property, Plant and Equipment [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Reimbursement of nuclear fuel costs | 600,000 | ||||
Fuel Expense [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Reimbursement of nuclear fuel costs | $900,000 | $1,800,000 | |||
Class A Members [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Number of members | 11 | ||||
Number of directors | 2 | ||||
Class B Members [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Number of members | 1 | ||||
Number of directors | 1 | ||||
Minimum [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Percentage of actual total interest charges | 10.00% | ||||
Maximum [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Percentage of actual total interest charges | 20.00% |
Summary_Of_Significant_Account4
Summary Of Significant Accounting Policies (Schedule Of Depreciation Rates) (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Clover [Member] | |||
Segment Reporting Information [Line Items] | |||
Depreciation Rates | 1.80% | 1.80% | 1.80% |
North Anna [Member] | |||
Segment Reporting Information [Line Items] | |||
Depreciation Rates | 3.00% | 3.00% | 3.00% |
Louisa [Member] | |||
Segment Reporting Information [Line Items] | |||
Depreciation Rates | 3.50% | 3.50% | 3.50% |
Marsh Run [Member] | |||
Segment Reporting Information [Line Items] | |||
Depreciation Rates | 3.20% | 3.20% | 3.20% |
Rock Springs [Member] | |||
Segment Reporting Information [Line Items] | |||
Depreciation Rates | 3.30% | 3.30% | 3.30% |
Electric_Plant_Narrative_Detai
Electric Plant (Narrative) (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jan. 15, 2015 | |
Segment Reporting Information [Line Items] | ||||
Estimated project cost | $790,500,000 | |||
Administrative and general | 40,279,000 | 42,385,000 | 35,958,000 | |
Construction work in progress | 171,953,000 | 36,482,000 | ||
Clover [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Undivided ownership interest | 50.00% | |||
Power facility output | 874 | |||
Number of units | 2 | |||
Outstanding accounts payable balance | 11,400,000 | 12,700,000 | ||
Construction work in progress | 11,364,000 | 6,670,000 | ||
North Anna [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Decommissioning Liability, Noncurrent | 93,700,000 | 72,100,000 | ||
Undivided ownership interest | 11.60% | |||
Power facility output | 1,897 | |||
Percent of costs | 11.60% | |||
Number of units | 2 | |||
Outstanding accounts payable balance | 3,100,000 | 4,100,000 | ||
Construction work in progress | 33,580,000 | 20,536,000 | ||
Combustion Turbine Facilities [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Number of combustion facilities | 3 | |||
Transmission lines | 1,100 | |||
Transmission line capacity | 500 | |||
Substation Capacity | 500 | |||
Other [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Transmission lines | 100 | |||
Construction work in progress | 11,230,000 | 9,276,000 | ||
Wildcat Point [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Power facility output | 1,000 | |||
Number of combustion turbines | 2 | |||
Number of heat recovery systems | 2 | |||
Number of steam turbine generators | 1 | |||
Construction work in progress | 115,779,000 | |||
Non-capital cost expense | 4,500,000 | 7,700,000 | ||
2015 Series Bonds [Member] | Subsequent Event [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Debt instrument, face amount | $332,000,000 |
Electric_Plant_Schedule_Of_Pub
Electric Plant (Schedule Of Public Utility Property, Plant, And Equipment) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | |
In Thousands, unless otherwise specified | |||
Segment Reporting Information [Line Items] | |||
Property, plant, and equipment | $1,690,555 | $1,660,548 | [1] |
Accumulated depreciation | -784,215 | -755,288 | |
Net Property, plant, and equipment | 906,340 | 905,260 | |
Nuclear fuel | 19,376 | 23,636 | |
Construction work in progress | 171,953 | 36,482 | |
