| Ÿ | | Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and service activities reported as operatingcontracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue for Dominion are as follows:and associated derivative activity; Ÿ | | Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;
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Ÿ | | Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;
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Ÿ | | Regulated gas sales consist primarily of state-regulated retail natural gas sales and related distribution services;
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Ÿ | | Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity;
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Ÿ | | Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services and associated derivative activity.
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| Ÿ | | Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; and |
| Ÿ | | Other revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes miscellaneous service revenue from electric and gas distribution operations, and gas processing and handling revenue. |
The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows: | Ÿ | | Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and |
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The primary types of sales and service activities reported as operating revenue for Dominion Gas are as follows: | Ÿ | | Regulated gas sales consist primarily of state- and FERC-regulated natural gas sales and related distribution services; |
| Ÿ | | Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices and sales of gas purchased from third parties. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties; |
| Ÿ | | Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; |
| Ÿ | | NGL revenueconsists primarily of sales of NGL production and condensate, extracted products and associated derivative activity; and |
| Ÿ | | Other revenue consists primarily of miscellaneous service revenue, gas processing and handling revenue and gathering revenue. |
Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs Where permitted by regulatory authorities, the differences between Dominion’s and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion’s and Dominion Gas’ purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability. Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 84% is currently subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms. Virtually all of Dominion Gas’, Cove Point’s and Hope’s natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale. Income Taxes A consolidated federal income tax return is filed for Dominion and its subsidiaries, including Virginia Power and Dominion Gas’ subsidiaries. In addition, where applicable, combined income tax returns for Dominion and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed. Although Dominion Gas is disregarded for income tax purposes, a provision for income taxes is recognized to reflect the inclusion of its business activities in the tax returns of its parent, Dominion. Virginia Power and Dominion Gas participate in intercompany tax sharing agreements with Dominion and its subsidiaries, and current income taxes are based on taxable income or loss, determined on a separate company basis. Under the agreements, if a subsidiary incurs a net operating loss, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or to the extent the net operating loss is absorbed by the taxable income of other Dominion consolidated group members. Otherwise, the net operating loss is carried forward and is recognized as a deferred tax asset until realized. Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. The Companies establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities. The Companies recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited
Combined Notes to Consolidated Financial Statements, Continued Ÿ | | Other revenue consists primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.
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Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs
Where permitted by regulatory authorities, the differences between Virginia Power’s actual electric fuel and purchased energy expenses and Dominion’s purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.
Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 84% is currently subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.
Income Taxes
A consolidated federal income tax return is filed for Dominion and its subsidiaries, including Virginia Power. In addition, where applicable, combined income tax returns for Dominion and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed. Virginia Power participates in an intercompany tax sharing agreement with Dominion and its subsidiaries, and its current income taxes are based on its taxable income or loss, determined on a separate company basis.
Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.
Dominion and Virginia Power recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.
If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the consolidated balance sheets and current
payables are included in accrued interest, payroll and taxes on the consolidated balance sheets.
Dominion and Virginia Power recognize changes in estimated interest payable on net underpayments of income taxes in interest expense. Changes in interest receivable related to net overpayments of income taxes and estimated penalties that may result from the settlement of some uncertain tax positions are recognized in other income. In its Consolidated Statements of Income for 2013, Dominion recognized interest income of $3 million and interest expense of $10 million and no penalties. In 2012, Dominion recognized interest income of $8 million and interest expense of $3 million and a reduction in penalties of less than $1 million. In 2011, Dominion recognized interest income of $12 million and interest expense of $7 million and a reduction in penalties of less than $1 million. Dominion had accrued interest receivable of $5 million, interest payable of $15 million and penalties payable of less than $1 million at December 31, 2013 and interest receivable of $5 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2012.
Virginia Power’s interest and penalties were immaterial in 2013 and 2012. In 2011, Virginia Power recognized interest income of $12 million, and penalties were immaterial.
At December 31, 2013, Virginia Power’s Consolidated Balance Sheet included $3 million of state income taxes receivable, $22 million of federal and state income taxes payable, $12 million of noncurrent state income taxes receivable and $28 million of noncurrent federal and state income taxes payable.
At December 31, 2012, Virginia Power’s Consolidated Balance Sheet included $10 million of federal income taxes payable and $36
to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the consolidated balance sheets and current payables are included in accrued interest, payroll and taxes on the consolidated balance sheets. The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income, respectively. Penalties are also recognized in other income. Dominion’s, Virginia Power’s and Dominion Gas’ interest and penalties were immaterial in 2014, 2013 and 2012. At December 31, 2014, Virginia Power’s Consolidated Balance Sheet included $225 million of federal and state income taxes receivable, $13 million of noncurrent state income taxes receivable and $38 million of noncurrent federal and state income taxes payable. At December 31, 2013, Virginia Power’s Consolidated Balance Sheet included $3 million of state income taxes receivable, $22 million of federal and state income taxes payable, $12 million of noncurrent state income taxes receivable and $28 million of noncurrent federal and state income taxes payable. At December 31, 2014, Dominion Gas’ Consolidated Balance Sheet included $96 million of federal and state income taxes receivable, $14 million of state income taxes payable, $7 million of noncurrent state income taxes payable and $20 million noncurrent state income taxes receivable. At December 31, 2013, Dominion Gas’ Consolidated Balance Sheet included $17 million of federal income taxes payable, $23 million of state income taxes payable, $1 million of state income taxes receivable, $7 million of noncurrent state income taxes payable and $20 million noncurrent state income taxes receivable. Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold. Cash and Cash Equivalents Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 2013 and 2012, Dominion’s accounts payable included $38 million and $53 million, respectively, ofThe following table illustrates the checks outstanding but not yet presented for payment. At December 31, 2013payment and 2012, Virginia Power’srecorded in accounts payable included $21 million and $30 million, respectively, of checks outstanding but not yet presented for payment. the Companies: | | | | | | | | | | Year Ended December 31, | | 2014 | | | 2013 | | | (millions) | | | | | | | Dominion | | $ | 42 | | | $ | 38 | | Virginia Power | | | 20 | | | | 21 | | Dominion Gas | | | 9 | | | | 7 | | | | | | | | | | | |
For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less. Derivative Instruments Dominion and Virginia Power use derivative instruments such as futures, swaps, forwards, options and FTRs to manage the commodity, currency exchange and financial market risks of their business operations.
Combined Notes Dominion Gas uses derivative instruments such as physical and financial forwards, futures and swaps to Consolidated Financial Statements, Continuedmanage commodity price and interest rate risks.
All derivatives, other thanexcept those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. Dominion and Virginia PowerThe Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion had margin assets of $620$287 million and $212$620 million associated with cash collateral at December 31, 20132014 and 2012,2013, respectively. Dominion had margin liabilities of $2$34 million and $4$2 million associated with cash collateral at December 31, 20132014 and 2012,2013, respectively. Virginia Power had margin assets of $11$6 million and $18$11 million associated with cash collateral at December 31, 20132014 and 2012,2013, respectively. Virginia Power’sPower did not have any margin liabilities associated with cash collateral were not material at December 31, 2013 and 2012.2014 or 2013. Dominion Gas did not have any margin assets or liabilities related to cash collateral at December 31, 2014 or 2013. See Note 7 for further information about offsetting derivatives.
To manage price risk, Dominion and Virginia Power hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent the CompaniesDominion and Virginia Power do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. As part of Dominion’s strategy to market energy and manage related risks, it also managesformerly managed a portfolio of commodity-based financial derivative instruments held for trading purposes. Dominion usesused established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and usesused various derivative instruments to reduce risk by creating offsetting market positions. In the second quarter of 2013, Dominion commenced a repositioning of its producer services business. The repositioning was completed in the first quarter of 2014 and resulted in the termination of natural gas trading and certain energy marketing activities. Statement of Income Presentation: | Ÿ | | Derivatives Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis. |
| Ÿ | | Derivatives Not Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses or interest and related charges based on the nature of the underlying risk. |
In Virginia Power’s generation operations, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings. DERIVATIVE INSTRUMENTS DESIGNATEDAS HEDGING INSTRUMENTS Dominion and Virginia PowerThe Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, Dominion and Virginia Powerthe Companies formally document the relationship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using the hedging instrument. The Companies assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.
