Document And Entity Information
Document And Entity Information | 12 Months Ended |
Dec. 31, 2017USD ($)shares | |
Document And Entity Information [Abstract] | |
Document Type | 10-K |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2017 |
Document Fiscal Year Focus | 2,017 |
Document Fiscal Period Focus | FY |
Entity Registrant Name | OLD DOMINION ELECTRIC COOPERATIVE |
Entity Central Index Key | 885,568 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | shares | 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 ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Electric Plant: | ||
Property, plant, and equipment | $ 1,754,236 | $ 1,746,852 |
Less accumulated depreciation | (891,701) | (855,068) |
Net Property, plant, and equipment | 862,535 | 891,784 |
Nuclear fuel, at amortized cost | 18,089 | 22,138 |
Construction work in progress | 822,667 | 736,996 |
Net Electric Plant | 1,703,291 | 1,650,918 |
Investments: | ||
Nuclear decommissioning trust | 183,681 | 159,155 |
Lease deposits | 106,812 | 104,514 |
Unrestricted investments and other | 7,009 | 6,599 |
Total Investments | 297,502 | 270,268 |
Current Assets: | ||
Cash and cash equivalents | 4,084 | 2,946 |
Accounts receivable | 10,379 | 6,563 |
Accounts receivable–members | 83,133 | 85,116 |
Fuel, materials, and supplies | 52,766 | 56,353 |
Deferred energy | 3,669 | |
Prepayments and other | 5,274 | 4,737 |
Total Current Assets | 159,305 | 155,715 |
Deferred Charges: | ||
Regulatory assets | 45,284 | 49,682 |
Other | 3,780 | 3,533 |
Total Deferred Charges | 49,064 | 53,215 |
Total Assets | 2,209,162 | 2,130,116 |
CAPITALIZATION AND LIABILITIES: | ||
Patronage capital | 415,384 | 402,857 |
Non-controlling interest | 5,744 | 5,725 |
Total Patronage capital and Non-controlling interest | 421,128 | 408,582 |
Long-term debt | 1,198,396 | 990,083 |
Revolving credit facility | 43,400 | 152,000 |
Total long-term debt and revolving credit facility | 1,241,796 | 1,142,083 |
Total Capitalization | 1,662,924 | 1,550,665 |
Current Liabilities: | ||
Long-term debt due within one year | 40,792 | 28,292 |
Accounts payable | 92,259 | 131,581 |
Accounts payable–members | 59,064 | 66,380 |
Accrued expenses | 6,391 | 5,806 |
Deferred energy | 40,029 | |
Regulatory liability-revenue deferral | 15,000 | |
Obligations under long-term lease | 103,683 | |
Total Current Liabilities | 317,189 | 272,088 |
Deferred Credits and Other Liabilities: | ||
Asset retirement obligations | 126,470 | 120,083 |
Obligations under long-term lease | 96,930 | |
Regulatory liabilities | 101,237 | 89,020 |
Other | 1,342 | 1,330 |
Total Deferred Credits and Other Liabilities | 229,049 | 307,363 |
Commitments and Contingencies | ||
Total Capitalization and Liabilities | $ 2,209,162 | $ 2,130,116 |
Consolidated Statements Of Reve
Consolidated Statements Of Revenues, Expenses, And Patronage Capital - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |||
Income Statement [Abstract] | |||||
Operating Revenues | $ 753,107 | $ 877,871 | $ 1,020,028 | ||
Operating Expenses: | |||||
Fuel | 94,603 | 138,391 | 159,917 | ||
Purchased power | 397,387 | 408,006 | 494,909 | ||
Transmission | 97,302 | 121,456 | 113,622 | ||
Deferred energy | (43,698) | 12,194 | 47,783 | ||
Operations and maintenance | 48,508 | 50,088 | 49,768 | ||
Administrative and general | 42,182 | 41,477 | 37,448 | ||
Depreciation and amortization | 45,433 | 45,739 | 45,168 | ||
Amortization of regulatory asset/(liability), net | 18,156 | 2,233 | 9,496 | ||
Accretion of asset retirement obligations | 5,044 | 4,839 | 4,695 | ||
Taxes, other than income taxes | 8,216 | 8,256 | 8,269 | ||
Total Operating Expenses | 713,133 | 832,679 | 971,075 | ||
Operating Margin | 39,974 | 45,192 | 48,953 | ||
Other expense, net | (3,826) | (3,811) | (3,339) | ||
Investment income | 12,950 | 5,411 | 5,519 | ||
Interest income on North Anna Unit 3 cost recovery | 4,598 | 6,393 | |||
Interest charges, net | (27,040) | (29,133) | (45,627) | ||
Income taxes | (11) | (1) | (3) | ||
Net Margin including Non-controlling interest | 26,645 | 17,658 | 11,896 | ||
Non-controlling interest | (18) | (21) | (17) | ||
Net Margin attributable to ODEC | 26,627 | [1] | 17,637 | [2] | 11,879 |
Patronage Capital - Beginning of Period | 402,857 | 390,976 | 379,097 | ||
Patronage Capital – Retirement | (14,100) | (5,756) | |||
Patronage Capital - End of Period | $ 415,384 | $ 402,857 | $ 390,976 | ||
[1] | For the fourth quarter of 2017, includes an equity contribution of $14.1 million. | ||||
[2] | For the fourth quarter of 2016, includes an equity contribution of $5.8 million. |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating Activities: | |||
Net Margin including Non-controlling interest | $ 26,645 | $ 17,658 | $ 11,896 |
Adjustments to reconcile net margin to net cash provided by operating activities: | |||
Depreciation and amortization | 45,433 | 45,739 | 45,168 |
Other non-cash charges | 18,899 | 18,177 | 18,706 |
Amortization of lease obligations | 6,753 | 6,308 | 5,893 |
Interest on lease deposits | (3,045) | (2,984) | (2,910) |
Change in current assets | 1,217 | 11,151 | (2,871) |
Change in deferred energy | (43,698) | 12,194 | 47,783 |
Change in current liabilities | (16,339) | (36,449) | 62,694 |
Change in regulatory assets and liabilities | 19,683 | 17,882 | 26,968 |
Change in deferred charges-other and deferred credits and other liabilities-other | 950 | (1,224) | 5,973 |
Net Cash Provided by Operating Activities | 56,498 | 88,452 | 219,300 |
Investing Activities: | |||
Purchases of held to maturity securities | (3,723) | (480) | (130,293) |
Proceeds from sale of held to maturity securities | 4,024 | 960 | 130,240 |
Increase in other investments | (12,522) | (4,300) | (4,726) |
Electric plant additions | (153,856) | (263,777) | (373,516) |
Net Cash Used for Investing Activities | (166,077) | (267,597) | (378,295) |
Financing Activities: | |||
Issuance of long-term debt | 250,000 | 332,000 | |
Debt issuance costs | (2,391) | (1,754) | |
Payments of long-term debt | (28,292) | (28,292) | (28,292) |
Draws on revolving credit facility | 385,400 | 333,850 | 104,000 |
Repayments on revolving credit facility | (494,000) | (181,850) | (190,000) |
Net Cash Provided by Financing Activities | 110,717 | 123,708 | 215,954 |
Net Change in Cash and Cash Equivalents | 1,138 | (55,437) | 56,959 |
Cash and Cash Equivalents - Beginning of Period | 2,946 | 58,383 | 1,424 |
Cash and Cash Equivalents - End of Period | $ 4,084 | $ 2,946 | $ 58,383 |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
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. The assets and liabilities, and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $5.7 million as of December 31, 2017 and December 31, 2016. The income taxes reported on our Consolidated Statements of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC, which is a taxable corporation. As TEC is 100% owned by our Class A members, its equity is presented as a non-controlling interest on 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 is TEC. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. Our rates are set periodically by a formula that was accepted for filing by FERC, and are not regulated by the public service commissions of the states in which our member distribution cooperatives operate. 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 use the group method of depreciation and conduct depreciation studies approximately every five years. Our last depreciation study was performed in 2016 and implemented in 2017. Our depreciation rates were as follows: Depreciation Rates Generating Facility 2017 2016 2015 Clover 1.9 % 1.8 % 1.8 % North Anna 3.3 3.0 3.0 Louisa 3.1 3.5 3.5 Marsh Run 3.0 3.2 3.2 Rock Springs 3.1 3.3 3.3 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, 2019. We continue to recognize receivables for certain spent nuclear fuel-related costs. We believe the recovery of these costs from the DOE is probable. As of December 31, 2017 and 2016, we had an outstanding receivable of $2.9 million and $3.3 million, respectively. Fuel, Materials, and Supplies Fuel, materials, and supplies is primarily composed of fuel and spare parts for our generating assets, and renewable energy credits, all of which are recorded at cost. Fuel consists primarily of coal and No. 2 fuel oil. 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 2017, 2016, and 2015, was $35.6 million, $30.3 million, and $13.8 million, respectively. Income Taxes We are a not-for-profit electric cooperative and 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, 2017, 2016, and 2015. Operating Revenues Our operating revenues are derived from sales to our members and non-members and are recorded when power and renewable energy credits are delivered. We sell power to our member distribution cooperatives pursuant to long-term wholesale power contracts that we maintain with each of them. These wholesale power contracts obligate each member distribution cooperative to pay us for power furnished in accordance with our rates. See Note 5—Wholesale Power Contracts. Revenues from sales to our member distribution cooperatives for the past three years were as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Sales to member distribution cooperatives excluding renewable energy credit sales $ 731,557 $ 844,539 $ 966,752 Renewable energy credit sales to member distribution cooperatives 19 2,555 2,173 Total Sales to Member Distribution Cooperatives $ 731,576 $ 847,094 $ 968,925 We sell excess purchased and generated energy, if any, to TEC, or 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 2017, 2016, and 2015, 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. Revenues from sales to non-members for the past three years were as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Sales to non-members excluding renewable energy credit sales $ 16,356 $ 21,645 $ 42,556 Renewable energy credit sales to non-members 5,175 9,132 8,547 Total Sales to Non-members $ 21,531 $ 30,777 $ 51,103 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. Our 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. The base energy rate 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 base energy rate is reset in accordance with our budget and the energy adjustment rate is reset to 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. We 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 that 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. • 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. 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 utilizing Margin Stabilization. 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. For the year ended December 31, 2017, our board of directors approved an additional equity contribution of $14.1 million and we recorded a reduction in operating revenues of $34.1 million, utilizing Margin Stabilization, to produce a net margin equal to 42.5% of our actual total interest charges. For the year ended December 31, 2016, our board of directors approved an additional equity contribution of $5.8 million and we recorded a reduction in operating revenues of $15.1 million utilizing Margin Stabilization, to produce a net margin equal to 29.7% of our actual total interest charges. For the year ended December 31, 2015, we recorded a reduction in operating revenues of $9.6 million, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges. 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 generally included in deferred charges and regulatory liabilities are generally 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 totaled $7.3 million and $6.4 million as of December 31, 2017 and 2016, respectively, and are included as a direct reduction to long-term debt. Capitalized costs associated with our revolving credit facility totaled $1.1 million and $0.4 million as of December 31, 2017 and 2016, respectively, and are recorded 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 revolving credit facility, and are included in interest charges, net. Deferred Energy In accordance with Accounting for Regulated Operations, 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. Under-collected energy costs appear as an asset and will be collected from our member distribution cooperatives in subsequent periods through our formula rate. Conversely, over-collected energy costs appear as a liability and will be returned to our member distribution cooperatives in subsequent periods through our formula rate. As of December 31, 2017 and 2016, we had an under-collected deferred energy balance of $3.7 million and an over-collected deferred energy balance of $40.0 million, respectively. To address the under- and over-collection of energy costs, we implemented rate changes as follows: Effective Date of Rate Change % Change January 1, 2016 (5.4) April 1, 2016 (6.8) September 1, 2016 (6.5) January 1, 2017 (6.7) January 1, 2018 11.1 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 these forward purchase derivative contracts qualify for the normal purchases/normal sales accounting exception 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 our facilities which utilize natural gas. These derivatives do not qualify for the normal purchases/normal sales accounting 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 liability or regulatory asset, respectively, in accordance with Accounting for Regulated Operations. These amounts are subsequently reclassified as purchased power or fuel expense 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, 2017, 2016, and 2015. 