Net Electric Plant | 1,097,669 | 965,378 | |
Clover [Member] | |||
Segment Reporting Information [Line Items] | |||
Property, plant, and equipment | 678,006 | 671,708 | [1] |
Accumulated depreciation | -352,271 | -349,197 | |
Net Property, plant, and equipment | 325,735 | 322,511 | |
Construction work in progress | 11,364 | 6,670 | |
Net Electric Plant | 337,099 | 329,181 | |
North Anna [Member] | |||
Segment Reporting Information [Line Items] | |||
Property, plant, and equipment | 351,636 | 335,151 | [1] |
Accumulated depreciation | -190,317 | -184,314 | |
Net Property, plant, and equipment | 161,319 | 150,837 | |
Nuclear fuel | 19,376 | 23,636 | |
Construction work in progress | 33,580 | 20,536 | |
Net Electric Plant | 214,275 | 195,009 | |
Combustion Turbine Facilities [Member] | |||
Segment Reporting Information [Line Items] | |||
Property, plant, and equipment | 587,955 | 585,067 | [1] |
Accumulated depreciation | -218,020 | -198,520 | |
Net Property, plant, and equipment | 369,935 | 386,547 | |
Net Electric Plant | 369,935 | 386,547 | |
Wildcat Point [Member] | |||
Segment Reporting Information [Line Items] | |||
Property, plant, and equipment | 6,000 | ||
Construction work in progress | 115,779 | ||
Net Electric Plant | 115,779 | ||
Other [Member] | |||
Segment Reporting Information [Line Items] | |||
Property, plant, and equipment | 72,958 | 68,622 | [1] |
Accumulated depreciation | -23,607 | -23,257 | |
Net Property, plant, and equipment | 49,351 | 45,365 | |
Construction work in progress | 11,230 | 9,276 | |
Net Electric Plant | 60,581 | 54,641 | |
Transmission [Member] | |||
Segment Reporting Information [Line Items] | |||
Property, plant, and equipment | $3,100 | ||
[1] | Other includes $6.0 million related to Wildcat Point and $3.1 million for transmission. |
Accounting_For_Asset_Retiremen2
Accounting For Asset Retirement And Environmental Obligations (Narrative) (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Asset Retirement And Environmental Obligations [Line Items] | ||
Decommission study period | 4 years | |
Increase to asset retirement cost | $2,253,000 | |
North Anna [Member] | ||
Asset Retirement And Environmental Obligations [Line Items] | ||
North Anna's nuclear decommissioning asset retirement obligation | $93,700,000 | $72,100,000 |
Asset retirement obligations cash flow estimates useful life | 20 years |
Accounting_For_Asset_Retiremen3
Accounting For Asset Retirement And Environmental Obligations (Schedule Of Changes In Asset Retirement Obligations) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Accounting For Asset Retirement And Environmental Obligations [Abstract] | |||
Asset retirement obligations | $80,860 | $76,880 | |
Accretion expense | 3,870 | 3,980 | 3,739 |
Increase in asset retirement obligations - new layer | 17,953 | ||
Additional asset retirement obligations, net | 2,253 | ||
Asset retirement obligations | $104,936 | $80,860 | $76,880 |
Power_Purchase_Agreements_Narr
Power Purchase Agreements (Narrative) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Power Purchase Agreements [Abstract] | |||
Energy requirements from owned generating facilities | 40.20% | 39.40% | 33.40% |
Deposits from counterparties pursuant to contracts | $4,400 | ||
Purchased power | $518,814 | $463,159 | $471,557 |
Power_Purchase_Agreements_Sche
Power Purchase Agreements (Schedule Of Energy And Capacity Purchase Commitments) (Details) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2014 |
Power Purchase Agreements [Abstract] | |
2015 | $279.80 |
2016 | 200.3 |
2017 | 161.5 |
Energy and Capacity Purchase Obligations | $641.60 |
Wholesale_Power_Contracts_Narr
Wholesale Power Contracts (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2014 | |
MW | |
Wholesale Power Contracts [Abstract] | |
Wholesale power contract, expiration date | 1-Jan-54 |
Purchases under principal contract exceptions, percent of energy requirements | 1.40% |