Cash Flow Hedges—A majority of Dominion’s and Virginia Power’sthe Companies’ hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas, NGLs and other energy-related products. The Companies also use foreign currency contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which Dominion and Virginia Powerthe Companies are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable. Dominion entered into interest rate derivative instruments to hedge its forecasted interest payments related to planned debt issuances in 2013 and 2014. These interest rate derivatives were designated by Dominion as cash flow hedges in 2012 and 2013, prior to the formation of Dominion Gas. For the purposes of the Dominion Gas financial statements, the derivative balances, AOCI balance, and any income statement impact related to these interest rate derivative instruments entered into by Dominion have been, and will continue to be, included in the Dominion Gas’ Consolidated Financial Statements as the forecasted interest payments related to the debt issuances will now occur at Dominion Gas. Fair Value Hedges—Dominion also uses fair value hedges to mitigate the fixed price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, Dominion and Virginia Power have designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Derivative gains and losses from the hedged item are reclassified to earnings when the hedged item is included in earnings, or earlier, if the hedged item no longer qualifies for hedgeforhedge accounting. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.
Property, Plant and Equipment Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred. In 2014, 2013 2012 and 2011,2012, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $80 million, $66 million $91 million and $85$91 million, respectively. In 2014, 2013 2012 and 2011,2012, Virginia Power capitalized AFUDC to property, plant and equipment of $33$39 million, $31$33 million and $31 million, respectively. In 2014, 2013 and 2012, Dominion Gas capitalized AFUDC to property, plant and equipment of $1 million, $5 million and $23 million, respectively. Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2014, 2013 2012 and 2011,2012, Virginia Power recorded $8 million, $32 million $37 million and $20$37 million of AFUDC related to these projects, respectively. For property subject to cost-of-service rate regulation, including Virginia Power electric distribution, electric transmission, and generation property, Dominion Gas natural gas distribution and transmission property, and for certain Dominion natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be retired or abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be retired or abandoned. For Dominion and Virginia Power property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associatedasso-
Combined Notes to Consolidated Financial Statements, Continued ciated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date. Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. Dominion’s and Virginia Power’sThe Companies’ average composite depreciation rates on utility property, plant and equipment are as follows: | | | | | | | | | | | | | | Year Ended December 31, | | 2013 | | | 2012 | | | 2011 | | | (percent) | | | | | | | | | | Dominion | | | | | | | | | | | | | Generation | | | 2.71 | | | | 2.62 | | | | 2.68 | | Transmission | | | 2.36 | | | | 2.17 | | | | 2.26 | | Distribution | | | 3.13 | | | | 3.17 | | | | 3.19 | | Storage | | | 2.43 | | | | 2.59 | | | | 2.64 | | Gas gathering and processing | | | 2.39 | | | | 2.49 | | | | 2.52 | | General and other | | | 3.82 | | | | 4.55 | | | | 4.66 | | | | | | Virginia Power | | | | | | | | | | | | | Generation | | | 2.71 | | | | 2.62 | | | | 2.68 | | Transmission | | | 2.28 | | | | 1.98 | | | | 2.03 | | Distribution | | | 3.33 | | | | 3.32 | | | | 3.33 | | General and other | | | 3.51 | | | | 4.32 | | | | 4.38 | |
| | | | | | | | | | | | | | Year Ended December 31, | | 2014 | | | 2013 | | | 2012 | | | (percent) | | | | | | | | | | Dominion | | | | | | | | | | | | | Generation | | | 2.66 | | | | 2.71 | | | | 2.62 | | Transmission | | | 2.38 | | | | 2.36 | | | | 2.17 | | Distribution | | | 3.12 | | | | 3.13 | | | | 3.17 | | Storage | | | 2.39 | | | | 2.43 | | | | 2.59 | | Gas gathering and processing | | | 2.81 | | | | 2.39 | | | | 2.49 | | General and other | | | 3.62 | | | | 3.82 | | | | 4.55 | | | | | | Virginia Power | | | | | | | | | | | | | Generation | | | 2.66 | | | | 2.71 | | | | 2.62 | | Transmission | | | 2.34 | | | | 2.28 | | | | 1.98 | | Distribution | | | 3.34 | | | | 3.33 | | | | 3.32 | | General and other | | | 3.29 | | | | 3.51 | | | | 4.32 | | | | | | Dominion Gas | | | | | | | | | | | | | Transmission | | | 2.40 | | | | 2.43 | | | | 2.35 | | Distribution | | | 2.47 | | | | 2.50 | | | | 2.66 | | Storage | | | 2.40 | | | | 2.43 | | | | 2.58 | | Gas gathering and processing | | | 2.82 | | | | 2.39 | | | | 2.50 | | General and other | | | 5.77 | | | | 5.93 | | | | 6.09 | |
In 2013, Virginia Power revised its depreciation rates to reflect the results of a new depreciation study. This change resulted in an increase of $19 million ($12 million after-tax) in depreciation and amortization expense in Virginia Power’s Consolidated Statements of Income. In 2014, Virginia Power also made a one-time adjustment to depreciation expense as ordered by the Virginia Commission. This adjustment resulted in an increase of $38 million ($23 million after-tax) in depreciation and amortization expense in Virginia Power’s Consolidated Statements of Income. In 2013, Dominion Gas revised the depreciation rates for East Ohio to reflect the results of a new depreciation study. This change resulted in a decrease of $8 million ($5 million after-tax) in depreciation and amortization expense in Dominion Gas’ Consolidated Statements of Income. Dominion’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives: | | | | | | Asset | | Estimated Useful Lives | | Merchant generation-nuclear | | | 44 years | | Merchant generation-other | | | 15 –- 36 years | | General and other | | | 5 –- 59 years | |
Depreciation and amortization related to Virginia Power’s and Dominion Gas’ nonutility property, plant and equipment and E&P properties was immaterial for the years ended December 31, 2014, 2013 and 2012. Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows. Long-Lived and Intangible Assets Dominion and Virginia PowerThe Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for a discussion of impairments related to certain long-lived assets and intangible assets with finite lives.
Regulatory Assets and Liabilities The accounting for Dominion’s and Dominion Gas’ regulated gas and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator. The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions, legislation or historical experience, as well as discussions with applicable regulatory authorities.authorities and legal counsel. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. Asset Retirement Obligations Dominion and Virginia PowerThe Companies recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since
Combined Notes to Consolidated Financial Statements, Continued
relevant market information is not available, fair value is estimated using discounted cash flow analyses. At least annually, the Companies evaluate the key assumptions underlying their AROs including estimates of the amounts and timing of future cash flows associated with retirement activities. AROs are adjusted when significant changes in these assumptions are identified. Dominion reportsand Dominion Gas report accretion of AROs and depreciation on asset retirement costs associated with itstheir natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Virginia Power reports accretion of AROs and depreciation on asset retirement costs associated with decommissioning its nuclear
power stations as an adjustment to the regulatory liability for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs is reported in other operations and maintenance expense and depreciation expense in the Consolidated Statements of Income. Amortization of Debt Issuance Costs
Dominion and Virginia PowerThe Companies defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as an asset and classified in other current assets and other deferred charges and other assets in the Consolidated Balance Sheets. Unamortized costs associated with redemptions of debt securities prior to stated maturity dates are generally recognized and recorded in interest expense immediately. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized over the lives of the new issuances.