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. See Note 11—Long-term Debt for discussion of the restrictions contained in the Indenture. We operate on a not-for-profit basis and, accordingly, seek to generate revenues sufficient to recover our cost of service and produce margins sufficient to establish reasonable reserves, meet financial coverage requirements, and accumulate additional equity approved by our board of directors. On November 7, 2017, and December 13, 2016, our board of directors approved an additional equity contribution of $14.1 million and $5.8 million, respectively. Revenues in excess of expenses in any year are designated as net margin attributable to ODEC on our Consolidated Statements of Revenues, Expenses, and Patronage Capital. We designate retained net margins attributable to ODEC on our Consolidated Balance Sheet as patronage capital, which we assign to each of our members on the basis of its class of membership and business with us. On November 7, 2017, and December 13, 2016, our board of directors declared a patronage capital retirement of $14.1 million and $5.8 million, respectively. The $14.1 million patronage capital retirement is to be paid on April 2, 2018. The $5.8 million patronage capital retirement was paid on April 3, 2017. As a result of the November 7, 2017, and December 13, 2016, declarations, we reduced patronage capital and increased accounts payable–members by $14.1 million and $5.8 million, respectively. 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 $85.1 million, as of December 31, 2017 and 2016, 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. New Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update 2014-09 Revenue from Contracts with Customers. This update requires entities to recognize revenue when the transfer of promised goods or services to customers occurs in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We supply power requirements (energy and demand) to our eleven member distribution cooperatives subject to substantially identical wholesale power contracts with each of them. The revenues from these wholesale power contracts constituted at least 95% of our total revenues for the past three years. We have substantially completed our contract review of our wholesale power and other contracts within the scope of Topic 606, and are finalizing the last steps of our analysis. We currently do not anticipate a significant impact from adopting this standard and will adopt it in the first quarter of 2018. In February 2016, the FASB issued Accounting Standards Update 2016-02 Leases (Subtopic 835-30). This update revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. We are currently evaluating the impact of this pronouncement. We plan to adopt this standard for the fiscal year beginning January 1, 2019. |
Electric Plant
Electric Plant | 12 Months Ended |
Dec. 31, 2017 | |
Property Plant And Equipment [Abstract] | |
Electric Plant | NOTE 2—Electric Plant Our net electric plant is composed of the following as of December 31, 2017: Clover North Anna Combustion Turbine Facilities Wildcat Point Other Total (in thousands) Property, plant, and equipment $ 698,497 $ 366,423 $ 590,137 $ — $ 99,179 $ 1,754,236 Accumulated depreciation (375,106 ) (216,486 ) (271,225 ) — (28,884 ) (891,701 ) Net Property, plant, and equipment 323,391 149,937 318,912 — 70,295 862,535 Nuclear fuel, at amortized cost — 18,089 — — — 18,089 Construction work in progress 6,189 24,982 72 789,661 1,763 822,667 Net Electric Plant $ 329,580 $ 193,008 $ 318,984 $ 789,661 $ 72,058 $ 1,703,291 Our net electric plant is composed of the following as of December 31, 2016: Clover North Anna Combustion Turbine Facilities Wildcat Point Other Total (in thousands) Property, plant, and equipment $ 695,843 $ 365,646 $ 589,049 $ — $ 96,314 $ 1,746,852 Accumulated depreciation (364,602 ) (206,868 ) (257,026 ) — (26,572 ) (855,068 ) Net Property, plant, and equipment 331,241 158,778 332,023 — 69,742 891,784 Nuclear fuel, at amortized cost — 22,138 — — — 22,138 Construction work in progress 3,927 15,181 62 715,855 1,971 736,996 Net Electric Plant $ 335,168 $ 196,097 $ 332,085 $ 715,855 $ 71,713 $ 1,650,918 We hold a 50% undivided ownership interest in Clover, a two-unit, 877 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 on our consolidated financial statements in accordance with proportionate consolidation accounting. As of December 31, 2017 and 2016, we had an outstanding accounts payable balance of $10.4 million and $8.2 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, 1,892 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 on our consolidated financial statements in accordance with proportionate consolidation accounting. As of December 31, 2017 and 2016, we had an outstanding accounts payable balance of $8.8 million and $3.8 million, respectively, due to Virginia Power for operation, maintenance, and capital investment at North Anna. We own three combustion turbine facilities that are primarily fueled by natural gas. We also own six distributed generation facilities, which are included in “Other” in the net electric plant table. Additionally, we own approximately 110 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 the sole owner of an approximate 1,000 MW natural gas-fueled combined cycle generation facility, named Wildcat Point, in Cecil County, Maryland. Wildcat Point's major equipment consists of two Mitsubishi combustion turbines, two Alstom heat recovery steam generators, and one Alstom steam turbine generator. While the facility was scheduled to become operational in mid-2017, we currently anticipate that Wildcat Point will achieve substantial completion in the spring of 2018. The majority of construction has been completed; however, some additional construction work and testing is required before Wildcat Point becomes commercially operable and available for dispatch by PJM to meet a portion of our member distribution cooperatives’ power requirements. WOPC, the EPC contractor, claims that the delay was associated with the incurrence of additional work and other matters, including alleged misrepresentation under the EPC contract, for which it will seek recovery, in whole or in part, from its subcontractors and us. On May 24, 2017, WOPC filed a complaint against Alstom and us, in the United States District Court for the District of Maryland. An amended complaint was filed on July 21, 2017. On August 21, 2017, motions were filed by Alstom and us to transfer venue from the United States District Court for the District of Maryland to the United States District Court for the Eastern District of Virginia, and on November 7, 2017, these motions were granted. We have reviewed the asserted claims of WOPC against us and believe they are without merit. We do not believe any liability is estimable or probable and intend to vigorously defend against these claims. Additionally, on September 29, 2017, we filed a complaint in the United States District Court for the Eastern District of Virginia against WOPC, a joint venture, and its constituent members, PCL Industrial Construction Company and Sargent & Lundy, L.L.C., alleging that the companies have breached the contract they entered into with ODEC to engineer, procure, and construct Wildcat Point. On November 16, 2017, the United States District Court for the Eastern District of Virginia ordered that the WOPC complaint against Alstom and us, our complaint against WOPC, and a separate complaint filed by WOPC against Mitsubishi on May 9, 2017, be consolidated into one case. If it is ultimately determined that we owe any such amounts to WOPC, the amounts are not expected to have a material impact on our financial position or results of operations due to our ability to collect such amounts through rates to our member distribution cooperatives. Through December 31, 2017, we capitalized construction costs related to Wildcat Point totaling $789.7 million, including $77.8 million of capitalized interest, offset by $53.2 million of liquidated damages. We do not believe we have any additional liability associated with WOPC’s claims; and therefore, we continue to estimate that the total project cost, after consideration of liquidated damages, is consistent with our original project cost estimate of $834.3 million. |
Accounting For Asset Retirement
Accounting For Asset Retirement And Environmental Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [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 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, 2017 and 2016, North Anna’s nuclear decommissioning asset retirement obligation totaled $105.8 million and $101.6 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, are the primary drivers 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. In 2016, we recorded a $2.9 million decrease to an asset retirement obligation for Clover related to a change in estimate as a result of more refined cost information obtained during the contract bidding process. In 2017, we established a $2.1 million asset retirement obligation related to Wildcat Point and a $0.1 million asset retirement obligation related to one of our distributed generation facilities. The following represents changes in our asset retirement obligations for the years ended December 31, 2017 and 2016 (in thousands): Asset retirement obligations as of December 31, 2015 $ 118,200 Accretion expense 4,839 Decrease in asset retirement obligations (2,869 ) Payments (87 ) Asset retirement obligations as of December 31, 2016 $ 120,083 Accretion expense 5,044 Additional asset retirement obligations 2,210 Payments (867 ) Asset retirement obligations as of December 31, 2017 $ 126,470 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, 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. Virginia Power, the co-owner of North Anna, has announced its intention to apply for an additional 20-year operating license extension for North Anna. |
Power Purchase Agreements
Power Purchase Agreements | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Power Purchase Agreements | NOTE 4—Power Purchase Agreements In 2017, 2016, and 2015, our owned generating facilities together furnished approximately 36.7%, 45.2%, and 43.0%, 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 purchased 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 and sales of excess 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. We are required to post collateral from time to time due to changes in power prices. As of December 31, 2017, we had posted $12.0 million in letters of credit and as of December 31, 2016, we had posted $5.0 million in letters of credit. Our purchased power expense for 2017, 2016, and 2015 was $397.4 million, $408.0 million, and $494.9 million, respectively. As of December 31, 2017, our capacity and energy purchase obligations under the various agreements were as follows: Year Ending December 31, Capacity and Energy Obligations (in millions) 2018 $ 203.5 2019 186.8 2020 81.5 $ 471.8 |
Wholesale Power Contracts
Wholesale Power Contracts | 12 Months Ended |
Dec. 31, 2017 | |
Wholesale Power Contracts [Abstract] | |
Wholesale Power Contracts | NOTE 5—Wholesale Power Contracts Our financial relationships with our member distribution cooperatives are based primarily on our contractual arrangements for the supply of power and related transmission and ancillary services. These arrangements are set forth in our wholesale power contracts with our member distribution cooperatives which are effective until January 1, 2054, and beyond this date unless either party gives the other at least three years notice of termination. The wholesale power contracts are “all-requirements” contracts. Each contract obligates us to sell and deliver to our member distribution cooperative, and obligates our 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. An exception to the all-requirements obligations of our member distribution cooperatives relates to the ability of our eight mainland Virginia member distribution cooperatives to purchase hydroelectric power allocated to them from SEPA, a federal power marketing administration. Purchases under this exception constituted less than 2% of our member distribution cooperatives’ total energy requirements in 2017. There are two additional limited exceptions to the all-requirements nature of the contract. One exception permits each of our member distribution cooperatives, with 180 days prior written notice, to receive up to the greater of 5% of its demand and associated energy or 5 MW and associated energy from its owned generation or from other suppliers. The other exception permits our member distribution cooperatives to purchase additional power from other suppliers in limited circumstances following approval by our board of directors. If all of our member distribution cooperatives elected to utilize the 5% or 5 MW exception, we estimate the current impact would be a reduction of approximately 175 MW of demand and associated energy. As of May 1, 2018, there will be approximately 66 MW remaining that can be utilized under this exception. The following table summarizes the cumulative removal of load requirements under this exception since January 1, 2016. Date MW January 1, 2016 9 May 1, 2016 60 June 1, 2017 65 May 1, 2018 109 We do not anticipate that either the current or potential full utilization of this exception will have a material impact on our financial condition, results of operations, or cash flows. As of December 31, 2017, none of our member distribution cooperatives had utilized the other exception noted above. Each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract in accordance with our formula rate. We review our formula rate design at least every three years to consider whether it is appropriately achieving its intended results. 