Purchases under limited contract exceptions, percent of power received from owned generation or other suppliers | 5.00% |
Purchases under limited contract exceptions, amount of power received from owned generation or other suppliers | 5 |
Power received under limited exceptions to wholesale power contract | 8.7 |
Wholesale_Power_Contracts_Sche
Wholesale Power Contracts (Schedule Of Revenues From Member Distribution Cooperatives) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Related Party Transaction [Line Items] | |||
Member distribution revenue | $908 | $810.10 | $826.80 |
Rappahannock Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 311.7 | 275.9 | 280.4 |
Shenandoah Valley Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 172.1 | 150.4 | 152.1 |
Delaware Electric Cooperative, Inc. [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 106.8 | 94.7 | 95.4 |
Choptank Electric Cooperative, Inc. [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 80.2 | 72.1 | 75.9 |
Southside Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 70.2 | 64.5 | 66 |
A&N Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 53 | 47.8 | 48.4 |
Mecklenburg Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 43.8 | 39.7 | 40.6 |
Prince George Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 23.5 | 21.6 | 22.1 |
Northern Neck Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 21.3 | 19.5 | 19.7 |
Community Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 15.3 | 13.9 | 14.1 |
BARC Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | $10.10 | $10 | $12.10 |
Fair_Value_Measurements_Detail
Fair Value Measurements (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | $146,020 | $135,039 | ||
Financial Liabilities | 5,215 | |||
Derivatives - Gas And Power [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | 412 | [1] | ||
Financial Liabilities | 5,215 | [1] | ||
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | 45,573 | 43,246 | ||
Financial Liabilities | 5,215 | |||
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Derivatives - Gas And Power [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | 412 | [1] | ||
Financial Liabilities | 5,215 | [1] | ||
Significant Other Observable Inputs (Level 2) [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | 100,447 | 91,793 | ||
Nuclear Decommissioning Trust [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | 145,822 | [2],[3] | 134,454 | [2],[3] |
Nuclear Decommissioning Trust [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | 45,573 | [2],[3] | 42,661 | [2],[3] |
Nuclear Decommissioning Trust [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | 100,249 | [2],[3] | 91,793 | [2],[3] |
Unrestricted Investment And Other [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | 198 | [4] | 173 | [4] |
Unrestricted Investment And Other [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | 173 | [4] | ||
Unrestricted Investment And Other [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Financial Assets | $198 | [4] | ||
[1] | Derivatives - gas and power represent natural gas futures contracts which are recorded on our Consolidated Balance Sheet in either deferred charges-other or deferred credits and other liabilities-other, and which are indexed against NYMEX. For additional information about our derivative financial instruments see Note 1bSummary of Significant Accounting Policies | |||
[2] | For additional information about our nuclear decommissioning trust see Note 9bInvestments | |||
[3] | 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 | |||
[4] | Unrestricted investments and other includes investments that are related to equity securities |
Derivatives_And_Hedging_Schedu
Derivatives And Hedging (Schedule Of Outstanding Derivative Instruments) (Details) (Natural Gas [Member]) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
MMBTU | MMBTU | |
Natural Gas [Member] | ||
Derivative [Line Items] | ||
Quantity | 5,610,000 | 1,470,000 |
Derivatives_And_Hedging_Schedu1