Investments MARKETABLE EQUITYAND DEBT SECURITIES Dominion accounts for and classifies investments in marketable equity and debt securities as trading or available-for-sale securities. Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities. | Ÿ | | Trading securitiesinclude marketable equity and debt securities held by Dominion in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income. |
| Ÿ | | Available-for-sale securitiesinclude all other marketable equity and debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other available-for-sale securities, including those held in Dominion’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax. |
In determining realized gains and losses for marketable equity and debt securities, the cost basis of the security is based on the specific identification method. NON--MMARKETABLEARKETABLE INVESTMENTS Dominion and Virginia PowerThe Companies account for illiquid and privately held securities for which market prices or quotations are not readily available under either the equity or cost method. Non-marketable investments include:
| Ÿ | | Equity method investmentswhen Dominion and Virginia Powerthe Companies have the ability to exercise significant influence, but not control, over the investee. Dominion’s investments are included in investments in equity method affiliates and Virginia Power’s investments are included in other investments in their Consolidated Balance Sheets. Dominion and Virginia PowerThe Companies record equity method adjustments in other income in the Consolidated Statements of Income including: their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method. |
| Ÿ | | Cost method investments when Dominion and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion’s and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds. |
OTHER-THAN-TEMPORARY IMPAIRMENT Dominion and Virginia Power periodically review their investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period. Decommissioning Trust Investments—Special Considerations | Ÿ | | The recognition provisions of the FASB’s other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities. |
| Ÿ | | Debt Securities—Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, the CompaniesDominion and Virginia Power record the credit loss in earnings and any remaining portion of the unrealized loss in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors. |
| Ÿ | | Equity securities and other investments—Dominion’s and Virginia Power’s method of assessing other-than-temporary declines requires demonstrating the ability to hold individual |
Combined Notes to Consolidated Financial Statements, Continued | | securities for a period of time sufficient to allow for the anticipated recovery in their market value prior to the consideration of the other criteria mentioned above. Since the CompaniesDominion and Virginia Power have limited ability to oversee the day-to-day |
| | management of nuclear decommissioning trust fund investments, they do not have the ability to ensure investments are held through an anticipated recovery period. Accordingly, they consider all equity and other securities as well as non-marketable investments held in nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired. |
Inventories Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory for Dominion Gas used in East Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at $7$12 million and $24$7 million at December 31, 20132014 and December 31, 2012,2013, respectively. Based on the average price of gas purchased during 20132014 and 2012,2013, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $77$98 million and $69$77 million, respectively. Stored gas inventory for Dominion held by Hope and certain nonregulated gas operations is valued using the weighted-average cost method. Gas Imbalances Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion valuesand Dominion Gas value these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion and Dominion Gas from other parties are reported in other current assets and imbalances that Dominion owesand Dominion Gas owe to other parties are reported in other current liabilities in the Consolidated Balance Sheets. Goodwill Dominion evaluatesand Dominion Gas evaluate goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. NOTE 3. ACQUISITIONSANDDISPOSITIONS SaleDOMINION
ACQUISITIONOF SOLAR DEVELOPMENT PROJECTS In March 2014, Dominion acquired 100% of Illinois Gas Contractsthe equity interests of six solar development projects in California from Recurrent Energy Development Holdings, LLC for approximately $50 million in cash. The projects cost approximately $446 million to construct, including the initial acquisition cost. The facilities, which began commercial operations in the fourth quarter of 2014, generate approximately 139 MW. In November 2014, Dominion acquired 100% of the equity interests of a solar project in California from CSI Project Holdco, LLC for approximately $79 million in cash. The project costs approximately $80 million to construct, including the initial acquisition cost. The facility, which began commercial operations in the fourth quarter of 2014, generates approximately 20 MW. In December 2014, Dominion acquired 100% of the equity interests of a solar project in California from EDF Renewable Development, Inc. for approximately $71 million in cash. The project is expected to cost approximately $73 million to construct, including the initial acquisition cost. The facility, which began commercial operations in January 2015, generates approximately 20 MW. The purchase price for each of these acquisitions was allocated to Property, Plant and Equipment. In September 2014, Dominion entered into agreements to acquire 100% of the equity interests in two additional solar projects in California from EDF Renewable Development, Inc. for approximately $175 million in cash. The acquisitions are expected to close in the first half of 2015 prior to the projects commencing operations. The projects are expected to cost approximately $185 million once constructed, including the initial acquisition cost. Upon completion, the facilities are expected to generate approximately 42 MW. These acquisitions provide Dominion with a large utility-scale solar presence and significantly increase its solar generation portfolio. Long-term power purchase, interconnection and operation and maintenance agreements have been executed for the projects. Dominion has claimed or expects to claim federal investment tax credits on the projects. ACQUISITIONOF CGT In January 2015, Dominion completed the acquisition of 100% of the equity interests of CGT from SCANA Corporation for approximately $495 million in cash, subject to final acquired working capital adjustments. CGT owns and operates nearly 1,500 miles of FERC-regulated interstate natural gas pipeline in South Carolina and southeastern Georgia. This acquisition supports Dominion’s natural gas expansion into the Southeast. The acquired assets of CGT will be included in the Dominion Energy operating segment. Subject to board approvals by Dominion and Dominion Midstream, Dominion expects to contribute CGT into Dominion Midstream for a combination of debt and Dominion Midstream common units during the first half of 2015. The allocation of the purchase price to individual assets is under evaluation by management and has not been finalized. SALEOF ELECTRIC RETAIL ENERGY MARKETING BUSINESS In March 2014, Dominion completed the sale of its electric retail energy marketing business. The proceeds were approximately $187 million, net of transaction costs. The sale resulted in a gain, subject to post-closing adjustments, of approximately $100 million ($57 million after-tax) net of a $31 million write-off of goodwill, and is included in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. The sale of the electric retail energy marketing business did not qualify for discontinued operations classification. SALEOF ILLINOIS GAS CONTRACTS In June 2013, Dominion completed the sale of Illinois Gas Contracts. The sales price was approximately $32 million, subject to post-closing adjustments. The sale resulted in a gain of approximatelyapprox-
imately $29 million ($18 million after-tax) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in Dominion’s Consolidated Statement of Income. The sale of Illinois Gas Contracts did not qualify for discontinued operations classification as it is not considered a component under applicable accounting guidance. Sale of Brayton Point, Kincaid and Equity Method Investment in ElwoodSALEOF BRAYTON POINT, KINCAIDAND EQUITY METHOD INVESTMENTIN ELWOOD
In March 2013, Dominion entered into an agreement with Energy Capital Partners to sell Brayton Point, Kincaid, and its equity method investment in Elwood. In the first and second quarters of 2013, Brayton Point’s and Kincaid’s assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell, resulting in impairment charges totaling $48 million ($28 million after-tax), which are included in discontinued operations in Dominion’s Consolidated Statements of Income. In both periods, Dominion used the market approach to estimate the fair value of Brayton Point’s and Kincaid’s long-lived assets. These were considered Level 2 fair value measurements given that they were based on the agreed-upon sales price. Dominion’s 50% interest in Elwood was an equity method investment and therefore, in accordance with applicable accounting guidance, the carrying amount of this investment was not classified as held for sale nor were the equity earnings from this investment reported as discontinued operations. In August 2013, Dominion completed the sale and received proceeds of approximately $465 million, net of transaction costs. The sale resulted in a $35 million ($25 million after-tax) gain attributable to its equity method investment in Elwood, which is included in other income in Dominion’s Consolidated Statement of Income, which was partially offset by a $17 million ($18 million after-tax) loss attributable to Brayton Point and Kincaid, which includes a $16 million write-off of goodwill and is reflected in loss from discontinued operations in Dominion’s Consolidated Statement of Income. See Note 6 for other impairments related to these power stations. The following table presents selected information regarding the results of operations of Brayton Point and Kincaid, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income: | | Year Ended December 31, | | 2013 | | 2012 | | 2011 | | | 2013 | | 2012 | | | (millions) | | | | | | | | | | | | | Operating revenue | | $ | 304 | | | $ | 258 | | | $ | 380 | | | $ | 304 | | | $ | 258 | | Loss before income taxes | | | (135 | )(1) | | | (1,768 | )(2) | | | (57 | ) | | | (135 | )(1) | | | (1,768 | )(2) |
| (1) | Includes $64 million of charges related to the defeasance of Brayton Point debt and the early redemption of Kincaid debt in 2013. See Note 17 for more information. |