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. See “Regulation—Rate Regulation” in Item 1, "Legal Proceedings—FERC Proceeding Related to Formula Rate" in Item 3, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formula Rate” in Item 7. 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, 2017 2016 2015 (in millions) Rappahannock Electric Cooperative $ 217.7 $ 271.2 $ 334.2 Shenandoah Valley Electric Cooperative 146.8 164.5 181.0 Delaware Electric Cooperative, Inc. 97.5 105.9 114.0 Choptank Electric Cooperative, Inc. 69.7 77.2 83.8 Southside Electric Cooperative 58.4 67.9 76.5 A&N Electric Cooperative 46.0 51.1 55.5 Mecklenburg Electric Cooperative 36.7 41.2 47.4 Prince George Electric Cooperative 20.6 22.5 25.4 Northern Neck Electric Cooperative 18.2 21.3 23.4 Community Electric Cooperative 11.4 14.4 16.6 BARC Electric Cooperative 8.6 9.9 11.1 Total $ 731.6 $ 847.1 $ 968.9 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [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, 2017 and 2016: Quoted Prices in Active Significant Markets for Other Significant Identical Observable Observable December 31, Assets Inputs Inputs 2017 (Level 1) (Level 2) (Level 3) (in thousands) Nuclear decommissioning trust (1) $ 59,723 $ 59,723 $ — $ — Nuclear decommissioning trust - net asset value (1)(2) 123,958 — — — Unrestricted investments and other (3) 308 — 308 — Total Financial Assets $ 183,989 $ 59,723 $ 308 $ — Derivatives - gas and power (4) $ 1,034 $ 975 $ 59 $ — Total Financial Liabilities $ 1,034 $ 975 $ 59 $ — Quoted Prices in Active Significant Markets for Other Significant Identical Observable Observable December Assets Inputs Inputs 2016 (Level 1) (Level 2) (Level 3) (in thousands) Nuclear decommissioning trust (1) $ 48,142 $ 48,142 $ — $ — Nuclear decommissioning trust - net asset value (1)(2) 111,013 — — — Unrestricted investments and other (3) 247 — 247 — Derivatives - gas and power (4) 6,968 4,874 2,094 — Total Financial Assets $ 166,370 $ 53,016 $ 2,341 $ — (1) For additional information about our nuclear decommissioning trust, see Note 9—Investments. (2) Nuclear decommissioning trust includes investments measured at net asset value per share (or its equivalent) as a practical expedient and these investments have not been categorized in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Consolidated Balance Sheet. (3) Unrestricted investments and other includes investments that are related to equity securities. (4) Derivatives – gas and power represent natural gas futures contracts. Level 1 are indexed against NYMEX. Level 2 are valued by ACES using observable market inputs for similar transactions. 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, 2017 | |
Derivative Instruments And Hedging Activities Disclosure [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: Quantity As of As of Commodity Unit of Measure December 31, 2017 December 31, 2016 Natural Gas MMBTU 23,700,000 14,250,000 The fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows: Fair Value As of December 31, As of December 31, Balance Sheet Location 2017 2016 (in thousands) Derivatives in an asset position: Natural gas futures contracts Deferred charges-other $ — $ 6,968 Total derivatives in an asset position $ — $ 6,968 Derivatives in a liability position: Natural gas futures contracts Deferred credits and other liabilities-other $ 1,034 $ — Total derivatives in a liability position $ 1,034 $ — The Effect of Derivative Instruments on the Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Years Ended December 31, 2017 and 2016 Amount of Gain Amount of Gain Location of (Loss) Reclassified (Loss) Recognized Gain (Loss) from Regulatory in Regulatory Reclassified Asset/Liability Asset/Liability for from Regulatory into Income for Derivatives Accounted for Derivatives as of Asset/Liability the Year Utilizing Regulatory Accounting December 31, into Income Ended December 31, 2017 2016 2017 2016 (in thousands) (in thousands) Natural gas futures contracts $ (2,008 ) $ 7,005 Fuel $ 1,342 $ (2,369 ) Total $ (2,008 ) $ 7,005 $ 1,342 $ (2,369 ) |
Long-Term Lease Transaction
Long-Term Lease Transaction | 12 Months Ended |
Dec. 31, 2017 | |
Leases Capital [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 was amortized into income ratably over the 21.8 year operating lease term, as a reduction to depreciation and amortization expense. As of December 31, 2017, the deferred gain was fully amortized. 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. As of December 31, 2017, the payment undertaking agreement had a balance of $304.7 million, and the amount of debt considered to be extinguished by in substance defeasance We elected to purchase the owner trust’s interest in the unit and terminate the lease effective January 5, 2018, for a fixed purchase price of $430.5 million. On January 5, 2018, payments under the payment undertaking agreement funded $289.7 million of this amount, and $32.2 million was provided by us and in turn paid to us as the holder of a loan to the owner trust. The remaining balance of the fixed purchase price is funded by United States Treasury securities with a maturity value of $108.6 million and will be paid in four installments during 2018. |
Investments
Investments | 12 Months Ended |
Dec. 31, 2017 | |
Investments [Abstract] | |
Investments | NOTE 9—Investments Investments were as follows as of December 31, 2017 and 2016: Gross Gross Unrealized Unrealized Fair Carrying Description Designation Cost Gains Losses Value Value (in thousands) December 31, 2017 Nuclear decommissioning trust (1) Debt securities Available for sale $ 54,375 $ 5,029 $ — $ 59,404 $ 59,404 Equity securities Available for sale 77,838 46,474 (354 ) 123,958 123,958 Cash and other Available for sale 319 — — 319 319 Total Nuclear Decommissioning Trust $ 132,532 $ 51,503 $ (354 ) $ 183,681 $ 183,681 Lease Deposits (2) Government obligations Held to maturity $ 106,812 $ 776 $ — $ 107,588 $ 106,812 Total Lease Deposits $ 106,812 $ 776 $ — $ 107,588 $ 106,812 Unrestricted investments Government obligations Held to maturity $ 2,344 $ — $ (13 ) $ 2,331 $ 2,344 Debt securities Held to maturity 2,217 — (3 ) 2,214 2,217 Total Unrestricted Investments $ 4,561 $ — $ (16 ) $ 4,545 $ 4,561 Other Equity securities Trading $ 223 $ 85 $ — $ 308 $ 308 Non-marketable equity investments Equity 2,140 2,066 — 4,206 2,140 Total Other $ 2,363 $ 2,151 $ — $ 4,514 $ 2,448 $ 297,502 December 31, 2016 Nuclear decommissioning trust (1) Debt securities Available for sale $ 44,086 $ 3,537 $ — $ 47,623 $ 47,623 Equity securities Available for sale 75,332 35,958 (277 ) 111,013 111,013 Cash and other Available for sale 519 — — 519 519 Total Nuclear Decommissioning Trust $ 119,937 $ 39,495 $ (277 ) $ 159,155 $ 159,155 Lease Deposits (2) Government obligations Held to maturity $ 104,514 $ 2,948 $ — $ 107,462 $ 104,514 Total Lease Deposits $ 104,514 $ 2,948 $ — $ 107,462 $ 104,514 Unrestricted investments Government obligations Held to maturity $ 2,000 $ 1 $ - $ 2,001 $ 2,000 Debt securities Held to maturity 2,210 6 - 2,216 2,210 Total Unrestricted Investments $ 4,210 $ 7 $ - $ 4,217 $ 4,210 Other Equity securities Trading $ 198 $ 49 $ — $ 247 $ 247 Non-marketable equity investments Equity 2,142 2,012 — 4,154 2,142 Total Other $ 2,340 $ 2,061 $ — $ 4,401 $ 2,389 $ 270,268 (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 on investments held in the nuclear decommissioning trust are deferred as a regulatory liability or regulatory asset, 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 as of December 31, 2017 and 2016, were as follows: December 31, 2017 December 31, 2016 Carrying Carrying Description Cost Value Cost Value (in thousands) (in thousands) Available for sale $ 132,532 $ 183,681 $ 119,937 $ 159,155 Held to maturity 111,373 111,373 108,724 108,724 Equity 2,140 2,140 2,142 2,142 Trading 223 308 198 247 Total $ 246,268 $ 297,502 $ 231,001 $ 270,268 Contractual maturities of debt securities as of December 31, 2017, 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) $ — $ — $ 59,404 $ — $ 59,404 Held to maturity 111,018 355 — — 111,373 Total $ 111,018 $ 355 $ 59,404 $ — $ 170,777 (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 Liabiliti
Regulatory Assets And Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets And Liabilities Disclosure [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 as of December 31, 2017 and 2016, were as follows: December 31, 2017 2016 (in thousands) Regulatory Assets: Unamortized losses on reacquired debt $ 9,977 $ 11,841 Deferred asset retirement costs 296 313 NOVEC contract termination fee 26,915 29,362 Loan acquisition fee — 224 Interest rate hedge 2,220 2,381 Voluntary prepayment to NRECA Retirement Security Plan 3,868 4,641 Deferred net unrealized losses on derivative instruments 2,008 — Wildcat Point lease termination — 920 Total Regulatory Assets $ 45,284 $ 49,682 Regulatory Assets included in Current Assets: Deferred energy $ 3,669 $ — Regulatory Liabilities: North Anna asset retirement obligation deferral $ 49,739 $ 42,390 North Anna nuclear decommissioning trust unrealized gain 51,149 39,218 Unamortized gains on reacquired debt 349 407 Deferred net unrealized gains on derivative instruments — 7,005 Total Regulatory Liabilities $ 101,237 $ 89,020 Regulatory Liabilities included in Current Liabilities: Deferred energy $ — $ 40,029 Regulatory liability-revenue deferral $ 15,000 $ — The regulatory assets will be recognized as expenses concurrent with their recovery through rates and the regulatory liabilities will be recognized as reductions 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 was amortized ratably over the remaining life of the lease and was fully amortized as of December 31, 2017. • 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. • 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 pension plan qualified under Section 401 and tax-exempt under Section 501(a) of the Internal Revenue Code. It is considered a multi-employer plan under the accounting standards. We recorded this prepayment as a regulatory asset which will be fully amortized in 2022. See Note 13—Employee Benefits. • Deferred net unrealized losses on derivative instruments will be matched and recognized in the same period the expense is incurred for the hedged item. • Wildcat Point lease termination. We had a ground lease related to land and land rights associated with Wildcat Point that was accounted for as an operating lease. In 2015, we purchased the land and the land rights from Essential Power Rock Springs, LLC for $40.0 million. Prior to purchasing the land and land rights, thus terminating the ground lease, we made prepaid rent payments related to the ground lease. We established a regulatory asset for the unamortized portion of the prepaid rent which was fully amortized as of May 31, 2017. 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 collected from our member distribution cooperatives 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. • 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 member distribution cooperatives in subsequent periods. • Regulatory liability-revenue deferral to be amortized ratably in 2018 to reduce revenue requirements. |
Long-term Debt
Long-term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long-term Debt | NOTE 11—Long-term Debt Long-term debt consists of the following: December 31, 2017 2016 (in thousands) $250,000,000 principal amount of First Mortgage Bonds, 2017 Series A due 2037 at an interest rate of 3.33% $ 250,000 $ — $260,000,000 principal amount of First Mortgage Bonds, 2015 Series A due 2044 at an interest rate of 4.46% 260,000 260,000 $72,000,000 principal amount of First Mortgage Bonds, 2015 Series B due 2053 at an interest rate of 4.56% 72,000 72,000 $50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due 2043 at an interest rate of 4.21% 50,000 50,000 $50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due 2053 at an interest rate of 4.36% 50,000 50,000 $90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due 2040 at an interest rate of 4.83% 69,000 72,000 $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% 78,375 80,750 $250,000,000 principal amount of 2003 Series A Bonds due 2028 at an interest rate of 5.676% 114,579 124,996 $300,000,000 principal amount of 2002 Series B Bonds due 2028 at an interest rate of 6.21% 137,500 150,000 1,246,454 1,024,746 Debt issuance costs (7,266 ) (6,371 ) Current maturities (40,792 ) (28,292 ) $ 1,198,396 $ 990,083 As of December 31, 2017 and 2016, deferred gains and losses on reacquired debt totaled a net loss of approximately $9.6 million and $11.4 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) 2018 $ 40,792 2019 40,792 2020 40,792 2021 49,041 2022 49,041 2023 and thereafter 1,025,996 $ 1,246,454 The aggregate fair value of long-term debt was $1,320.1 million and $1,092.0 million as of December 31, 2017 and 2016, 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 secured 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. On July 6, 2017, we issued $250 million of long-term debt in a private placement transaction. The issuance consisted of $250 million of 3.33% First Mortgage Bonds, 2017 Series A due December 1, 2037. Additionally, we maintain a revolving credit facility. See Note 12—Liquidity Resources. |