Derivatives And Hedging (Schedule Of Derivative Instruments On The Statement Of Revenues, Expenses, And Patronage Capital) (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | |||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain (Loss) Recognized in Regulatory Asset/Liability for Derivatives | ($5,497,000) | $419,000 | ||
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income | -1,080,000 | -3,031,000 | ||
Regulatory asset to be recognized in the future | 7,000 | |||
Regulatory liability to be recognized in the future | 300,000 | |||
Natural Gas Future Contracts [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain (Loss) Recognized in Regulatory Asset/Liability for Derivatives | -5,497,000 | [1] | 419,000 | [1] |
Natural Gas Future Contracts [Member] | Fuel [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income | -1,170,000 | [1] | -3,031,000 | [1] |
Purchased Power Contracts [Member] | Operating Revenues [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income | $90,000 | |||
[1] | As of December 31, 2014, includes a regulatory liability of $0.3 million and as of December 31, 2013, includes a regulatory asset of $7.0 thousand, to be recognized in future periods as the result of the contracts being effectively settled |
LongTerm_Lease_Transaction_Det
Long-Term Lease Transaction (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Long-Term Lease Transaction [Abstract] | ||
Lease term | 48 years 9 months 18 days | |
Lease value | $315 | |
Leaseback term | 21 years 9 months 18 days | |
Deferred gain | 23.7 | |
Unamortized portion of the deferred gain | 3.2 | 4.3 |
Payment undertaking agreement | 308.5 | |
Debt considered to be extinguished by in substance defeasance | $308.50 | $309.70 |
Investments_Schedule_Of_Invest
Investments (Schedule Of Investments) (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Schedule of Invested Securities [Line Items] | ||||
Available for sale, Cost | $110,316 | $103,235 | ||
Available for sale, Fair Value | 145,822 | 134,454 | ||
Held to maturity, Cost | 103,832 | 119,008 | ||
Equity, Cost | 2,210 | 2,349 | ||
Trading, Cost | 151 | 131 | ||
Trading, Fair Value | 198 | 173 | ||
Total Nuclear Decommissioning Trust | 145,822 | 134,454 | ||
Total Lease Deposits | 99,191 | 96,634 | ||
Total Carrying Value | 252,062 | 255,984 | ||
Nuclear Decommissioning Trust [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Available for sale, Cost | 110,316 | [1],[2] | 103,235 | [1],[2] |
Available for sale, Gross Unrealized Gains | 35,506 | [1],[2] | 31,219 | [1],[2] |
Available for sale, Fair Value | 145,822 | [1],[2] | 134,454 | [1],[2] |
Total Nuclear Decommissioning Trust | 145,822 | [1],[2] | 134,454 | [1],[2] |
Nuclear Decommissioning Trust [Member] | Debt Securities [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Available for sale, Cost | 41,654 | [1],[2] | 40,352 | [1],[2] |
Available for sale, Gross Unrealized Gains | 3,516 | [1],[2] | 1,719 | [1],[2] |
Available for sale, Fair Value | 45,170 | [1],[2] | 42,071 | [1],[2] |
Total Carrying Value | 45,170 | [1],[2] | 42,071 | [1],[2] |
Nuclear Decommissioning Trust [Member] | Equity Securities [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Available for sale, Cost | 68,259 | [1],[2] | 62,293 | [1],[2] |
Available for sale, Gross Unrealized Gains | 31,990 | [1],[2] | 29,500 | [1],[2] |
Available for sale, Fair Value | 100,249 | [1],[2] | 91,793 | [1],[2] |
Total Carrying Value | 100,249 | [1],[2] | 91,793 | [1],[2] |
Nuclear Decommissioning Trust [Member] | Cash And Other [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Available for sale, Cost | 403 | [1],[2] | 590 | [1],[2] |
Available for sale, Fair Value | 403 | [1],[2] | 590 | [1],[2] |
Total Carrying Value | 403 | [1],[2] | 590 | [1],[2] |
Lease Deposits [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Held to maturity, Cost | 99,191 | [2] | 96,634 | [2] |
Held to maturity, Gross Unrealized Gains | 5,569 | [2] | 5,676 | [2] |