| (2) | Includes a long-lived asset impairment charge of $1.6 billion. |
Sale of Salem Harbor and State LineSALEOF SALEM HARBORAND STATE LINE
In August 2012, Dominion completed the sale of Salem Harbor. In the second quarter of 2012, the assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell. Also during the second quarter of 2012, Dominion completed the sale of State Line, which ceased operations in March 2012. See Note 6 for impairments related to these power stations. The following table presents selected information regarding the results of operations of Salem Harbor and State Line, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income: | | Year Ended December 31, | | 2012 | | 2011 | | | 2012 | | | (millions) | | | | | | | | | Operating revenue | | $ | 57 | | | $ | 233 | | | $ | 57 | | Loss before income taxes(1) | | | (49 | ) | | | (34 | ) | | | (49 | ) |
Dominion and Dominion Gas BLUE RACER See Note 9 for a discussion of transactions related to Blue Racer. MARCELLUS ACREAGE See Note 10 for a discussion of assignments of Marcellus acreage. (1) | Includes long-lived asset impairment charges of $55 million in 2011. |
NOTE 4. OPERATING REVENUE The Companies’ operating revenue consists of the following: | | | | | | | | | | | | | | Year Ended December 31, | | 2014 | | | 2013 | | | 2012 | | | (millions) | | | | | | | | | | Dominion | | | | | | | | | | | | | Electric sales: | | | | | | | | | | | | | Regulated | | $ | 7,460 | | | $ | 7,193 | | | $ | 7,102 | | Nonregulated | | | 1,839 | | | | 2,511 | | | | 2,483 | | Gas sales: | | | | | | | | | | | | | Regulated | | | 334 | | | | 323 | | | | 250 | | Nonregulated | | | 751 | | | | 930 | | | | 1,071 | | Gas transportation and storage | | | 1,543 | | | | 1,535 | | | | 1,401 | | Other | | | 509 | | | | 628 | | | | 528 | | Total operating revenue | | $ | 12,436 | | | $ | 13,120 | | | $ | 12,835 | | Virginia Power | | | | | | | | | | | | | Regulated electric sales | | $ | 7,460 | | | $ | 7,193 | | | $ | 7,102 | | Other | | | 119 | | | | 102 | | | | 124 | | Total operating revenue | | $ | 7,579 | | | $ | 7,295 | | | $ | 7,226 | | Dominion Gas | | | | | | | | | | | | | Gas sales: | | | | | | | | | | | | | Regulated | | $ | 209 | | | $ | 202 | | | $ | 138 | | Nonregulated | | | 26 | | | | 32 | | | | 28 | | Gas transportation and storage | | | 1,353 | | | | 1,338 | | | | 1,188 | | NGL revenue | | | 212 | | | | 292 | | | | 275 | | Other | | | 98 | | | | 73 | | | | 48 | | Total operating revenue | | $ | 1,898 | | | $ | 1,937 | | | $ | 1,677 | |
Combined Notes to Consolidated Financial Statements, Continued NOTE 4. OPERATING REVENUE
Dominion’s and Virginia Power’s operating revenue consists of the following:
| | | | | | | | | | | | | | Year Ended December 31, | | 2013 | | | 2012 | | | 2011 | | | (millions) | | | | | | | | | | Dominion | | | | | | | | | | | | | Electric sales: | | | | | | | | | | | | | Regulated | | $ | 7,193 | | | $ | 7,102 | | | $ | 7,114 | | Nonregulated | | | 2,511 | | | | 2,483 | | | | 2,721 | | Gas sales: | | | | | | | | | | | | | Regulated | | | 323 | | | | 250 | | | | 287 | | Nonregulated | | | 930 | | | | 1,071 | | | | 1,634 | | Gas transportation and storage | | | 1,535 | | | | 1,401 | | | | 1,506 | | Other | | | 628 | | | | 528 | | | | 503 | | Total operating revenue | | $ | 13,120 | | | $ | 12,835 | | | $ | 13,765 | | Virginia Power | | | | | | | | | | | | | Regulated electric sales | | $ | 7,193 | | | $ | 7,102 | | | $ | 7,114 | | Other | | | 102 | | | | 124 | | | | 132 | | Total operating revenue | | $ | 7,295 | | | $ | 7,226 | | | $ | 7,246 | |
NOTE 5. INCOME TAXES Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. Dominion and Virginia PowerThe Companies are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material. On January 2, 2013,In December 2014, U.S. federal legislation was enacted that provides an extension of the 50% bonus depreciation allowance for qualifying capital expenditures incurred through 2013.
In September 2013, the IRS issued final regulations that provide guidance to taxpayers on the treatment of amounts paid to acquire, produce or improve tangible property, including whether expenditures should be deducted as repairs or capitalized and depreciated on tax returns. The final regulations include a number of safe harbor tax accounting methods which a taxpayer may choose to elect and, if adopted, will not be challenged by the IRS. In addition, the IRS reissued certain temporary regulations that were also issued concurrently as proposed regulations regarding property dispositions. The final regulations are effective for tax years beginning on or after January 1, 2014. Although changes in tax accounting methods would be effective prospectively, implementation of certain changes will require a calculation of the cumulative effect of the change on prior years. Under IRS procedural guidance issued in January 2014, if such cumulative effect increases taxable income, it is includible in taxable income over a four-year period, beginning with the year of the change. However, if such cumulative effect decreases taxable income, the entire amount is includible in taxable income in the year of the change.
Dominion and Virginia Power have evaluated tax accounting method changes that may be elected or required by the final regulations. At December 31, 2013, $17 million of deferred tax liabilities have been classified as current in the Companies’ Consolidated Balance Sheets, representing cumulative adjustment
amounts expected to be reflected in income for tax purposes during the twelve months ending December 31, 2014. Tax accounting method changes in 2014 are not expected to materially affect the Companies’ cash flows, results of operations or financial condition.
Continuing Operations Details of income tax expense for continuing operations including noncontrolling interests were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion(1) | | | Virginia Power(2) | | | Year Ended December 31, | | 2013 | | | 2012 | | | 2011 | | | 2013 | | | 2012 | | | 2011 | | | (millions) | | | | | | | | | | | | | | | | | | | Current: | | | | | | | | | | | | | | | | | | | | | | | | | Federal | | $ | 317 | | | $ | 43 | | | $ | 31 | | | $ | 357 | | | $ | 70 | | | $ | (35 | ) | State | | | 110 | | | | 84 | | | | 16 | | | | 62 | | | | 81 | | | | 79 | | Total current expense | | | 427 | | | | 127 | | | | 47 | | | | 419 | | | | 151 | | | | 44 | | Deferred: | | | | | | | | | | | | | | | | | | | | | | | | | Federal | | | 497 | | | | 645 | | | | 685 | | | | 224 | | | | 482 | | | | 484 | | State | | | (31 | ) | | | 40 | | | | 48 | | | | 17 | | | | 21 | | | | 13 | | Total deferred expense | | | 466 | | | | 685 | | | | 733 | | | | 241 | | | | 503 | | | | 497 | | Amortization of deferred investment tax credits | | | (1 | ) | | | (1 | ) | | | (2 | ) | | | (1 | ) | | | (1 | ) | | | (1 | ) | Total income tax expense | | $ | 892 | | | $ | 811 | | | $ | 778 | | | $ | 659 | | | $ | 653 | | | $ | 540 | |
(1) | In 2012, Dominion’s current federal income tax expense for continuing and discontinued operations includes a $195 million benefit related to a carryback of its 2012 net operating loss. In 2011, Dominion’s deferred federal income tax expense includes the recognition of a $346 million benefit, including $51 million related to discontinued operations, for its 2011 net operating loss expected to be used to reduce taxable income in future years. |
(2) | In 2011, Virginia Power’s deferred federal income tax expense includes a $54 million benefit related to a portion of its 2011 net operating loss that is expected to be used in future years. Also, Virginia Power’s current federal income tax expense reflects the amounts of its 2011 net operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion | | | Virginia Power | | | Dominion Gas | | | Year Ended December 31, | | 2014 | | | 2013 | | | 2012 | | | 2014 | | | 2013 | | | 2012 | | | 2014 | | | 2013 | | | 2012 | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Federal | | $ | (11 | ) | | $ | 317 | | | $ | 43 | | | $ | 85 | | | $ | 357 | | | $ | 70 | | | $ | 86 | | | $ | 158 | | | $ | (8 | ) | State | | | 14 | | | | 110 | | | | 84 | | | | 67 | | | | 62 | | | | 81 | | | | 32 | | | | 41 | | | | 2 | | Total current expense (benefit) | | | 3 | | | | 427 | | | | 127 | | | | 152 | | | | 419 | | | | 151 | | | | 118 | | | | 199 | | | | (6 | ) | Deferred: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Federal | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Taxes before operating loss carryforwards and investment tax credits | | | 956 | | | | 563 | | | | 645 | | | | 381 | | | | 224 | | | | 482 | | | | 192 | | | | 92 | | | | 257 | | Tax benefit of operating loss carryforwards | | | (352 | ) | | | (18 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | Investment tax credits | | | (152 | ) | | | (48 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | State | | | (2 | ) | | | (31 | ) | | | 40 | | | | 16 | | | | 17 | | | | 21 | | | | 24 | | | | 10 | | | | 37 | | Total deferred expense | | | 450 | | | | 466 | | | | 685 | | | | 397 | | | | 241 | | | | 503 | | | | 216 | | | | 102 | | | | 294 | | Amortization of deferred investment tax credits | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | — | | | | — | | | | — | | Total income tax expense | | $ | 452 | | | $ | 892 | | | $ | 811 | | | $ | 548 | | | $ | 659 | | | $ | 653 | | | $ | 334 | | | $ | 301 | | | $ | 288 | |
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion | | | Virginia Power | | | Dominion Gas | | | Year Ended December 31, | | 2014 | | | 2013 | | | 2012 | | | 2014 | | | 2013 | | | 2012 | | | 2014 | | | 2013 | | | 2012 | | U.S. statutory rate | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | Increases (reductions) resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | State taxes, net of federal benefit | | | — | | | | 2.1 | | | | 4.2 | | | | 3.8 | | | | 3.1 | | | | 3.9 | | | | 4.4 | | | | 4.3 | | | | 3.4 | | Investment tax credits | | | (8.6 | ) | | | (1.8 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | Production tax credits | | | (1.2 | ) | | | (0.6 | ) | | | (0.5 | ) | | | (0.6 | ) | | | (0.2 | ) | | | — | | | | — | | | | — | | | | — | | Valuation allowances | | | 0.7 | | | | (0.1 | ) | | | (0.7 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | AFUDC - equity | | | — | | | | (0.6 | ) | | | (0.9 | ) | | | — | | | | (0.8 | ) | | | (0.9 | ) | | | — | | | | (0.1 | ) | | | (0.6 | ) | Employee stock ownership plan deduction | | | (0.9 | ) | | | (0.6 | ) | | | (0.7 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | Other, net | | | 0.4 | | | | (0.4 | ) | | | (0.6 | ) | | | 0.8 | | | | (0.4 | ) | | | 0.3 | | | | 0.1 | | | | 0.3 | | | | 0.7 | | Effective tax rate | | | 25.4 | % | | | 33.0 | % | | | 35.8 | % | | | 39.0 | % | | | 36.7 | % | | | 38.3 | % | | | 39.5 | % | | | 39.5 | % | | | 38.5 | % |
Dominion’s effective tax rate in 2014 reflects the recognition of state tax credits and previously unrecognized tax benefits due to the expiration of statutes of limitations.