Liquidity Resources
Liquidity Resources | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Liquidity Resources | NOTE 12—Liquidity Resources We maintain a revolving credit facility to cover our short-term and medium-term funding needs that are not met by cash from operations or other available funds. Commitments under this syndicated credit agreement extend until March 3, 2023. Available funding under this facility totals $500 million through March 3, 2022, and $400 million from March 4, 2022 through March 3, 2023. As of December 31, 2017, we had outstanding under this facility, $43.4 million in borrowings at a weighted average interest rate of 2.6% and $12.0 million in letters of credit. As of December 31, 2016, we had outstanding under this facility, $152.0 million in borrowings at a weighted average interest rate of 1.6% and $5.2 million in letters of credit. 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 Indenture). Obligations under the credit agreement may be accelerated following, among other things: • our failure to timely pay any principal and interest due under the credit facility; • a breach by us of our representations and warranties in the credit agreement or related documents; • a breach of a covenant contained in the credit agreement, which, in some cases we are given an opportunity to cure and, in certain cases, includes a debt to capitalization financial covenant; • failure to pay, when due, other indebtedness above a specified amount; • an unsatisfied judgment above specified amounts; • bankruptcy or insolvency events relating to us; • invalidity of the credit agreement and related loan documentation or our assertion of invalidity; and • 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 are in compliance with the credit agreement. We maintain a program which allows our member distribution cooperatives to prepay or extend payment on their monthly power bills. Under this program, 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 |
Employee Benefits
Employee Benefits | 12 Months Ended |
Dec. 31, 2017 | |
Postemployment Benefits [Abstract] | |
Employee Benefits | NOTE 13—Employee Benefits Substantially all of our employees participate in the NRECA Retirement Security Plan, a noncontributory, defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501(a) of the IRC. It is considered a multi-employer plan under the accounting standards. 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, 2017 and 2016, 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 the Deferred Compensation 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 Deferred Compensation Pension Restoration Plan totaled $3.2 million, $2.7 million, and $2.5 million in 2017, 2016, and 2015, 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 2017. Pension expense, inclusive of administrative fees, was $4.1 million, $3.6 million, and $3.4 million for 2017, 2016, and 2015, respectively. Pension expense for 2017, 2016, and 2015 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 $289,000, $240,000, and $231,000 in 2017, 2016, and 2015, respectively. |
Supplemental Cash Flows Informa
Supplemental Cash Flows Information | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flows Information | NOTE 14—Supplemental Cash Flows Information Cash paid for interest, net of amounts capitalized, in 2017, 2016, and 2015, was $23.8 million, $26.4 million, and $42.0 million, respectively. Cash paid for income taxes was immaterial in 2017, 2016, and 2015. Accrued capital expenditures in 2017, 2016, and 2015 were $23.1 million, $66.9 million, and $74.8 million, respectively. |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments And Contingencies | NOTE 15—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 changes in environmental laws and regulations, including new requirements. 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 $13.4 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and is subject to change every five years for inflation and for the number of licensed reactors. 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 $33.4 million at December 31, 2017. |
Subsequent Event
Subsequent Event | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Event | NOTE 16—SUBSEQUENT EVENT On March 13, 2018, our Board of Directors approved an increase to our total energy rate of approximately 3.7%, effective April 1, 2018. This increase was implemented due to changes in our realized as well as projected energy costs. |
Selected Quarterly Financial Da
Selected Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Selected Quarterly Financial Data (Unaudited) | NOTE 17—Selected Quarterly Financial Data (Unaudited) A summary of the quarterly results of operations for the years 2017 and 2016 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 Quarter Second Quarter Third Quarter Fourth Quarter Total (in thousands) Statement of Operations Data 2017 Operating Revenues $ 189,779 $ 156,907 $ 193,425 $ 212,996 $ 753,107 Operating Margin 8,641 (836 ) 9,813 22,356 39,974 Net Margin attributable to ODEC (1) 2,968 3,047 3,258 17,354 26,627 2016 Operating Revenues $ 256,459 $ 199,149 $ 222,802 $ 199,461 $ 877,871 Operating Margin 12,224 9,884 9,022 14,062 45,192 Net Margin attributable to ODEC (2) 2,953 2,955 2,991 8,738 17,637 (1) (2) |
Summary Of Significant Accoun22
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
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. The assets and liabilities, and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $5.7 million as of December 31, 2017 and December 31, 2016. The income taxes reported on our Consolidated Statements of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC, which is a taxable corporation. As TEC is 100% owned by our Class A members, its equity is presented as a non-controlling interest on 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 is TEC. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. Our rates are set periodically by a formula that was accepted for filing by FERC, and are not regulated by the public service commissions of the states in which our member distribution cooperatives operate. 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 use the group method of depreciation and conduct depreciation studies approximately every five years. Our last depreciation study was performed in 2016 and implemented in 2017. Our depreciation rates were as follows: Depreciation Rates Generating Facility 2017 2016 2015 Clover 1.9 % 1.8 % 1.8 % North Anna 3.3 3.0 3.0 Louisa 3.1 3.5 3.5 Marsh Run 3.0 3.2 3.2 Rock Springs 3.1 3.3 3.3 |
Nuclear Fuel | 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, 2019. We continue to recognize receivables for certain spent nuclear fuel-related costs. We believe the recovery of these costs from the DOE is probable. As of December 31, 2017 and 2016, we had an outstanding receivable of $2.9 million and $3.3 million, respectively. |
Fuel, Materials, And Supplies | Fuel, Materials, and Supplies Fuel, materials, and supplies is primarily composed of fuel and spare parts for our generating assets, and renewable energy credits, all of which are recorded at cost. Fuel consists primarily of coal and No. 2 fuel oil. |
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 2017, 2016, and 2015, was $35.6 million, $30.3 million, and $13.8 million, respectively. |
Income Taxes | Income Taxes We are a not-for-profit electric cooperative and 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, 2017, 2016, and 2015. |
Operating Revenues | Operating Revenues Our operating revenues are derived from sales to our members and non-members and are recorded when power and renewable energy credits are delivered. We sell power to our member distribution cooperatives pursuant to long-term wholesale power contracts that we maintain with each of them. These wholesale power contracts obligate each member distribution cooperative to pay us for power furnished in accordance with our rates. See Note 5—Wholesale Power Contracts. Revenues from sales to our member distribution cooperatives for the past three years were as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Sales to member distribution cooperatives excluding renewable energy credit sales $ 731,557 $ 844,539 $ 966,752 Renewable energy credit sales to member distribution cooperatives 19 2,555 2,173 Total Sales to Member Distribution Cooperatives $ 731,576 $ 847,094 $ 968,925 We sell excess purchased and generated energy, if any, to TEC, or 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 2017, 2016, and 2015, 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. Revenues from sales to non-members for the past three years were as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Sales to non-members excluding renewable energy credit sales $ 16,356 $ 21,645 $ 42,556 Renewable energy credit sales to non-members 5,175 9,132 8,547 Total Sales to Non-members $ 21,531 $ 30,777 $ 51,103 |
Formula Rate | 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. Our 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. The base energy rate 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 base energy rate is reset in accordance with our budget and the energy adjustment rate is reset to 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. We 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 that 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. • 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. 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 utilizing Margin Stabilization. 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. For the year ended December 31, 2017, our board of directors approved an additional equity contribution of $14.1 million and we recorded a reduction in operating revenues of $34.1 million, utilizing Margin Stabilization, to produce a net margin equal to 42.5% of our actual total interest charges. For the year ended December 31, 2016, our board of directors approved an additional equity contribution of $5.8 million and we recorded a reduction in operating revenues of $15.1 million utilizing Margin Stabilization, to produce a net margin equal to 29.7% of our actual total interest charges. For the year ended December 31, 2015, we recorded a reduction in operating revenues of $9.6 million, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges. |
Regulatory Assets And Liabilities | 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 generally included in deferred charges and regulatory liabilities are generally 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 totaled $7.3 million and $6.4 million as of December 31, 2017 and 2016, respectively, and are included as a direct reduction to long-term debt. Capitalized costs associated with our revolving credit facility totaled $1.1 million and $0.4 million as of December 31, 2017 and 2016, respectively, and are recorded 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 revolving credit facility, and are included in interest charges, net. |
Deferred Energy | Deferred Energy In accordance with Accounting for Regulated Operations, 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. Under-collected energy costs appear as an asset and will be collected from our member distribution cooperatives in subsequent periods through our formula rate. Conversely, over-collected energy costs appear as a liability and will be returned to our member distribution cooperatives in subsequent periods through our formula rate. As of December 31, 2017 and 2016, we had an under-collected deferred energy balance of $3.7 million and an over-collected deferred energy balance of $40.0 million, respectively. To address the under- and over-collection of energy costs, we implemented rate changes as follows: Effective Date of Rate Change % Change January 1, 2016 (5.4) April 1, 2016 (6.8) September 1, 2016 (6.5) January 1, 2017 (6.7) January 1, 2018 11.1 |
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 these forward purchase derivative contracts qualify for the normal purchases/normal sales accounting exception 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 our facilities which utilize natural gas. These derivatives do not qualify for the normal purchases/normal sales accounting 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 liability or regulatory asset, respectively, in accordance with Accounting for Regulated Operations. These amounts are subsequently reclassified as purchased power or fuel expense 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, 2017, 2016, and 2015. 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. See Note 11—Long-term Debt for discussion of the restrictions contained in the Indenture. We operate on a not-for-profit basis and, accordingly, seek to generate revenues sufficient to recover our cost of service and produce margins sufficient to establish reasonable reserves, meet financial coverage requirements, and accumulate additional equity approved by our board of directors. On November 7, 2017, and December 13, 2016, our board of directors approved an additional equity contribution of $14.1 million and $5.8 million, respectively. Revenues in excess of expenses in any year are designated as net margin attributable to ODEC on our Consolidated Statements of Revenues, Expenses, and Patronage Capital. We designate retained net margins attributable to ODEC on our Consolidated Balance Sheet as patronage capital, which we assign to each of our members on the basis of its class of membership and business with us. On November 7, 2017, and December 13, 2016, our board of directors declared a patronage capital retirement of $14.1 million and $5.8 million, respectively. The $14.1 million patronage capital retirement is to be paid on April 2, 2018. The $5.8 million patronage capital retirement was paid on April 3, 2017. As a result of the November 7, 2017, and December 13, 2016, declarations, we reduced patronage capital and increased accounts payable–members by $14.1 million and $5.8 million, respectively. |