Held to maturity, Fair Value | 104,760 | [2] | 102,310 | [2] |
Total Lease Deposits | 99,191 | [2] | 96,634 | [2] |
Lease Deposits [Member] | Government Obligations [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Held to maturity, Cost | 99,191 | [2] | 96,634 | [2] |
Held to maturity, Gross Unrealized Gains | 5,569 | [2] | 5,676 | [2] |
Held to maturity, Fair Value | 104,760 | [2] | 102,310 | [2] |
Total Carrying Value | 99,191 | [2] | 96,634 | [2] |
Unrestricted Investments [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Held to maturity, Cost | 4,641 | 22,374 | ||
Held to maturity, Gross Unrealized Gains | 1 | |||
Held to maturity, Gross Unrealized Losses | -18 | -4 | ||
Held to maturity, Fair Value | 4,623 | 22,371 | ||
Total Unrestricted Investments | 4,641 | 22,374 | ||
Unrestricted Investments [Member] | Government Obligations [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Held to maturity, Cost | 2,005 | 20,174 | ||
Held to maturity, Gross Unrealized Gains | 1 | |||
Held to maturity, Fair Value | 2,005 | 20,175 | ||
Total Carrying Value | 2,005 | 20,174 | ||
Unrestricted Investments [Member] | Debt Securities [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Held to maturity, Cost | 2,636 | 2,200 | ||
Held to maturity, Gross Unrealized Losses | -18 | -4 | ||
Held to maturity, Fair Value | 2,618 | 2,196 | ||
Total Carrying Value | 2,636 | 2,200 | ||
Other Debt Securities [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Other, Cost | 2,361 | 2,480 | ||
Other, Gross Unrealized Gains | 1,868 | 1,777 | ||
Other, Fair Value | 4,229 | 4,257 | ||
Total Other | 2,408 | 2,522 | ||
Other Debt Securities [Member] | Equity Securities [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Trading, Cost | 151 | 131 | ||
Trading, Gross Unrealized Gains | 47 | 42 | ||
Trading, Fair Value | 198 | 173 | ||
Total Carrying Value | 198 | 173 | ||
Other Debt Securities [Member] | Non-Marketable Equity Investments [Member] | ||||
Schedule of Invested Securities [Line Items] | ||||
Equity, Cost | 2,210 | 2,349 | ||
Equity, Gross Unrealized Gains | 1,821 | 1,735 | ||
Equity, Fair Value | 4,031 | 4,084 | ||
Total Carrying Value | $2,210 | $2,349 | ||
[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 3bAccounting for Asset Retirement and Environmental Obligations. Unrealized gains and losses related to assets held in the nuclear decommissioning trust are deferred as a regulatory asset or liability, respectively | |||
[2] | Investments in lease deposits are restricted for the use of funding our future lease obligations. See Note 8bLong-term Lease Transaction. |
Investments_Schedule_Of_Invest1
Investments (Schedule Of Investments By Classification) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Investments [Abstract] | ||
Available for sale, Cost | $110,316 | $103,235 |
Held to maturity, Cost | 103,832 | 119,008 |
Equity, Cost | 2,210 | 2,349 |
Trading, Cost | 151 | 131 |
Investments, Cost | 216,509 | 224,723 |
Available for sale, Carrying Value | 145,822 | 134,454 |
Held to maturity, Carrying Value | 103,832 | 119,008 |
Equity, Carrying Value | 2,210 | 2,349 |
Trading, Carrying Value | 198 | 173 |
Total Investments | $252,062 | $255,984 |
Investments_Schedule_Of_Contra
Investments (Schedule Of Contractual Maturities Of Debt Securities) (Details) (Unrestricted Securities [Member], USD $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | ||
Unrestricted Securities [Member] | ||
Contractual Maturities [Line Items] | ||
Available for sale securities, Less than 1 year | [1] | |
Available for sale securities, 1-5 years | [1] | |
Available for sale securities, 5-10 years | 45,170 | [1] |
Available for sale securities, More than 10 years | [1] | |
Available for sale securities, Total | 45,170 | [1] |
Held to maturity securities, Less than 1 year | 519 | |
Held to maturity securities, 1-5 years | 103,233 | |
Held to maturity securities, 5-10 years | 80 | |
Held to maturity securities, More than 10 years | ||