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to Dominion’s and Virginia Power’s effective income tax rate as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion | | | Virginia Power | | | Year Ended December 31, | | 2013 | | | 2012 | | | 2011 | | | 2013 | | | 2012 | | | 2011 | | U.S. statutory rate | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % | Increases (reductions) resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | State taxes, net of federal benefit | | | 2.1 | | | | 4.2 | | | | 1.9 | | | | 3.1 | | | | 3.9 | | | | 4.4 | | Valuation allowances | | | (0.1 | ) | | | (0.7 | ) | | | — | | | | — | | | | — | | | | — | | Investment and production tax credits | | | (2.4 | ) | | | (0.5 | ) | | | (0.6 | ) | | | (0.2 | ) | | | — | | | | — | | AFUDC – equity | | | (0.6 | ) | | | (0.9 | ) | | | (0.6 | ) | | | (0.8 | ) | | | (0.9 | ) | | | (0.8 | ) | Employee stock ownership plan deduction | | | (0.6 | ) | | | (0.7 | ) | | | (0.6 | ) | | | — | | | | — | | | | — | | Other, net | | | (0.4 | ) | | | (0.6 | ) | | | (0.7 | ) | | | (0.4 | ) | | | 0.3 | | | | 1.1 | | Effective tax rate | | | 33.0 | % | | | 35.8 | % | | | 34.4 | % | | | 36.7 | % | | | 38.3 | % | | | 39.7 | % |
Dominion’s effective tax rate in 2012 reflects a $20 million reduction of a valuation allowance related to state operating loss carryforwards attributable to Fairless. After considering the results of Fairless’ operations in recent years and a forecast of future operating results reflecting Dominion’s planned purchase of the facility, Dominion concluded that it was more likely than not that the tax benefit of the operating losses would be realized. Dominion acquired Fairless in 2013 and will continue to evaluate the likelihood of realizing these tax benefits on a quarterly basis.
The Companies’ deferred income taxes consist of the following: | | | | Dominion | | Virginia Power | | | Dominion | | Virginia Power | | Dominion Gas | | | At December 31, | | 2013 | | 2012 | | 2013 | | | 2012 | | | 2014 | | 2013 | | 2014 | | 2013 | | 2014 | | 2013 | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | Deferred income taxes: | | | | | | | | | | | | | | | | | | | | | Total deferred income tax assets | | $ | 2,142 | | | $ | 2,505 | | | $ | 462 | | | $ | 466 | | | $ | 2,023 | | | $ | 2,142 | | | $ | 500 | | | $ | 462 | | | $ | 227 | | | $ | 216 | | Total deferred income tax liabilities | | | 8,463 | | | | 7,716 | | | | 4,498 | | | | 4,238 | | | | 8,663 | | | | 8,463 | | | | 4,915 | | | | 4,498 | | | | 2,289 | | | | 2,103 | | Total net deferred income tax liabilities | | $ | 6,321 | | | $ | 5,211 | | | $ | 4,036 | | | $ | 3,772 | | | $ | 6,640 | | | $ | 6,321 | | | $ | 4,415 | | | $ | 4,036 | | | $ | 2,062 | | | $ | 1,887 | | Total deferred income taxes: | | | | | | | | | | | | | | | | | | | | | Plant and equipment, primarily depreciation method and basis differences | | $ | 5,383 | | | $ | 4,601 | | | $ | 3,628 | | | $ | 3,394 | | | $ | 5,895 | | | $ | 5,383 | | | $ | 3,965 | | | $ | 3,628 | | | $ | 1,417 | | | $ | 1,266 | | Nuclear decommissioning | | | 1,136 | | | | 994 | | | | 441 | | | | 407 | | | | 1,241 | | | | 1,136 | | | | 474 | | | | 441 | | | | — | | | | — | | Deferred state income taxes | | | 606 | | | | 474 | | | | 285 | | | | 265 | | | | 659 | | | | 606 | | | | 299 | | | | 285 | | | | 207 | | | | 182 | | Federal benefit of deferred state income taxes | | | (212 | ) | | | (166 | ) | | | (100 | ) | | | (93 | ) | | | (231 | ) | | | (212 | ) | | | (105 | ) | | | (100 | ) | | | (72 | ) | | | (64 | ) | Deferred fuel, purchased energy and gas costs | | | (33 | ) | | | 3 | | | | (50 | ) | | | (16 | ) | | | 27 | | | | (33 | ) | | | 18 | | | | (50 | ) | | | 7 | | | | 13 | | Pension benefits | | | 435 | | | | 231 | | | | (52 | ) | | | (17 | ) | | | 272 | | | | 435 | | | | (77 | ) | | | (52 | ) | | | 567 | | | | 522 | | Other postretirement benefits | | | (78 | ) | | | (171 | ) | | | (3 | ) | | | (7 | ) | | | (17 | ) | | | (78 | ) | | | 13 | | | | (3 | ) | | | (12 | ) | | | (13 | ) | Loss and credit carryforwards | | | (797 | ) | | | (656 | ) | | | (106 | ) | | | (77 | ) | | | (1,434 | ) | | | (797 | ) | | | (116 | ) | | | (106 | ) | | | (10 | ) | | | (10 | ) | Valuation allowances | | | 69 | | | | 93 | | | | — | | | | — | | | | 87 | | | | 69 | | | | — | | | | — | | | | — | | | | — | | Partnership basis differences | | | 125 | | | | 174 | | | | — | | | | — | | | | 304 | | | | 125 | | | | — | | | | — | | | | 42 | | | | 42 | | Other | | | (313 | ) | | | (366 | ) | | | (7 | ) | | | (84 | ) | | | (163 | ) | | | (313 | ) | | | (56 | ) | | | (7 | ) | | | (84 | ) | | | (51 | ) | Total net deferred income tax liabilities | | $ | 6,321 | | | $ | 5,211 | | | $ | 4,036 | | | $ | 3,772 | | | $ | 6,640 | | | $ | 6,321 | | | $ | 4,415 | | | $ | 4,036 | | | $ | 2,062 | | | $ | 1,887 | |
At December 31, 2013,2014, Dominion had the following deductible loss and credit carryforwards: Federal loss carryforwards of $1.2$2.2 billion that expire if unutilized during the period 2021 through 2033;2034; Federal investment tax credits of $58$245 million that expire if unutilized during the period 2033 through 2033;2034; Federal production and other tax credits of $45$65 million that expire if unutilized during the period 2031 through 2033;2034; State loss carryforwards of $1.5$1.7 billion that expire if unutilized during the period 20142018 through 2033.2034. A valuation allowance on $763$962 million of these carryforwards has been established; State minimum tax credits of $133$194 million that do not expire; and State investment tax credits of $7$29 million that expire if unutilized during the period 2016 through 2017.2019. At December 31, 2013,2014, Virginia Power had the following deductible loss and credit carryforwards: Federal loss carryforwards of $282$279 million that expire if unutilized during the period 2031 through 2033; and
Combined Notes to Consolidated Financial Statements, Continued
Federal production and other tax credits of $5$14 million that expire if unutilized during the period 2031 through 2034. At December 31, 2014, Dominion Gas had the following deductible loss carryforwards: Federal loss carryforwards of $25 million that expire if unutilized during the period 2031 through 2033; and State loss carryforwards of $2$4 million that expire if unutilized during the period 2031 through 2033.2032. Dominion Gas had no credit carryforwards at December 31, 2014. A reconciliation of changes in the Companies’ unrecognized tax benefits follows: | | | | Dominion | | Virginia Power | | | Dominion | | Virginia Power | | Dominion Gas | | | | | 2013 | | 2012 | | 2011 | | 2013 | | 2012 | | 2011 | | | 2014 | | 2013 | | 2012 | | 2014 | | 2013 | | 2012 | | 2014 | | 2013 | | 2012 | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at January 1 | | $ | 293 | | | $ | 347 | | | $ | 307 | | | $ | 57 | | | $ | 114 | | | $ | 117 | | | $ | 222 | | | $ | 293 | | | $ | 347 | | | $ | 39 | | | $ | 57 | | | $ | 114 | | | $ | 29 | | | $ | 30 | | | $ | 30 | | Increases—prior period positions | | | 17 | | | | 28 | | | | 127 | | | | 12 | | | | 4 | | | | 22 | | | Decreases—prior period positions | | | (99 | ) | | | (106 | ) | | | (119 | ) | | | (42 | ) | | | (80 | ) | | | (51 | ) | | Increases—current period positions | | | 30 | | | | 43 | | | | 64 | | | | 14 | | | | 24 | | | | 47 | | | Decreases—current period positions | | | (5 | ) | | | — | | | | (21 | ) | | | — | | | | — | | | | (21 | ) | | Increases-prior period positions | | | | 24 | | | | 17 | | | | 28 | | | | 2 | | | | 12 | | | | 4 | | | | — | | | | — | | | | — | | Decreases-prior period positions | | | | (26 | ) | | | (99 | ) | | | (106 | ) | | | (16 | ) | | | (42 | ) | | | (80 | ) | | | — | | | | (1 | ) | | | — | | Increases-current period positions | | | | 16 | | | | 30 | | | | 43 | | | | 11 | | | | 14 | | | | 24 | | | | — | | | | — | | | | — | | Decreases-current period positions | | | | — | | | | (5 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | Settlements with tax authorities | | | (2 | ) | | | (4 | ) | | | — | | | | (2 | ) | | | (4 | ) | | | — | | | | — | | | | (2 | ) | | | (4 | ) | | | — | | | | (2 | ) | | | (4 | ) | | | — | | | | — | | | | — | | Expiration of statutes of limitations | | | (12 | ) | | | (15 | ) | | | (11 | ) | | | — | | | | (1 | ) | | | — | | | | (91 | ) | | | (12 | ) | | | (15 | ) | | | — | | | | — | | | | (1 | ) | | | — | | | | — | | | | — | | Balance at December 31 | | $ | 222 | | | $ | 293 | | | $ | 347 | | | $ | 39 | | | $ | 57 | | | $ | 114 | | | $ | 145 | | | $ | 222 | | | $ | 293 | | | $ | 36 | | | $ | 39 | | | $ | 57 | | | $ | 29 | | | $ | 29 | | | $ | 30 | |
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. For Dominion and its subsidiaries, these unrecognized tax benefits were $77 million, $126 million $167 million and $184$167 million at December 31, 2014, 2013 2012 and 2011,2012, respectively. For Dominion, the change in these unrecognized tax benefits decreased income tax expense by $47 million and $29 million in 2014 and 2013, respectively, and increased income tax expense by $1 million and $51 million in 2012 and 2011, respectively.2012. For Virginia Power, these unrecognized tax benefits were $8 million $13 millionat December 31, 2014 and $202013, and $13 million at December 31, 2013, 2012 and 2011, respectively.2012. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by less than $1 million in 2014, and increased income tax expense by $4 million $1 million and $6$1 million in 2013 and 2012, respectively. For Dominion Gas, these unrecognized tax benefits were $19 million at December 31, 2014 and 2011, respectively.2013 and $20 million at December 31, 2012. For Dominion Gas, the change in these unrecognized tax benefits affected income tax expense by less than $1 million in 2014, 2013 and 2012. In January 2012, the Appellate Division of the IRS informed Dominion that the Joint Committee had completed its review of the settlement of tax years 2004 and 2005 for Dominion and its consolidated subsidiaries. Since the measurement of unrecognized tax benefits in 2011 considered the results of completed settlement negotiations, Dominion’s results of operations in 2012 were not affected. In April 2012, the IRS issued its Revenue Agent Report for Dominion’s consolidated tax returns for tax years 2006 and 2007, reflecting the resolution of all issues except one that was subsequently settled in 2012.
Combined Notes to Consolidated Financial Statements, Continued The IRS examination of tax years 2008, 2009, 2010 and 2010 began in the first quarter of 2012 and was later expanded to include the examination of the 2011 tax year. The audit concluded in late 2013, resulting in a payment of $46 million. However, the amount ofmillion, and an adjustment to a refund previously received by Dominion for its carryback of 2008 losses to 2007 was adjusted.2007. The loss carryback, as adjusted, has beenwas submitted to the Joint Committee for review. Dominion anticipates resolution of this matter earlyEarly in 2014, Dominion received notification that the matter had been resolved with no further adjustments. Accordingly, except for 2007 and 2008, the earliest tax year remaining open for examination of Dominion’s federal tax returns is 2012.
Effective for its 2014 tax year, Dominion has been accepted into the CAP. The CAP is a method of identifying and resolving tax issues through open, cooperative, and transparent interaction between the IRS and taxpayers prior to the filing of a return. Through the CAP, Dominion will have the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions accepted by the IRS. Under a Pre-CAP plan, the IRS audit of tax years 2012 and 2013 will beginbegan in early 2014. With the audit protection afforded tax accounting method changes implemented under the September 2013 IRS regulations,It is reasonably possible that settlement negotiations and expiration of statutes of limitations it is reasonably possible thatcould result in a decrease in unrecognized tax benefits could decrease in 20142015 by up to $115$30 million for Dominion and up to $25 million for Virginia Power. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by up to $65$10 million for Dominion and $7 million for Virginia Power.
Otherwise, with regard to 20132014 and prior years, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2014.2015. After considering the possibility of potential changes in the status of its remaining unrecognized tax benefits, Dominion Gas has concluded that no significant changes are reasonably possible to occur in 2015. For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows: | | | | | | State | | Earliest
Open Tax
Year | | Pennsylvania(1) | | | 2010 | 2010 | | Connecticut | | | 2011 | 2010 | | MassachusettsVirginia(2)
| | | 2011 | 2008 | | West Virginia(1) | | | 2011 | 2010 | | West VirginiaNew York(1)
| | | 2007 | 2010 | |
| (1) | Virginia is the onlyConsidered a major state consideredfor Dominion Gas’ operations. |
| (2) | Considered a major state for Virginia Power’s operations. |
Dominion and Virginia PowerThe Companies are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are subject to examination.
Discontinued Operations Details of income tax expense for Dominion’s discontinued operations were as follows: | | | | Dominion | | | | | | | Year Ended December 31, | | 2013 | | 2012 | | 2011 | | | 2013 | | 2012 | | | (millions) | | | | | | | | | | | | | Current: | | | | | | | | | | | Federal | | | (274 | ) | | | (248 | ) | | | (41 | ) | | $ | (274 | ) | | $ | (248 | ) | State | | | (41 | ) | | | (6 | ) | | | (17 | ) | | | (41 | ) | | | (6 | ) | Total current benefit | | | (315 | ) | | | (254 | ) | | | (58 | ) | | | (315 | ) | | | (254 | ) | Deferred: | | | | | | | | | | | Federal | | | 232 | | | | (368 | ) | | | 10 | | | | 232 | | �� | | (368 | ) | State | | | 40 | | | | (70 | ) | | | 15 | | | | 40 | | | | (70 | ) | Total deferred expense (benefit) | | | 272 | | | | (438 | ) | | | 25 | | | | 272 | | | | (438 | ) | Total income tax benefit | | | (43 | ) | | | (692 | ) | | | (33 | ) | | $ | (43 | ) | | $ | (692 | ) |
Dominion’s effective tax rate for 2013 reflects the impact of goodwill written off in the sale of Kincaid and Brayton Point and Kincaid that is not deductible for tax purposes. Dominion’s effective tax rate for 2011 reflects an expectation that State Line’s deferred tax assets, including 2011 operating losses, will not be realized in State Line’s separately filed state tax returns.