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 $85.1 million, as of December 31, 2017 and 2016, 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. |
New Accounting Pronouncements | New Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update 2014-09 Revenue from Contracts with Customers. This update requires entities to recognize revenue when the transfer of promised goods or services to customers occurs in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We supply power requirements (energy and demand) to our eleven member distribution cooperatives subject to substantially identical wholesale power contracts with each of them. The revenues from these wholesale power contracts constituted at least 95% of our total revenues for the past three years. We have substantially completed our contract review of our wholesale power and other contracts within the scope of Topic 606, and are finalizing the last steps of our analysis. We currently do not anticipate a significant impact from adopting this standard and will adopt it in the first quarter of 2018. In February 2016, the FASB issued Accounting Standards Update 2016-02 Leases (Subtopic 835-30). This update revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. We are currently evaluating the impact of this pronouncement. We plan to adopt this standard for the fiscal year beginning January 1, 2019. |
Summary Of Significant Accoun23
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Schedule of Depreciation Rates | We use the group method of depreciation and conduct depreciation studies approximately every five years. Our last depreciation study was performed in 2016 and implemented in 2017. Our depreciation rates were as follows: Depreciation Rates Generating Facility 2017 2016 2015 Clover 1.9 % 1.8 % 1.8 % North Anna 3.3 3.0 3.0 Louisa 3.1 3.5 3.5 Marsh Run 3.0 3.2 3.2 Rock Springs 3.1 3.3 3.3 |
Schedule of Revenues From Sales to Member Distribution Cooperatives | Revenues from sales to our member distribution cooperatives for the past three years were as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Sales to member distribution cooperatives excluding renewable energy credit sales $ 731,557 $ 844,539 $ 966,752 Renewable energy credit sales to member distribution cooperatives 19 2,555 2,173 Total Sales to Member Distribution Cooperatives $ 731,576 $ 847,094 $ 968,925 |
Schedule of Revenues From Sales to Non-Members | Revenues from sales to non-members for the past three years were as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Sales to non-members excluding renewable energy credit sales $ 16,356 $ 21,645 $ 42,556 Renewable energy credit sales to non-members 5,175 9,132 8,547 Total Sales to Non-members $ 21,531 $ 30,777 $ 51,103 |
Schedule Of Rate Changes Implemented To Address Under- And Over-Collection Of Energy Costs | To address the under- and over-collection of energy costs, we implemented rate changes as follows: Effective Date of Rate Change % Change January 1, 2016 (5.4) April 1, 2016 (6.8) September 1, 2016 (6.5) January 1, 2017 (6.7) January 1, 2018 11.1 |
Electric Plant (Tables)
Electric Plant (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property Plant And Equipment [Abstract] | |
Schedule Of Net Electric Plant | Our net electric plant is composed of the following as of December 31, 2017: Clover North Anna Combustion Turbine Facilities Wildcat Point Other Total (in thousands) Property, plant, and equipment $ 698,497 $ 366,423 $ 590,137 $ — $ 99,179 $ 1,754,236 Accumulated depreciation (375,106 ) (216,486 ) (271,225 ) — (28,884 ) (891,701 ) Net Property, plant, and equipment 323,391 149,937 318,912 — 70,295 862,535 Nuclear fuel, at amortized cost — 18,089 — — — 18,089 Construction work in progress 6,189 24,982 72 789,661 1,763 822,667 Net Electric Plant $ 329,580 $ 193,008 $ 318,984 $ 789,661 $ 72,058 $ 1,703,291 Our net electric plant is composed of the following as of December 31, 2016: Clover North Anna Combustion Turbine Facilities Wildcat Point Other Total (in thousands) Property, plant, and equipment $ 695,843 $ 365,646 $ 589,049 $ — $ 96,314 $ 1,746,852 Accumulated depreciation (364,602 ) (206,868 ) (257,026 ) — (26,572 ) (855,068 ) Net Property, plant, and equipment 331,241 158,778 332,023 — 69,742 891,784 Nuclear fuel, at amortized cost — 22,138 — — — 22,138 Construction work in progress 3,927 15,181 62 715,855 1,971 736,996 Net Electric Plant $ 335,168 $ 196,097 $ 332,085 $ 715,855 $ 71,713 $ 1,650,918 |
Accounting For Asset Retireme25
Accounting For Asset Retirement And Environmental Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule Of Changes In Asset Retirement Obligations | The following represents changes in our asset retirement obligations for the years ended December 31, 2017 and 2016 (in thousands): Asset retirement obligations as of December 31, 2015 $ 118,200 Accretion expense 4,839 Decrease in asset retirement obligations (2,869 ) Payments (87 ) Asset retirement obligations as of December 31, 2016 $ 120,083 Accretion expense 5,044 Additional asset retirement obligations 2,210 Payments (867 ) Asset retirement obligations as of December 31, 2017 $ 126,470 |
Power Purchase Agreements (Tabl
Power Purchase Agreements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Schedule Of Energy And Capacity Purchase Obligations | As of December 31, 2017, our capacity and energy purchase obligations under the various agreements were as follows: Year Ending December 31, Capacity and Energy Obligations (in millions) 2018 $ 203.5 2019 186.8 2020 81.5 $ 471.8 |
Wholesale Power Contracts (Tabl
Wholesale Power Contracts (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Wholesale Power Contracts [Abstract] | |
Summary Of Removal Of Load Requirements Under Exception | The following table summarizes the cumulative removal of load requirements under this exception since January 1, 2016. Date MW January 1, 2016 9 May 1, 2016 60 June 1, 2017 65 May 1, 2018 109 |
Schedule of Revenues from Member Distribution Cooperatives | Revenues from our member distribution cooperatives for the past three years were as follows: Year Ended December 31, 2017 2016 2015 (in millions) Rappahannock Electric Cooperative $ 217.7 $ 271.2 $ 334.2 Shenandoah Valley Electric Cooperative 146.8 164.5 181.0 Delaware Electric Cooperative, Inc. 97.5 105.9 114.0 Choptank Electric Cooperative, Inc. 69.7 77.2 83.8 Southside Electric Cooperative 58.4 67.9 76.5 A&N Electric Cooperative 46.0 51.1 55.5 Mecklenburg Electric Cooperative 36.7 41.2 47.4 Prince George Electric Cooperative 20.6 22.5 25.4 Northern Neck Electric Cooperative 18.2 21.3 23.4 Community Electric Cooperative 11.4 14.4 16.6 BARC Electric Cooperative 8.6 9.9 11.1 Total $ 731.6 $ 847.1 $ 968.9 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis | The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2017 and 2016: Quoted Prices in Active Significant Markets for Other Significant Identical Observable Observable December 31, Assets Inputs Inputs 2017 (Level 1) (Level 2) (Level 3) (in thousands) Nuclear decommissioning trust (1) $ 59,723 $ 59,723 $ — $ — Nuclear decommissioning trust - net asset value (1)(2) 123,958 — — — Unrestricted investments and other (3) 308 — 308 — Total Financial Assets $ 183,989 $ 59,723 $ 308 $ — Derivatives - gas and power (4) $ 1,034 $ 975 $ 59 $ — Total Financial Liabilities $ 1,034 $ 975 $ 59 $ — Quoted Prices in Active Significant Markets for Other Significant Identical Observable Observable December Assets Inputs Inputs 2016 (Level 1) (Level 2) (Level 3) (in thousands) Nuclear decommissioning trust (1) $ 48,142 $ 48,142 $ — $ — Nuclear decommissioning trust - net asset value (1)(2) 111,013 — — — Unrestricted investments and other (3) 247 — 247 — Derivatives - gas and power (4) 6,968 4,874 2,094 — Total Financial Assets $ 166,370 $ 53,016 $ 2,341 $ — (1) For additional information about our nuclear decommissioning trust, see Note 9—Investments. (2) Nuclear decommissioning trust includes investments measured at net asset value per share (or its equivalent) as a practical expedient and these investments have not been categorized in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Consolidated Balance Sheet. (3) Unrestricted investments and other includes investments that are related to equity securities. (4) Derivatives – gas and power represent natural gas futures contracts. Level 1 are indexed against NYMEX. Level 2 are valued by ACES using observable market inputs for similar transactions. 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, 2017 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Schedule Of Outstanding Derivative Instruments | Excluding contracts accounted for as normal purchase/normal sale, we had the following outstanding derivative instruments: Quantity As of As of Commodity Unit of Measure December 31, 2017 December 31, 2016 Natural Gas MMBTU 23,700,000 14,250,000 |
Schedule Of Fair Value Of Derivative Instruments | The fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows: Fair Value As of December 31, As of December 31, Balance Sheet Location 2017 2016 (in thousands) Derivatives in an asset position: Natural gas futures contracts Deferred charges-other $ — $ 6,968 Total derivatives in an asset position $ — $ 6,968 Derivatives in a liability position: Natural gas futures contracts Deferred credits and other liabilities-other $ 1,034 $ — Total derivatives in a liability position $ 1,034 $ — |
Schedule Of Derivative Instruments On The Statement Of Revenues, Expenses, And Patronage Capital | The Effect of Derivative Instruments on the Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Years Ended December 31, 2017 and 2016 Amount of Gain Amount of Gain Location of (Loss) Reclassified (Loss) Recognized Gain (Loss) from Regulatory in Regulatory Reclassified Asset/Liability Asset/Liability for from Regulatory into Income for Derivatives Accounted for Derivatives as of Asset/Liability the Year Utilizing Regulatory Accounting December 31, into Income Ended December 31, 2017 2016 2017 2016 (in thousands) (in thousands) Natural gas futures contracts $ (2,008 ) $ 7,005 Fuel $ 1,342 $ (2,369 ) Total $ (2,008 ) $ 7,005 $ 1,342 $ (2,369 ) |
Investments (Tables)
Investments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Investments [Abstract] | |
Schedule Of Investments | Investments were as follows as of December 31, 2017 and 2016: Gross Gross Unrealized Unrealized Fair Carrying Description Designation Cost Gains Losses Value Value (in thousands) December 31, 2017 Nuclear decommissioning trust (1) Debt securities Available for sale $ 54,375 $ 5,029 $ — $ 59,404 $ 59,404 Equity securities Available for sale 77,838 46,474 (354 ) 123,958 123,958 Cash and other Available for sale 319 — — 319 319 Total Nuclear Decommissioning Trust $ 132,532 $ 51,503 $ (354 ) $ 183,681 $ 183,681 Lease Deposits (2) Government obligations Held to maturity $ 106,812 $ 776 $ — $ 107,588 $ 106,812 Total Lease Deposits $ 106,812 $ 776 $ — $ 107,588 $ 106,812 Unrestricted investments Government obligations Held to maturity $ 2,344 $ — $ (13 ) $ 2,331 $ 2,344 Debt securities Held to maturity 2,217 — (3 ) 2,214 2,217 Total Unrestricted Investments $ 4,561 $ — $ (16 ) $ 4,545 $ 4,561 Other Equity securities Trading $ 223 $ 85 $ — $ 308 $ 308 Non-marketable equity investments Equity 2,140 2,066 — 4,206 2,140 Total Other $ 2,363 $ 2,151 $ — $ 4,514 $ 2,448 $ 297,502 December 31, 2016 Nuclear decommissioning trust (1) Debt securities Available for sale $ 44,086 $ 3,537 $ — $ 47,623 $ 47,623 Equity securities Available for sale 75,332 35,958 (277 ) 111,013 111,013 Cash and other Available for sale 519 — — 519 519 Total Nuclear Decommissioning Trust $ 119,937 $ 39,495 $ (277 ) $ 159,155 $ 159,155 Lease Deposits (2) Government obligations Held to maturity $ 104,514 $ 2,948 $ — $ 107,462 $ 104,514 Total Lease Deposits $ 104,514 $ 2,948 $ — $ 107,462 $ 104,514 Unrestricted investments Government obligations Held to maturity $ 2,000 $ 1 $ - $ 2,001 $ 2,000 Debt securities Held to maturity 2,210 6 - 2,216 2,210 Total Unrestricted Investments $ 4,210 $ 7 $ - $ 4,217 $ 4,210 Other Equity securities Trading $ 198 $ 49 $ — $ 247 $ 247 Non-marketable equity investments Equity 2,142 2,012 — 4,154 2,142 Total Other $ 2,340 $ 2,061 $ — $ 4,401 $ 2,389 $ 270,268 (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 on investments held in the nuclear decommissioning trust are deferred as a regulatory liability or regulatory asset, 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 as of December 31, 2017 and 2016, were as follows: December 31, 2017 December 31, 2016 Carrying Carrying Description Cost Value Cost Value (in thousands) (in thousands) Available for sale $ 132,532 $ 183,681 $ 119,937 $ 159,155 Held to maturity 111,373 111,373 108,724 108,724 Equity 2,140 2,140 2,142 2,142 Trading 223 308 198 247 Total $ 246,268 $ 297,502 $ 231,001 $ 270,268 |