Held to maturity, carrying value | 103,832 | |
Contractual maturities of securities, Less than 1 year | 519 | |
Contractual maturities of securities, 1-5 years | 103,233 | |
Contractual maturities of securities, 5-10 years | 45,250 | |
Contractual maturities of securities, More than 10 years | ||
Contractual maturities of securities, Total | $149,002 | |
[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 |
Regulatory_Assets_And_Liabilit2
Regulatory Assets And Liabilities (Narrative) (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2014 |
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Loan acquisition fee | 33 | |
Multiple employer pension prepayment | $7.70 | |
Norfolk Southern Settlement [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Amortization date | 2014-05 | |
Unamortized Gains On Reacquired Debt [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Amortization year | 2023 | |
Unamortized Losses On Reacquired Debt [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Amortization year | 2023 | |
Deferred Asset Retirement Costs [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Amortization year | 2034 | |
NOVEC Contract Termination Fee [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Amortization year | 2028 | |
Loan Acquisition Fee [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Amortization year | 2018 | |
Interest Rate Hedge [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Amortization year | 2050 |
Regulatory_Assets_And_Liabilit3
Regulatory Assets And Liabilities (Schedule Of Regulatory Assets And Liabilities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory assets | $87,987 | $87,983 |
Regulatory liabilities | 78,764 | 76,940 |
North Anna Asset Retirement Obligation Deferral [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory liabilities | 42,733 | 39,581 |
Norfolk Southern Settlement [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory liabilities | 5,136 | |
North Anna Nuclear Decommissioning Trust Unrealized Gain [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory liabilities | 35,506 | 31,220 |
Unamortized Gains On Reacquired Debt [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory liabilities | 525 | 584 |
Deferred Energy [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Liabilities included in Current Liabilities | 37,193 | |
Deferred Net Unrealized Gains On Derivative Instruments [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory liabilities | 419 | |
Unamortized Losses On Reacquired Debt [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory assets | 15,571 | 17,435 |
Deferred Asset Retirement Costs [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory assets | 346 | 363 |
NOVEC Contract Termination Fee [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory assets | 34,256 | 36,703 |
Loan Acquisition Fee [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory assets | 671 | 894 |
Interest Rate Hedge [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory assets | 2,710 | 2,879 |
North Anna Unit 3 [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory assets | 22,748 | 22,748 |
Voluntary Prepayment To NRECA Retirement Security Plan [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory assets | 6,188 | 6,961 |
Deferred Net Unrealized Losses On Derivative Instruments [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory assets | 5,497 | |
Deferred Energy [Member] | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||
Regulatory Assets included in Current Assets | $19,948 |
LongTerm_Debt_Narrative_Detail
Long-Term Debt (Narrative) (Details) (USD $) | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2013 | Jun. 01, 2013 | Jun. 28, 2013 | Jan. 15, 2015 | |
Debt Instrument [Line Items] | |||||
Net loss on reacquired debt | $15,000,000 | $16,900,000 | |||
Fair value of long-term debt | 847,700,000 | 846,400,000 | |||