NOTE 6. FAIR VALUE MEASUREMENTS Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of Dominion’s and Virginia Power’sthe Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion and Virginia Power apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, and nuclear decommissioning trust and other investments including those held in Dominion’s rabbi, pension and other postretirement benefit plan trusts, in accordance with the requirements described above. Dominion Gas applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments and investments held in pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above. These credit adjustments are currently not material to the derivative fair values.
Inputs and Assumptions The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, theythe Companies consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases theythe Companies must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect their market assumptions. Dominion’s and Virginia Power’sThe Companies’ commodity derivative valuations are prepared by theDominion’s ERM department. The ERM department reports directly to the Companies’Dominion’s CFO. The ERM department creates daily mark-to-market valuations for the Companies’ derivative transactions using computer-based statistical models. The inputs that go into the market valuations are transactional information stored in the systems of record and market pricing information that resides in data warehouse databases. The majority of forward prices are automatically uploaded into the data warehouse databases from various third-party sources. Inputs obtained from third-party sources are evaluated for reliability considering the reputation, independence, market presence, and methodology used by the third-party. If forward prices are not available from third-party sources, then the ERM department models the forward prices based on other available market data. A team consisting of risk management and risk quantitative analysts meets each business day to assess the validity of market prices and mark-to-market valuations. During this meeting, the changes in mark-to-market valuations from period to period are examined and qualified against historical expectations. If any discrepancies are identified during this process, the mark-to-market valuations or the market pricing information is evaluated further and adjusted, if necessary.
For options and contracts with option-like characteristics where observable pricing information is not available from external sources, the CompaniesDominion and Virginia Power generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. The CompaniesDominion and Virginia Power use other option models under special circumstances, including a Spread Approximation Model when contracts include different commodities or commodity locations and a Swing Option Model when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, the CompaniesDominion and Virginia Power may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value. The inputs and assumptions used in measuring fair value include the following: For commodity and foreign currency derivative contracts: | | Ÿ | | Forward commodity prices |
| | Ÿ | | Forward foreign currency prices |
Combined Notes to Consolidated Financial Statements, Continued
| | Ÿ | | Credit quality of counterparties and Dominion and Virginia Powerthe Companies |
For interest rate derivative contracts: | | Ÿ | | Credit quality of counterparties and Dominion and Virginia Powerthe Companies |
For investments: | | Ÿ | | Quoted securities prices and indices |
| | Ÿ | | Securities trading information including volume and restrictions |
| | Ÿ | | NAV (for alternative investments and common/collective trust funds) |
Dominion and Virginia PowerThe Companies regularly evaluate and validate the inputs used to estimate fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities and investments in which the Companies transact.
Levels The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: | Ÿ | | Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as the majority ofcertain exchange-traded derivatives, and exchange-listed equities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion and Virginia Power, benefit plan trust funds for Dominion and Dominion Gas, and rabbi and benefit plan trust funds for Dominion. |
| Ÿ | | Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 |
Combined Notes to Consolidated Financial Statements, Continued | | | primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps, interest rate swaps, foreign currency forwards and options, restricted cash equivalents, and certain Treasury securities, money market funds, common/collective trust funds, and corporate, state and municipal debt securities held in nuclear decommissioning trust funds for Dominion and Virginia Power, benefit plan trust funds for Dominion and Dominion Gas, and rabbi and benefit plan trust funds for Dominion. |
| Ÿ | | Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for Dominion and Virginia Powerthe Companies consist of long-dated commodity derivatives, FTRs, NGLs, natural gas peaking options and other modeled commodity derivatives. Additional instruments categorized in Level 3 for Dominion include NGLs and natural gas peaking options andDominion Gas include alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments, held in benefit plan trust funds. |
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. In these cases, 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. For derivative contracts, Dominion and Virginia Powerthe Companies recognize transfers among Level 1, Level 2 and Level 3 based on fair values as of the first day of the month in which the transfer occurs. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change. Level 3 Valuations Fair value measurements are categorized as Level 3 when a significant amount of price or other inputs that are considered to be unobservable are used in their valuations. Long-dated commodity derivatives are generally based on unobservable inputs due to the length of time to settlement and the absence of market activity and are therefore categorized as Level 3. For NGL derivatives, market illiquidity requires a valuation based on proxy markets that do not always correlate to the actual instrument, therefore they are categorized as Level 3. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from ISO auctions, which are generally not considered to be liquid markets. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets. Alternative investments are categorized as Level 3 due to the absence of quoted market prices, illiquidity and the long-term nature of these assets. These investments are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value state-
mentsstatements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date.
Dominion and Virginia PowerThe Companies enter into certain physical and financial forwards, and futures, options and full requirements contracts,swaps, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards and futures contracts. An option model is used to value Level 3 physical and full requirements contracts.financial options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. Full requirements contracts add load shaping and usage factors in addition to the discounted cash flow model inputs. An option model is used to value Level 3 physical and financial options. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, price correlations, mean reversion speeds, the original sales prices, and volumes. For Level 3 fair value measurements, the forward market prices, thecredit spreads and implied price volatilities price correlations, load shaping, mean reversion speeds and usage factors are considered unobservable. The unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.
Combined Notes to Consolidated Financial Statements, Continued
The following table presents Dominion’s and Virginia Power’sDominion Gas’ quantitative information about Level 3 fair value measurements.measurements at December 31, 2014. The range and weighted average are presented in dollars for market price inputs years for mean reversion speeds, and percentages for price volatility price correlations, load shaping, and usage factors.credit spreads. | | | | Fair Value (millions) | | | Valuation Techniques | | Unobservable Input | | | | Range | | | Weighted
Average(1) | | | Fair Value (millions) | | | Valuation Techniques | | | Unobservable Input | | | Range | | | Weighted