Schedule Of Contractual Maturities Of Debt Securities | Contractual maturities of debt securities as of December 31, 2017, 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) $ — $ — $ 59,404 $ — $ 59,404 Held to maturity 111,018 355 — — 111,373 Total $ 111,018 $ 355 $ 59,404 $ — $ 170,777 (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 Liabili31
Regulatory Assets And Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets And Liabilities Disclosure [Abstract] | |
Schedule Of Regulatory Assets And Liabilities | Our regulatory assets and liabilities as of December 31, 2017 and 2016, were as follows: December 31, 2017 2016 (in thousands) Regulatory Assets: Unamortized losses on reacquired debt $ 9,977 $ 11,841 Deferred asset retirement costs 296 313 NOVEC contract termination fee 26,915 29,362 Loan acquisition fee — 224 Interest rate hedge 2,220 2,381 Voluntary prepayment to NRECA Retirement Security Plan 3,868 4,641 Deferred net unrealized losses on derivative instruments 2,008 — Wildcat Point lease termination — 920 Total Regulatory Assets $ 45,284 $ 49,682 Regulatory Assets included in Current Assets: Deferred energy $ 3,669 $ — Regulatory Liabilities: North Anna asset retirement obligation deferral $ 49,739 $ 42,390 North Anna nuclear decommissioning trust unrealized gain 51,149 39,218 Unamortized gains on reacquired debt 349 407 Deferred net unrealized gains on derivative instruments — 7,005 Total Regulatory Liabilities $ 101,237 $ 89,020 Regulatory Liabilities included in Current Liabilities: Deferred energy $ — $ 40,029 Regulatory liability-revenue deferral $ 15,000 $ — |
Long-term Debt (Tables)
Long-term Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule Of Long-term Debt | Long-term debt consists of the following: December 31, 2017 2016 (in thousands) $250,000,000 principal amount of First Mortgage Bonds, 2017 Series A due 2037 at an interest rate of 3.33% $ 250,000 $ — $260,000,000 principal amount of First Mortgage Bonds, 2015 Series A due 2044 at an interest rate of 4.46% 260,000 260,000 $72,000,000 principal amount of First Mortgage Bonds, 2015 Series B due 2053 at an interest rate of 4.56% 72,000 72,000 $50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due 2043 at an interest rate of 4.21% 50,000 50,000 $50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due 2053 at an interest rate of 4.36% 50,000 50,000 $90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due 2040 at an interest rate of 4.83% 69,000 72,000 $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% 78,375 80,750 $250,000,000 principal amount of 2003 Series A Bonds due 2028 at an interest rate of 5.676% 114,579 124,996 $300,000,000 principal amount of 2002 Series B Bonds due 2028 at an interest rate of 6.21% 137,500 150,000 1,246,454 1,024,746 Debt issuance costs (7,266 ) (6,371 ) Current maturities (40,792 ) (28,292 ) $ 1,198,396 $ 990,083 |
Schedule Of Maturities Of Long-term Debt | Maturities of long-term debt for the next five years and thereafter are as follows: Year Ending December 31, (in thousands) 2018 $ 40,792 2019 40,792 2020 40,792 2021 49,041 2022 49,041 2023 and thereafter 1,025,996 $ 1,246,454 |
Selected Quarterly Financial 33
Selected Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule Of Quarterly Results Of Operations | A summary of the quarterly results of operations for the years 2017 and 2016 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 Quarter Second Quarter Third Quarter Fourth Quarter Total (in thousands) Statement of Operations Data 2017 Operating Revenues $ 189,779 $ 156,907 $ 193,425 $ 212,996 $ 753,107 Operating Margin 8,641 (836 ) 9,813 22,356 39,974 Net Margin attributable to ODEC (1) 2,968 3,047 3,258 17,354 26,627 2016 Operating Revenues $ 256,459 $ 199,149 $ 222,802 $ 199,461 $ 877,871 Operating Margin 12,224 9,884 9,022 14,062 45,192 Net Margin attributable to ODEC (2) 2,953 2,955 2,991 8,738 17,637 (1) (2) |
Summary Of Significant Accoun34
Summary Of Significant Accounting Policies - Additional Information (Details) | Nov. 07, 2017USD ($) | Dec. 13, 2016USD ($) | Dec. 31, 2017USD ($)member_classmemberrepresentative | Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($)member_classmemberrepresentativeproductsegment | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Significant Accounting Policies [Line Items] | |||||||
Consolidated assets | $ 5,700,000 | $ 5,700,000 | $ 5,700,000 | $ 5,700,000 | |||
Number of classes of members | member_class | 2 | 2 | |||||
Number of Class A members | member | 11 | 11 | |||||
Number of representatives from each Class A member on the board of directors | representative | 2 | 2 | |||||
Number of representatives from each Class B member on the board of directors | representative | 1 | 1 | |||||
Frequency of depreciation study | 5 years | ||||||
Reimbursement of nuclear fuel costs receivable | $ 2,900,000 | 3,300,000 | $ 2,900,000 | 3,300,000 | |||
Interest costs capitalized | 35,600,000 | 30,300,000 | $ 13,800,000 | ||||
Non-member energy sales | $ 21,531,000 | $ 30,777,000 | $ 51,103,000 | ||||
Number of power products for sale | product | 2 | ||||||
Percentage of actual total interest charges | 42.50% | 29.70% | 20.00% | ||||
Additional equity contribution | $ 14,100,000 | $ 5,800,000 | 14,100,000 | 5,800,000 | $ 14,100,000 | $ 5,800,000 | |
Adjustments under margin stabilization | 34,100,000 | 15,100,000 | $ 9,600,000 | ||||
Deferred energy, asset | 3,700,000 | 3,700,000 | |||||
Deferred energy, liability | 40,000,000 | 40,000,000 | |||||
Retirement of patronage capital | $ 14,100,000 | $ 5,800,000 | 14,100,000 | 5,756,000 | |||
Payment date of patronage capital | Apr. 2, 2018 | Apr. 3, 2017 | |||||
Reduction of patronage capital | $ 14,100,000 | $ 5,800,000 | |||||
Increase in accounts payable-members | $ 14,100,000 | $ 5,800,000 | |||||
Accounts receivable–members | 83,133,000 | 85,116,000 | $ 83,133,000 | 85,116,000 | |||
Number of operating segments | segment | 1 | ||||||
Number of reportable segments | segment | 1 | ||||||
Revenue recognition period for wholesale power contracts | 3 years | ||||||
Long-term Debt [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Capitalized costs associated with the issuance of debt | 7,300,000 | 6,400,000 | $ 7,300,000 | 6,400,000 | |||
Deferred Charges - Other [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Capitalized costs associated with the issuance of debt | $ 1,100,000 | $ 400,000 | $ 1,100,000 | 400,000 | |||
Maximum [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Ownership interest recorded using the equity method of accounting | 50.00% | 50.00% | |||||
Percentage of actual total interest charges | 20.00% | ||||||
Derivative term | 3 years | ||||||
Minimum [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Percentage of actual total interest charges | 10.00% | ||||||
Revenue percentage from wholesale power contracts | 95.00% | ||||||
TEC [Member] | |||||||
Significant Accounting Policies [Line Items] | |||||||
Percentage of interest owned in subsidiary by our Class A members | 100.00% | ||||||
Non-member energy sales | $ 0 | $ 0 | $ 0 |
Summary Of Significant Accoun35
Summary Of Significant Accounting Policies (Schedule Of Depreciation Rates) (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Clover [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation Rates | 1.90% | 1.80% | 1.80% |
North Anna [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation Rates | 3.30% | 3.00% | 3.00% |
Louisa [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation Rates | 3.10% | 3.50% | 3.50% |
Marsh Run [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation Rates | 3.00% | 3.20% | 3.20% |
Rock Springs [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation Rates | 3.10% | 3.30% | 3.30% |
Summary Of Significant Accoun36
Summary Of Significant Accounting Policies (Schedule Of Revenue From Sales To Member Distribution Cooperatives) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounting Policies [Abstract] | |||
Sales to member distribution cooperatives excluding renewable energy credit sales | $ 731,557 | $ 844,539 | $ 966,752 |
Renewable energy credit sales to member distribution cooperatives | 19 | 2,555 | 2,173 |
Total Sales to Member Distribution Cooperatives | $ 731,576 | $ 847,094 | $ 968,925 |
Summary Of Significant Accoun37
Summary Of Significant Accounting Policies (Schedule Of Revenues From Sales To Non-Members) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounting Policies [Abstract] | |||
Sales to non-members excluding renewable energy credit sales | $ 16,356 | $ 21,645 | $ 42,556 |
Renewable energy credit sales to non-members | 5,175 | 9,132 | 8,547 |
Total Sales to Non-members | $ 21,531 | $ 30,777 | $ 51,103 |
Summary Of Significant Accoun38
Summary Of Significant Accounting Policies (Schedule Of Rate Changes Implemented To Address Under- And Over-Collection Of Energy Costs) (Details) | Jan. 01, 2018 | Jan. 01, 2017 | Sep. 01, 2016 | Apr. 01, 2016 | Jan. 01, 2016 |
Significant Accounting Policies [Line Items] | |||||
Percentage of rate change | (6.70%) | (6.50%) | (6.80%) | (5.40%) | |
Subsequent Event [Member] | |||||
Significant Accounting Policies [Line Items] | |||||
Percentage of rate change | 11.10% |
Electric Plant (Schedule Of Net
Electric Plant (Schedule Of Net Electric Plan) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | $ 1,754,236 | $ 1,746,852 |
Accumulated depreciation | (891,701) | (855,068) |
Net Property, plant, and equipment | 862,535 | 891,784 |
Nuclear fuel, at amortized cost | 18,089 | 22,138 |
Construction work in progress | 822,667 | 736,996 |
Net Electric Plant | 1,703,291 | 1,650,918 |
Clover [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | 698,497 | 695,843 |
Accumulated depreciation | (375,106) | (364,602) |
Net Property, plant, and equipment | 323,391 | 331,241 |
Nuclear fuel, at amortized cost | 0 | 0 |
Construction work in progress | 6,189 | 3,927 |
Net Electric Plant | 329,580 | 335,168 |
North Anna [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | 366,423 | 365,646 |
Accumulated depreciation | (216,486) | (206,868) |
Net Property, plant, and equipment | 149,937 | 158,778 |
Nuclear fuel, at amortized cost | 18,089 | 22,138 |
Construction work in progress | 24,982 | 15,181 |
Net Electric Plant | 193,008 | 196,097 |
Combustion Turbine Facilities [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | 590,137 | 589,049 |
Accumulated depreciation | (271,225) | (257,026) |
Net Property, plant, and equipment | 318,912 | 332,023 |
Nuclear fuel, at amortized cost | 0 | 0 |
Construction work in progress | 72 | 62 |
Net Electric Plant | 318,984 | 332,085 |
Wildcat Point [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | 0 | 0 |
Accumulated depreciation | 0 | 0 |
Net Property, plant, and equipment | 0 | 0 |
Nuclear fuel, at amortized cost | 0 | 0 |
Construction work in progress | 789,661 | 715,855 |
Net Electric Plant | 789,661 | 715,855 |
Other [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | 99,179 | 96,314 |
Accumulated depreciation | (28,884) | (26,572) |
Net Property, plant, and equipment | 70,295 | 69,742 |
Nuclear fuel, at amortized cost | 0 | 0 |
Construction work in progress | 1,763 | 1,971 |
Net Electric Plant | $ 72,058 | $ 71,713 |
Electric Plant - Additional Inf
Electric Plant - Additional Information (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($)kVunitfacilitytransmission_lineturbinegeneratormiftMW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Property, Plant and Equipment [Line Items] | |||
Construction work in progress | $ 822,667 | $ 736,996 | |
Interest costs capitalized | 35,600 | 30,300 | $ 13,800 |
Total project cost, after consideration of liquidated damages | $ 834,300 | ||
Clover [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Undivided ownership interest | 50.00% | ||
Number of units | unit | 2 | ||
Power facility output | MW | 877 | ||
Outstanding accounts payable balance | $ 10,400 | 8,200 | |
Construction work in progress | $ 6,189 | 3,927 | |
North Anna [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Undivided ownership interest | 11.60% | ||
Number of units | unit | 2 | ||
Power facility output | MW | 1,892 | ||
Outstanding accounts payable balance | $ 8,800 | 3,800 | |
Percentage of costs responsible for | 11.60% | ||
Construction work in progress | $ 24,982 | 15,181 | |
Combustion Turbine Facilities [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Number of combustion facilities | facility | 3 | ||
Transmission lines | ft | 1,100 | ||
Number of Transmission Lines | transmission_line | 2 | ||
Transmission line capacity | kV | 500 | ||
Substation capacity | kV | 500 | ||
Construction work in progress | $ 72 | 62 | |
Distributed Generation Facilities [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Number of distributed facilities | facility | 6 | ||
Other [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Transmission lines | mi | 110 | ||
Construction work in progress | $ 1,763 | 1,971 | |
Wildcat Point [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Power facility output | MW | 1,000 | ||
Number of combustion turbines | turbine | 2 | ||
Number of heat recovery steam generators | generator | 2 | ||
Number of steam turbine generators | generator | 1 | ||
Construction work in progress | $ 789,661 | $ 715,855 | |
Interest costs capitalized | 77,800 | ||
Amount of liquidated damages | $ 53,200 |
Accounting For Asset Retireme41
Accounting For Asset Retirement And Environmental Obligations - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2014 | |
Asset Retirement And Environmental Obligations [Line Items] | |||
Increase (decrease) in asset retirement obligations | $ (2,869) | $ 18,000 | |