Percent of patronage capital to total long-term debt and patronage capital required for distribution | 20.00% | ||||
Maximum distribution as percent of patronage capital | 5.00% | ||||
2002 Series A Bonds [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate principle amount | 60,200,000 | ||||
Bond redemption date | 1-Jun-13 | ||||
Premium | 300,000 | ||||
Unamortized debt issuance costs | 1,500,000 | ||||
Unamortized debt issuance costs and premium | 1,800,000 | ||||
2013 Series Bonds [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate principle amount | 100,000,000 | ||||
First Mortgage Bonds, 2013 Series A Due 2043 At 4.21% [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate principle amount | 50,000,000 | 50,000,000 | 50,000,000 | ||
Debt instrument, interest rate | 4.21% | 4.21% | |||
First Mortgage Bonds, 2013 Series B Due 2053 At 4.36% [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate principle amount | 50,000,000 | 50,000,000 | 50,000,000 | ||
Debt instrument, interest rate | 4.36% | 4.36% | |||
Subsequent Event [Member] | 2015 Series Bonds [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate principle amount | 332,000,000 | ||||
Subsequent Event [Member] | First Mortgage Bonds, 2015 Series A Due 2044 At 4.46% [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate principle amount | 260,000,000 | ||||
Debt instrument, interest rate | 4.46% | ||||
Subsequent Event [Member] | First Mortgage Bonds, 2015 Series B Due 2053 At 4.56% [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate principle amount | $72,000,000 | ||||
Debt instrument, interest rate | 4.56% |
LongTerm_Debt_Schedule_Of_Long
Long-Term Debt (Schedule Of Long-Term Debt) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Jun. 28, 2013 | |
Debt Instrument [Line Items] | |||
Long-term debt | $749,330,000 | $777,622,000 | |
Current maturities | -28,292,000 | -28,292,000 | |
Long-term debt, excluding current maturities | 721,038,000 | 749,330,000 | |
First Mortgage Bonds, 2013 Series A Due 2043 At 4.21% [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | 50,000,000 | 50,000,000 | |
Debt instrument, face amount | 50,000,000 | 50,000,000 | 50,000,000 |
Debt instrument, maturity | 2043 | 2043 | |
Debt instrument, interest rate | 4.21% | 4.21% | |
First Mortgage Bonds, 2013 Series B Due 2053 At 4.36% [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | 50,000,000 | 50,000,000 | |
Debt instrument, face amount | 50,000,000 | 50,000,000 | 50,000,000 |
Debt instrument, maturity | 2053 | 2053 | |
Debt instrument, interest rate | 4.36% | 4.36% | |
First Mortgage Bonds, 2011 Series A Due 2040 At 4.83% [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | 78,000,000 | 81,000,000 | |
Debt instrument, face amount | 90,000,000 | 90,000,000 | |
Debt instrument, maturity | 2040 | 2040 | |
Debt instrument, interest rate | 4.83% | 4.83% | |
First Mortgage Bonds, 2011 Series B Due 2040 At 5.54% [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | 165,000,000 | 165,000,000 | |
Debt instrument, face amount | 165,000,000 | 165,000,000 | |
Debt instrument, maturity | 2040 | 2040 | |
Debt instrument, interest rate | 5.54% | 5.54% | |
First Mortgage Bonds, 2011 Series C Due 2050 At 5.54% [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | 85,500,000 | 87,875,000 | |
Debt instrument, face amount | 95,000,000 | 95,000,000 | |
Debt instrument, maturity | 2050 | 2050 | |
Debt instrument, interest rate | 5.54% | 5.54% | |
2003 Series A Bonds Due 2028 At 5.676% [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | 145,830,000 | 156,247,000 | |
Debt instrument, face amount | 250,000,000 | 250,000,000 | |
Debt instrument, maturity | 2028 | 2028 | |
Debt instrument, interest rate | 5.68% | 5.68% | |
2002 Series B Bonds Due 2028 At 6.21% [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | 175,000,000 | 187,500,000 | |
Debt instrument, face amount | $300,000,000 | $300,000,000 | |
Debt instrument, maturity | 2028 | 2028 | |
Debt instrument, interest rate | 6.21% | 6.21% |
LongTerm_Debt_Schedule_Of_Matu
Long-Term Debt (Schedule Of Maturities Of Long-Term Debt) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Long-Term Debt [Abstract] | ||
2015 | $28,292 | |
2016 | 28,292 | |
2017 | 28,292 | |
2018 | 28,292 | |
2019 | 28,292 | |
2020 and thereafter | 607,870 | |
Long-term debt | $749,330 | $777,622 |
Liquidity_Resources_Details
Liquidity Resources (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Short-term Debt [Line Items] | ||
Member distribution cooperatives, amount prepaid | $35.20 | 15.2 |
Member distribution cooperatives, amount extended | 10.8 | |
Federal Funds Effective Rate [Member] | ||
Short-term Debt [Line Items] | ||
Spread on variable rate | 0.50% | |
Daily LIBOR [Member] | ||
Short-term Debt [Line Items] | ||
Spread on variable rate | 1.00% | |
Revolving Credit Facility [Member] | ||
Short-term Debt [Line Items] | ||
Credit facility, maximum borrowing capacity | 500 | |
Credit facility, term | 5 years | |
Line of credit outstanding | 86 | |
Credit facility, interest rate | 1.50% | 1.10% |
Letter of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Line of credit outstanding | $10 | |
Minimum [Member] | ||
Short-term Debt [Line Items] | ||
Margins-for-interest ratio | 1.1 | |
Minimum [Member] | LIBOR [Member] | ||
Short-term Debt [Line Items] | ||
Spread on variable rate | 0.90% | |
Minimum [Member] | Daily LIBOR [Member] | ||
Short-term Debt [Line Items] | ||
Spread on variable rate margin | 0.00% | |
Maximum [Member] | ||
Short-term Debt [Line Items] | ||
Debt to capitalization ratio | 0.85 | |
Maximum [Member] | LIBOR [Member] | ||
Short-term Debt [Line Items] | ||
Spread on variable rate | 1.50% | |
Maximum [Member] | Daily LIBOR [Member] | ||
Short-term Debt [Line Items] | ||
Spread on variable rate margin | 0.50% |
Employee_Benefits_Details
Employee Benefits (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Employee Benefits [Abstract] | |||
Funded percentage | 80.00% | 80.00% | |
Contributions | $2,900,000 | $2,900,000 | $2,900,000 |
Pension expense, inclusive of administrative fees | 3,300,000 | 3,000,000 | 3,000,000 |
Matching contributions percentage | 2.00% | 2.00% | 2.00% |
Matching contributions | 224,000 | 206,000 | 204,000 |
Companies contribution as percentage of total contributions made | 5.00% | 5.00% | 5.00% |
Multiple employer pension prepayment | 7,700,000 | ||
Amortization of voluntary prepayment | $800,000 | $800,000 |
Other_Details
Other (Details) (USD $) | 0 Months Ended |
In Millions, unless otherwise specified | Jun. 23, 2014 |
Other [Abstract] | |
Unreimbursed costs | $14.90 |
Supplemental_Cash_Flows_Inform1
Supplemental Cash Flows Information (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Supplemental Cash Flows Information [Abstract] | |||
Cash paid for interest, net of amounts capitalized | $43.10 | $44.30 | $45.40 |
Commitments_And_Contingencies_
Commitments And Contingencies (Details) (USD $) | 12 Months Ended |
Dec. 31, 2014 | |
Commitments And Contingencies [Abstract] | |
Liability protection for nuclear incidents | $13,600,000,000 |
Liability protection for nuclear incidents inflationary provision adjustment period | 5 years |
Liability protection for nuclear incidents per reactor | 127,000,000 |
Liability protection for nuclear incidents per reactor per year | 19,000,000 |
Contingent liability for coverage, maximum | $32,600,000 |
Selected_Quarterly_Financial_D2
Selected Quarterly Financial Data (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Selected Quarterly Financial Data [Abstract] | |||||||||||
Operating Revenue | $235,245 | $233,904 | $217,331 | $265,096 | $213,340 | $220,393 | $187,623 | $220,713 | $951,576 | $842,069 | $842,681 |
Operating Margin | 12,195 | 13,015 | 13,121 | 12,194 | 11,148 | 14,010 | 13,130 | 14,302 | 50,525 | 52,590 | 59,145 |
Net Margin attributable to ODEC | $2,111 | $2,349 | $2,330 | $2,310 | $2,393 | $2,448 | $2,346 | $2,386 | $9,100 | $9,573 | $9,939 |