Increase to asset retirement cost | $ 2,210 | ||
North Anna [Member] | |||
Asset Retirement And Environmental Obligations [Line Items] | |||
North Anna's nuclear decommissioning asset retirement obligation | $ 105,800 | 101,600 | |
Decommission study period | 4 years | ||
Asset retirement obligations cash flow estimates useful life | 20 years | ||
Asset retirement obligations cash flow estimates intention to apply for additional operating license extension | 20 years | ||
Wildcat Point [Member] | |||
Asset Retirement And Environmental Obligations [Line Items] | |||
Increase to asset retirement cost | $ 2,100 | ||
Distributed Generation Facilities [Member] | |||
Asset Retirement And Environmental Obligations [Line Items] | |||
Increase to asset retirement cost | $ 100 | ||
Clover [Member] | |||
Asset Retirement And Environmental Obligations [Line Items] | |||
Increase (decrease) in asset retirement obligations | $ (2,900) |
Accounting For Asset Retireme42
Accounting For Asset Retirement And Environmental Obligations (Schedule Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning balance | $ 120,083 | $ 118,200 | ||
Accretion expense | 5,044 | 4,839 | $ 4,695 | |
Additional asset retirement obligations | 2,210 | |||
Decrease in asset retirement obligations | (2,869) | $ 18,000 | ||
Payments | (867) | (87) | ||
Ending balance | $ 126,470 | $ 120,083 | $ 118,200 |
Power Purchase Agreements - Add
Power Purchase Agreements - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Regulated Operations [Abstract] | |||
Energy requirements from owned generating facilities | 36.70% | 45.20% | 43.00% |
Letters of credit | $ 12,000 | $ 5,000 | |
Purchased power | $ 397,387 | $ 408,006 | $ 494,909 |
Power Purchase Agreements (Sche
Power Purchase Agreements (Schedule Of Energy And Capacity Purchase Obligations) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Regulated Operations [Abstract] | |
2,018 | $ 203.5 |
2,019 | 186.8 |
2,020 | 81.5 |
Energy and Capacity Obligations | $ 471.8 |
Wholesale Power Contracts - Add
Wholesale Power Contracts - Additional Information (Details) | May 01, 2018MW | Jun. 01, 2017MW | May 01, 2016MW | Jan. 01, 2016MW | Dec. 31, 2017memberMW |
Wholesale Power Contracts [Line Items] | |||||
Required period for termination of wholesale power contract | 3 years | ||||
Purchases under principal contract exceptions, percent of energy requirements | 2.00% | ||||
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 | 65 | 60 | 9 | 5 | |
Power received under limited exception to wholesale power contract, period of prior written notice of power received from owned generation or other suppliers | 180 days | ||||
Current maximum reduction in demand and associated energy | 175 | ||||
Mainland Virginia [Member] | |||||
Wholesale Power Contracts [Line Items] | |||||
Principal exceptions to the all-requirements obligations by members | member | 8 | ||||
Scenario, Forecast [Member] | |||||
Wholesale Power Contracts [Line Items] | |||||
Purchases under limited contract exceptions, amount of power received from owned generation or other suppliers | 109 | ||||
Remaining Demand and Associated Energy Available for Use | 66 |
Wholesale Power Contracts - (Su
Wholesale Power Contracts - (Summary of Removal of Load Requirements Under Exception) (Details) - MW | May 01, 2018 | Jun. 01, 2017 | May 01, 2016 | Jan. 01, 2016 | Dec. 31, 2017 |
Public Utilities General Disclosures [Line Items] | |||||
Removal of load requirements under exception | 65 | 60 | 9 | 5 | |
Scenario, Forecast [Member] | |||||
Public Utilities General Disclosures [Line Items] | |||||
Removal of load requirements under exception | 109 |
Wholesale Power Contracts (Sche
Wholesale Power Contracts (Schedule Of Revenues From Member Distribution Cooperatives) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | |||
Member distribution revenue | $ 731.6 | $ 847.1 | $ 968.9 |
Rappahannock Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 217.7 | 271.2 | 334.2 |
Shenandoah Valley Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 146.8 | 164.5 | 181 |
Delaware Electric Cooperative, Inc. [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 97.5 | 105.9 | 114 |
Choptank Electric Cooperative, Inc. [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 69.7 | 77.2 | 83.8 |
Southside Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 58.4 | 67.9 | 76.5 |
A&N Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 46 | 51.1 | 55.5 |
Mecklenburg Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 36.7 | 41.2 | 47.4 |
Prince George Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 20.6 | 22.5 | 25.4 |
Northern Neck Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 18.2 | 21.3 | 23.4 |
Community Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 11.4 | 14.4 | 16.6 |
BARC Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | $ 8.6 | $ 9.9 | $ 11.1 |
Fair Value Measurements (Financ
Fair Value Measurements (Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | $ 183,989 | $ 166,370 |
Total Financial Liabilities | 1,034 | |
Derivatives - Gas And Power [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 6,968 | |
Total Financial Liabilities | 1,034 | |
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 59,723 | 53,016 |
Total Financial Liabilities | 975 | |
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Derivatives - Gas And Power [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 4,874 | |
Total Financial Liabilities | 975 | |
Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 308 | 2,341 |
Total Financial Liabilities | 59 | |
Significant Other Observable Inputs (Level 2) [Member] | Derivatives - Gas And Power [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 2,094 | |
Total Financial Liabilities | 59 | |
Nuclear Decommissioning Trust [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 59,723 | 48,142 |
Nuclear Decommissioning Trust [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 59,723 | 48,142 |
Nuclear Decommissioning Trust [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 0 | 0 |
Nuclear Decommissioning Trust - Net Asset Value [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 123,958 | 111,013 |
Nuclear Decommissioning Trust - Net Asset Value [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 0 | 0 |
Nuclear Decommissioning Trust - Net Asset Value [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 0 | 0 |
Unrestricted Investment And Other [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 308 | 247 |
Unrestricted Investment And Other [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | 0 | 0 |
Unrestricted Investment And Other [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total Financial Assets | $ 308 | $ 247 |
Derivatives And Hedging (Schedu
Derivatives And Hedging (Schedule Of Outstanding Derivative Instruments) (Details) - MMBTU | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Natural Gas [Member] | ||
Derivative [Line Items] | ||
Quantity | 23,700,000 | 14,250,000 |
Derivatives And Hedging (Sche50
Derivatives And Hedging (Schedule Of Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Derivatives, Fair Value [Line Items] | ||
Total derivatives in an asset position | $ 6,968 | |
Total derivatives in a liability position | $ 1,034 | |
Natural Gas Future Contracts [Member] | Deferred Charges - Other [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total derivatives in an asset position | $ 6,968 | |
Natural Gas Future Contracts [Member] | Deferred Credits And Other Liabilities - Other [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total derivatives in a liability position | $ 1,034 |
Derivatives And Hedging (Sche51
Derivatives And Hedging (Schedule Of Derivative Instruments On The Statement Of Revenues, Expenses, And Patronage Capital) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of Gain (Loss) Recognized in Regulatory Asset/Liability for Derivatives | $ (2,008) | $ 7,005 |
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income | 1,342 | (2,369) |
Natural Gas Future Contracts [Member] | Fuel [Member] | Operating Expense Fuel [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of Gain (Loss) Recognized in Regulatory Asset/Liability for Derivatives | (2,008) | 7,005 |
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income | $ 1,342 | $ (2,369) |
Long-Term Lease Transaction - A
Long-Term Lease Transaction - Additional Information (Details) | Jan. 05, 2018USD ($)Installment | Mar. 01, 1996USD ($) | Dec. 31, 2017USD ($) |
Sale Leaseback Transaction [Line Items] | |||
Lease term | 48 years 9 months 18 days | ||
Lease value | $ 315,000,000 | ||
Leaseback term | 21 years 9 months 18 days | ||
Deferred gain | $ 23,700,000 | ||
Payment undertaking agreement | $ 304,700,000 | ||
Debt considered to be extinguished by in substance defeasance | $ 304,700,000 | ||
Subsequent Event [Member] | |||
Sale Leaseback Transaction [Line Items] | |||
Lease termination date | Jan. 5, 2018 | ||
Fixed purchase price | $ 430,500,000 | ||
Lease repayment under payment undertaking agreement | 289,700,000 | ||
Repayment of long-term lease transaction with owner trust | 32,200,000 | ||
United States Treasury Securities [Member] | Subsequent Event [Member] | |||
Sale Leaseback Transaction [Line Items] | |||
Lease repayment fund | $ 108,600,000 | ||
Number of installments | Installment | 4 |
Investments (Schedule Of Invest
Investments (Schedule Of Investments) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule of Invested Securities [Line Items] | ||
Available for sale investments, Debt securities | $ 59,404 | |
Held to maturity investments, Cost | 106,812 | $ 104,514 |
Trading, Cost | 223 | 198 |
Trading, Gross Unrealized Gains | 85 | 49 |
Total Investments | 308 | 247 |
Equity, Cost | 2,140 | 2,142 |
Equity Method Investment Gross Unrealized Gains | 2,066 | 2,012 |
Equity, Fair Value | 4,206 | 4,154 |
Other, Cost | 2,363 | 2,340 |
Other Gross Unrealized Gains | 2,151 | 2,061 |
Other, Fair Value | 4,514 | 4,401 |
Total Other | 2,448 | 2,389 |
Held to maturity Investments | 111,373 | 108,724 |
Total Investments | 297,502 | 270,268 |
Available for sale investments, Cost | 132,532 | 119,937 |
Total Nuclear Decommissioning Trust | 183,681 | 159,155 |
Government Obligations [Member] | ||
Schedule of Invested Securities [Line Items] | ||
Held to maturity investments, Gross Unrealized Gains | 1 | |
Held to maturity Investments | 2,344 | 2,000 |
Held to maturity investments, Gross Unrealized Losses | (13) | |
Held to maturity investments, Fair Value | 2,331 | 2,001 |
Debt Securities [Member] | ||
Schedule of Invested Securities [Line Items] | ||
Held to maturity investments, Gross Unrealized Gains | 6 | |
Held to maturity Investments | 2,217 | 2,210 |
Held to maturity investments, Gross Unrealized Losses | (3) | |
Held to maturity investments, Fair Value | 2,214 | 2,216 |
Unrestricted Investments [Member] | ||
Schedule of Invested Securities [Line Items] | ||
Held to maturity investments, Gross Unrealized Gains | 7 | |
Held to maturity Investments | 4,561 | 4,210 |
Held to maturity investments, Gross Unrealized Losses | (16) | |
Held to maturity investments, Fair Value | 4,545 | 4,217 |
Nuclear Decommissioning Trust [Member] | ||
Schedule of Invested Securities [Line Items] | ||
Available for sale investments, Debt securities, Cost | 54,375 | 44,086 |
Available for sale investments, Debt securities, Gross Unrealized Gains | 5,029 | 3,537 |
Available for sale investments, Debt securities | 59,404 | 47,623 |
Available for sale investments, Equity securities, Cost | 77,838 | 75,332 |
Available for sale investments, Equity securities, Gross Unrealized Gains | 46,474 | 35,958 |
Available for sale Securities, Equity securities, Gross Unrealized Losses | (354) | (277) |
Available for sale investments, Equity securities | 123,958 | 111,013 |
Available for sale investments, Cash and other | 319 | 519 |
Available for sale investments, Cost | 132,532 | 119,937 |
Available for sale investments, Gross Unrealized Gains | 51,503 | 39,495 |
Available-for-sale Securities, Gross Unrealized Loss | (354) | (277) |
Total Nuclear Decommissioning Trust | 183,681 | 159,155 |
Lease Deposits [Member] | ||
Schedule of Invested Securities [Line Items] | ||
Held to maturity investments, Cost | 106,812 | 104,514 |
Held to maturity investments, Gross Unrealized Gains | 776 | 2,948 |
Held to maturity investments, Fair Value | 107,588 | 107,462 |
Lease Deposits [Member] | Government Obligations [Member] | ||
Schedule of Invested Securities [Line Items] | ||
Held to maturity investments, Cost | 106,812 | 104,514 |
Held to maturity investments, Gross Unrealized Gains | 776 | 2,948 |
Held to maturity investments, Fair Value | $ 107,588 | $ 107,462 |
Investments (Schedule Of Inve54
Investments (Schedule Of Investments By Classification) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Investments [Abstract] | ||
Available for sale, Cost | $ 132,532 | $ 119,937 |
Held to maturity, Cost | 111,373 | 108,724 |
Equity, Cost | 2,140 | 2,142 |
Trading, Cost | 223 | 198 |
Investments, Cost | 246,268 | 231,001 |
Available for sale, Carrying Value | 183,681 | 159,155 |
Held to maturity, Carrying Value | 111,373 | 108,724 |
Equity, Carrying Value | 2,140 | 2,142 |
Trading, Carrying Value | 308 | 247 |
Total Investments | $ 297,502 | $ 270,268 |
Investments (Schedule Of Contra
Investments (Schedule Of Contractual Maturities Of Debt Securities) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Investments [Abstract] | ||
Available for sale securities, 5-10 years | $ 59,404 | |
Available for sale securities, Total | 59,404 | |
Held to maturity securities, Less than 1 year | 111,018 | |
Held to maturity securities, 1-5 years | 355 | |
Held to maturity securities, 5-10 years | 0 | |
Held to maturity, carrying value | 111,373 | $ 108,724 |
Contractual maturities of securities, Less than 1 year | 111,018 | |
Contractual maturities of securities, 1-5 years | 355 | |
Contractual maturities of securities, 5-10 years | 59,404 | |
Contractual maturities of securities, Total | $ 170,777 |
Regulatory Assets And Liabili56
Regulatory Assets And Liabilities (Schedule Of Regulatory Assets And Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 45,284 | $ 49,682 |
Regulatory liabilities | 101,237 | 89,020 |
Regulatory Liabilities included in Current Liabilities | 15,000 | |
Deferred Energy [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory Assets included in Current Assets | 3,669 | 0 |
Regulatory Liabilities included in Current Liabilities | 0 | 40,029 |
North Anna Asset Retirement Obligation Deferral [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 49,739 | 42,390 |
Deferred Net Unrealized Gains On Derivative Instruments [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 7,005 |
North Anna Nuclear Decommissioning Trust Unrealized Gain [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 51,149 | 39,218 |
Unamortized Gains On Reacquired Debt [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 349 | 407 |
Regulatory Liability-Revenue Deferral [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory Liabilities included in Current Liabilities | 15,000 | 0 |
Interest Rate Hedge [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 2,220 | 2,381 |
Deferred Net Unrealized Losses On Derivative Instruments [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 2,008 | 0 |
Unamortized Losses On Reacquired Debt [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 9,977 | 11,841 |
Deferred Asset Retirement Costs [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 296 | 313 |
NOVEC Contract Termination Fee [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 26,915 | 29,362 |
Loan Acquisition Fee [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 0 | 224 |
Voluntary Prepayment To NRECA Retirement Security Plan [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 3,868 | 4,641 |
Wildcat Point Lease Termination [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 0 | $ 920 |
Regulatory Assets And Liabili57
Regulatory Assets And Liabilities - Additional Information (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Apr. 30, 2013 | Dec. 31, 2015 | Dec. 31, 2013 | Dec. 31, 2017 | |
Property, Plant and Equipment [Line Items] | ||||
Loan acquisition fee | $ 33 | |||
Multiple employer pension prepayment | $ 7.7 | $ 7.7 | ||
Wildcat Point [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Payment to acquire land per agreement | $ 40 |
Long-term Debt (Schedule Of Lon
Long-term Debt (Schedule Of Long-term Debt) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Long-term debt | $ 1,246,454 | $ 1,024,746 |
Debt issuance costs | (7,266) | (6,371) |
Current maturities | (40,792) | (28,292) |
Long-term debt, excluding current maturities | 1,198,396 | 990,083 |
$250,000,000 principal amount of First Mortgage Bonds, 2017 Series A due 2037 at an interest rate of 3.33% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 250,000 | 0 |
$260,000,000 principal amount of First Mortgage Bonds, 2015 Series A due 2044 at an interest rate of 4.46% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 260,000 | 260,000 |
$72,000,000 principal amount of First Mortgage Bonds, 2015 Series B due 2053 at an interest rate of 4.56% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 72,000 | 72,000 |
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due 2043 at an interest rate of 4.21% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 50,000 | 50,000 |
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due 2053 at an interest rate of 4.36% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 50,000 | 50,000 |
$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due 2040 at an interest rate of 4.83% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 69,000 | 72,000 |
$165,000,000 principal amount of First Mortgage Bonds, 2011 Series B due 2040 at an interest rate of 5.54% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 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% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 78,375 | 80,750 |
$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an interest rate of 5.676% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 114,579 | 124,996 |
$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an interest rate of 6.21% | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 137,500 | $ 150,000 |
Long-term Debt (Schedule Of L59
Long-term Debt (Schedule Of Long-term Debt) (Parenthetical) (Details) - USD ($) | Dec. 31, 2017 | Jul. 06, 2017 | Dec. 31, 2016 |
$250,000,000 principal amount of First Mortgage Bonds, 2017 Series A due 2037 at an interest rate of 3.33% | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 250,000,000 | $ 250,000,000 | |
Debt instrument, interest rate | 3.33% | 3.33% | |
$260,000,000 principal amount of First Mortgage Bonds, 2015 Series A due 2044 at an interest rate of 4.46% | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 260,000,000 | $ 260,000,000 | |
Debt instrument, interest rate | 4.46% | 4.46% | |
$72,000,000 principal amount of First Mortgage Bonds, 2015 Series B due 2053 at an interest rate of 4.56% | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 72,000,000 | $ 72,000,000 | |
Debt instrument, interest rate | 4.56% | 4.56% | |
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due 2043 at an interest rate of 4.21% | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 50,000,000 | $ 50,000,000 | |
Debt instrument, interest rate | 4.21% | 4.21% | |
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due 2053 at an interest rate of 4.36% | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 50,000,000 | $ 50,000,000 | |
Debt instrument, interest rate | 4.36% | 4.36% | |
$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due 2040 at an interest rate of 4.83% | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 90,000,000 | $ 90,000,000 | |
Debt instrument, interest rate | 4.83% | 4.83% | |
$165,000,000 principal amount of First Mortgage Bonds, 2011 Series B due 2040 at an interest rate of 5.54% | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 165,000,000 | $ 165,000,000 | |
Debt instrument, interest rate | 5.54% | 5.54% | |
$95,000,000 principal amount of First Mortgage Bonds, 2011 Series C due 2050 at an interest rate of 5.54% | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 95,000,000 | $ 95,000,000 | |
Debt instrument, interest rate | 5.54% | 5.54% | |
$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an interest rate of 5.676% | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 250,000,000 | $ 250,000,000 | |
Debt instrument, interest rate | 5.676% | 5.676% | |
$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an interest rate of 6.21% | |||
Debt Instrument [Line Items] | |||
Debt instrument, face amount | $ 300,000,000 | $ 300,000,000 | |
Debt instrument, interest rate | 6.21% | 6.21% |
Long-term Debt - Additional Inf
Long-term Debt - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Jul. 06, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | |||
Net loss on reacquired debt | $ 9,600,000 | $ 11,400,000 | |
Fair value of long-term debt | $ 1,320,100,000 | $ 1,092,000,000 | |
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% | ||
2017 Series Bonds | |||
Debt Instrument [Line Items] | |||
Aggregate principle amount | $ 250,000,000 | ||
First Mortgage Bonds, 2017 Series A due 2037 at an interest rate of 3.33% | |||
Debt Instrument [Line Items] | |||
Aggregate principle amount | $ 250,000,000 | $ 250,000,000 | |
Debt instrument, interest rate | 3.33% | 3.33% |
Long-term Debt (Schedule Of Mat
Long-term Debt (Schedule Of Maturities Of Long-term Debt) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Disclosure [Abstract] | ||
2,018 | $ 40,792 | |
2,019 | 40,792 | |
2,020 | 40,792 | |
2,021 | 49,041 | |
2,022 | 49,041 | |
2023 and thereafter | 1,025,996 | |
Long-term debt | $ 1,246,454 | $ 1,024,746 |
Liquidity Resources - Additiona
Liquidity Resources - Additional Information (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Short Term Debt [Line Items] | ||
Member distribution cooperatives, amount prepaid | $ 10,800,000 | $ 45,500,000 |
Member distribution cooperatives, amount extended | $ 7,200,000 | $ 9,200,000 |
Revolving Credit Facility [Member] | ||
Short Term Debt [Line Items] | ||
Credit facility, interest rate | 2.60% | 1.60% |
Line of credit outstanding | $ 43,400,000 | $ 152,000,000 |
Revolving Credit Facility [Member] | Minimum [Member] | ||
Short Term Debt [Line Items] | ||
Margins-for-interest ratio | 110.00% | |
Revolving Credit Facility [Member] | Maximum [Member] | ||
Short Term Debt [Line Items] | ||
Debt to capitalization ratio | 85.00% | |
Revolving Credit Facility [Member] | LIBOR [Member] | Minimum [Member] | ||
Short Term Debt [Line Items] | ||
Spread on variable rate | 0.90% | |
Revolving Credit Facility [Member] | LIBOR [Member] | Maximum [Member] | ||
Short Term Debt [Line Items] | ||
Spread on variable rate | 1.50% | |
Revolving Credit Facility [Member] | Federal Funds Effective Rate [Member] | ||
Short Term Debt [Line Items] | ||
Spread on variable rate | 0.50% | |
Revolving Credit Facility [Member] | Daily LIBOR [Member] | ||
Short Term Debt [Line Items] | ||
Spread on variable rate | 1.00% | |
Revolving Credit Facility [Member] | Daily LIBOR [Member] | Minimum [Member] | ||
Short Term Debt [Line Items] | ||
Spread on variable rate margin | 0.00% | |
Revolving Credit Facility [Member] | Daily LIBOR [Member] | Maximum [Member] | ||
Short Term Debt [Line Items] | ||
Spread on variable rate margin | 0.50% | |
Revolving Credit Facility [Member] | Through March 3, 2022 | ||
Short Term Debt [Line Items] | ||
Credit facility, maximum borrowing capacity | $ 500,000,000 | |
Revolving Credit Facility [Member] | March 4, 2022 through March 3, 2023 | ||
Short Term Debt [Line Items] | ||
Credit facility, maximum borrowing capacity | 400,000,000 | |
Letter of Credit [Member] | ||
Short Term Debt [Line Items] | ||
Line of credit outstanding | $ 12,000,000 | $ 5,200,000 |
Employee Benefits - Additional
Employee Benefits - Additional Information (Details) - USD ($) | 1 Months Ended | 12 Months Ended | |||
Apr. 30, 2013 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2013 | |
Postemployment Benefits [Abstract] | |||||
Funded percentage (greater than) | 80.00% | 80.00% | |||
Contributions | $ 3,200,000 | $ 2,700,000 | $ 2,500,000 | ||
Companies contribution as percentage of total contributions made (less than) | 5.00% | 5.00% | 5.00% | ||
Multiple employer pension prepayment | $ 7,700,000 | $ 7,700,000 | |||
Pension expense, inclusive of administrative fees | $ 4,100,000 | $ 3,600,000 | $ 3,400,000 | ||
Amortization of voluntary prepayment | $ 800,000 | 800,000 | 800,000 | ||
Matching contributions percentage | 2.00% | ||||
Matching contributions | $ 289,000 | $ 240,000 | $ 231,000 |
Supplemental Cash Flows Infor64
Supplemental Cash Flows Information - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental Cash Flow Elements [Abstract] | |||
Cash paid for interest, net of amounts capitalized | $ 23.8 | $ 26.4 | $ 42 |
Capital expenditures incurred but not yet paid | $ 23.1 | $ 66.9 | $ 74.8 |
Commitments And Contingencies -
Commitments And Contingencies - Additional Information (Details) | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Commitments And Contingencies Disclosure [Abstract] | |
Liability protection for nuclear incidents | $ 13,400,000,000 |
Liability protection period for nuclear incidents subject to change for inflation | 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 | $ 33,400,000 |
Subsequent Event (Details)
Subsequent Event (Details) | Apr. 01, 2018 |
Scenario, Forecast [Member] | |
Subsequent Event [Line Items] | |
Increase in total energy rate percentage | 3.70% |
Selected Quarterly Financial 67
Selected Quarterly Financial Data (Unaudited) (Schedule Of Quarterly Results Of Operations) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||||
Operating Revenues | $ 212,996 | $ 193,425 | $ 156,907 | $ 189,779 | $ 199,461 | $ 222,802 | $ 199,149 | $ 256,459 | $ 753,107 | $ 877,871 | $ 1,020,028 | ||||||||||
Operating Margin | 22,356 | 9,813 | (836) | 8,641 | 14,062 | 9,022 | 9,884 | 12,224 | 39,974 | 45,192 | 48,953 | ||||||||||
Net Margin attributable to ODEC | $ 17,354 | [1] | $ 3,258 | [1] | $ 3,047 | [1] | $ 2,968 | [1] | $ 8,738 | [2] | $ 2,991 | [2] | $ 2,955 | [2] | $ 2,953 | [2] | $ 26,627 | [1] | $ 17,637 | [2] | $ 11,879 |
[1] | For the fourth quarter of 2017, includes an equity contribution of $14.1 million. | ||||||||||||||||||||
[2] | For the fourth quarter of 2016, includes an equity contribution of $5.8 million. |
Selected Quarterly Financial 68
Selected Quarterly Financial Data (Unaudited) (Schedule Of Quarterly Results Of Operations ) (Parenthetical) (Details) - USD ($) $ in Millions | Nov. 07, 2017 | Dec. 13, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 |
Quarterly Financial Information Disclosure [Abstract] | ||||||
Equity contribution | $ 14.1 | $ 5.8 | $ 14.1 | $ 5.8 | $ 14.1 | $ 5.8 |