Average(1) | | At December 31, 2013 | | | | | | | | | | | | | | Assets: | | | | | | | | | | | | | | | | | | | | | | | | | Physical and Financial Forwards and Futures: | | | | | | | | | | | | | | | | | | | | | | | | | Natural Gas(2) | | $ | 14 | | | Discounted Cash Flow | | | Market Price (per Dth) | | | (5) | | | (2) – 5 | | | | 2 | | | $ | 74 | | | | Discounted Cash Flow | | | | Market Price (per Dth) | | | (4) | | | (2) – 11 | | | | (1 | ) | FTRs(3) | | | 2 | | | Discounted Cash Flow | | | Market Price (per MWh) | | | (5) | | | (1) – 5 | | | | — | | | Liquids(4) | | | 6 | | | Discounted Cash Flow | | | Market Price (per Gal) | | | (5) | | | 1 – 3 | | | | 1 | | | | | | | | | | | Credit Spread | | | (6) | | | 1% – 5% | | | | 2 | % | FTRs | | | | 44 | | | | Discounted Cash Flow | | | | Market Price (per MWh) | | | (4) | | | (1) – 21 | | | | 3 | | NGLs(3) | | | | 2 | | | | Discounted Cash Flow | | | | Market Price (per Gal) | | | (4) | | | 0 – 2 | | | | 1 | | Physical and Financial Options: | | | | | | | | | | | | | | | | | | | | | | | | | Natural Gas(2) | | | 4 | | | Option Model | | | Market Price (per Dth) | | | (5) | | | 3 – 5 | | | | 4 | | | | | | | | | | Price Volatility | | | (6) | | | 14% – 36% | | | | 20 | % | | | | | | | | | Price Correlation | | | (7) | | | (9%) – 100% | | | | 36 | % | | | | | | | | | Mean Reversion | | | (8) | | | .01 – 1 | | | | .53 | | | Full Requirements Contracts: | | | | | | | | | | | | | | Electricity | | | 6 | | | Discounted Cash Flow | | | Market Price (per MWh) | | | (5) | | | 10 – 406(11) | | | | 42 | | | | | | | | | | Load Shaping | | | (9) | | | 0% – 10% | | | | 7 | % | | Natural Gas | | | | 5 | | | | Option Model | | | | Market Price (per Dth) | | | (4) | | | 2 – 4 | | | | 3 | | | | | | | | | | Usage Factor | | | (10) | | | 11% – 29% | | | | 16 | % | | | | | | | Price Volatility | | | (5) | | | 19% – 67% | | | | 33 | % | Total assets | | $ | 32 | | | | | | | | | $ | 125 | | | | | | | | | | Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | Physical and Financial Forwards and Futures: | | | | | | | | | | | | | | | | | | | | | | | | | Natural Gas(2) | | $ | 19 | | | Discounted Cash Flow | | | Market Price (per Dth) | | | (5) | | | (2) – 30 | | | | 1 | | | $ | 12 | | | | Discounted Cash Flow | | | | Market Price (per Dth) | | | (4) | | | (2) – 4 | | | | 2 | | Electricity | | | 1 | | | Discounted Cash Flow | | | Market Price (per MWh) | | | (5) | | | 28 – 240(11) | | | | 39 | | | FTRs(3) | | | 9 | | | Discounted Cash Flow | | | Market Price (per MWh) | | | (5) | | | (1) – 5 | | | | 1 | | | Liquids(4) | | | 11 | | | Discounted Cash Flow | | | Market Price (per Gal) | | | (5) | | | 1 – 3 | | | | 1 | | | FTRs | | | | 4 | | | | Discounted Cash Flow | | | | Market Price (per MWh) | | | (4) | | | (21) – 21 | | | | — | | Physical and Financial Options: | | | | | | | | | | | | | | | | | | | | | | | | | Natural Gas(2) | | | 8 | | | Option Model | | | Market Price (per Dth) | | | (5) | | | 3 – 11 | | | | 7 | | | | | | | | | | Price Volatility | | | (6) | | | 14% – 36% | | | | 20 | % | | | | | | | | | Price Correlation | | | (7) | | | (9%) – 100% | | | | 36 | % | | Natural Gas | | | | 2 | | | | Option Model | | | | Market Price (per Dth) | | | (4) | | | 2 – 4 | | | | 3 | | | | | | | | | | Mean Reversion | | | (8) | | | .01 – 1 | | | | .53 | | | | | | | | Price Volatility | | | (5) | | | 19% – 67% | | | | 33 | % | Total liabilities | | $ | 48 | | | | | | | | | $ | 18 | | | | | | | | | |
| (1) | Averages weighted by volume. |
| (3) | Information represents Virginia Power’sDominion Gas’ quantitative information about Level 3 fair value measurements. |
(5) | Represents market prices beyond defined terms for Levels 1 and 2. |
(6)(5) | Represents volatilities unrepresented in published markets. |
(7)(6) | Represents intra-price correlations for which markets do not exist. |
(8) | Represents mean-reverting propertycredit spreads unrepresented in price simulation modeling. |
(9) | Converts block monthly loads to 24-hour load shapes. |
(10) | Represents expected increase (decrease) in sales volumes compared to historical usage. |
(11) | The range in market prices is the result of large variability in hourly power prices during peak and off-peak hours.published markets. |
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows: | | | | | | | | | Significant Unobservable
Inputs | | Position | | Change to Input | | Impact on Fair Value
Measurement | | Market Price | | Buy | | Increase (decrease) | | | Gain (loss) | | Market Price | | Sell | | Increase (decrease) | | | Loss (gain) | | Price Volatility | | Buy | | Increase (decrease) | | | Gain (loss) | | Price Volatility | | Sell | | Increase (decrease) | | | Loss (gain) | | Price CorrelationCredit Spread
| | BuyAsset | | Increase (decrease) | | | Loss (gain) | | Price Correlation
| | Sell | | Increase (decrease) | | | Gain (loss) | | Load Shaping
| | Sell(1) | | Increase (decrease) | | | Loss (gain) | | Usage Factor
| | Sell(2) | | Increase (decrease) | | | Gain (loss) | | Mean Reversion
| | Buy | | Increase (decrease) | | | Loss (gain) | | Mean Reversion
| | Sell | | Increase (decrease) | | | Gain (loss) | |
(1) | Assumes the contract is in a gain position and load increases during peak hours. |
(2) | Assumes the contract is in a gain position. |
Nonrecurring Fair Value Measurements NDATURALOMINION GAS FACILITIES
Natural Gas Assets In the fourth quarter of 2014, Dominion Gas recorded an impairment charge of $9 million ($6 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write off previously capitalized costs following the cancellation of a development project. In June 2013, Dominion Gas purchased certain natural gas infrastructure facilities that were previously leased from third parties. The purchase price was based on terms in the lease, which exceeded current market pricing. As a result of the purchase price and expected losses, Dominion Gas recorded an impairment charge of $49 million ($29 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write down the long-lived assets to their estimated fair values of less than $1 million. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion Gas used the income approach (discounted cash flows) to estimate the fair value of the assets in this impairment test. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs, including estimates of future production and other commodity prices. Also in June 2013, Dominion Gas recorded an impairment charge of $6 million ($4 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write off previously capitalized costs following the cancellation of two development projects.
MDERCHANT POWER STATIONSOMINION
Merchant Power Stations In the third quarter of 2012, Dominion decided to pursue the sale of Brayton Point and Kincaid, as well as its 50% interest in Elwood, which is an equity method investment. Since Dominion was unlikely to operate the Brayton Point and Kincaid facilities through their estimated useful lives, Dominion evaluated these power stations for recoverability under a probability weighted approach and concluded that the carrying values of these facilities were not impaired as of September 30, 2012. At December 31, 2012, Dominion updated its recoverability analysis for Brayton Point and Kincaid to reflect bids received and an updated probability weighting. As a result of this updated evaluation, Dominion recorded an impairment charge of approximately $1.6 billion ($1.0 billion after-tax), which is included in loss from discontinued operations in its Consolidated Statement of Income, to write down Brayton Point’s and Kincaid’s long-lived assets to their estimated fair value of approximately $216 million. Dominion used a market approach to estimate the fair value of Brayton Point’s and Kincaid’s long-lived assets. This was considered a Level 2 fair value measurement given it was based on bids received.
Combined Notes to Consolidated Financial Statements, Continued See Note 3 for information regarding the sale of Brayton Point, Kincaid and Dominion’s equity method investment in Elwood, including an additional impairment. In April 2011, Dominion announced it would pursue a sale of Kewaunee since it was not able to move forward with its original plan to grow its nuclear fleet in the Midwest to take advantage of economies of scale. Dominion was unable to find a buyer for the facility. In addition, the power purchase agreements for the two utilities that contracted to buy Kewaunee’s generation expired in December 2013 at a time of low wholesale electricity prices in the region. At September 30, 2012, Dominion expected that it would permanently cease generation operations at Kewaunee in 2013 and commence decommissioning of the facility. As a result, Dominion evaluated Kewaunee for impairment since it was more likely than not that Kewaunee would be retired before the end of its previously estimated useful life. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of Kewaunee’s long-lived assets. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs including estimates of future power and other commodity prices. As a result of this evaluation in September 2012, Dominion recorded impairment and other charges of $435 million ($281 million after-tax) largely reflected in other operations and maintenance expense in its Consolidated Statement of Income. This primarily reflects a $378 million ($244 million after-tax) charge for the full impairment of Kewaunee’s long-lived assets, a write down of materials and supplies inventories of $33 million ($21 million after-tax), and a $24 million ($16 million after-tax) charge related to severance costs. The decision to decommission Kewaunee was approved by Dominion’s Board of Directors in October 2012 after consideration of the factors discussed above, which made it uneconomic for Kewaunee to continue operations. Kewaunee ceased operations and decommissioning activities commenced in May 2013. During March 2011, Dominion determined that it was unlikely that State Line would participate in the May 2011 PJM capacity base residual auction that would commit State Line’s capacity from June 2014 through May 2015. This determination reflected an expectation that margins for coal-fired generation will remain compressed in the 2014 and 2015 period in combination with the expectation that State Line may be impacted during the same time period by environmental regulations that would likely require significant capital expenditures. As a result, Dominion evaluated State Line for impairment since it was more likely than not that State Line would be retired before the end of its previously estimated useful life. As a result of this evaluation, Dominion recorded an impairment charge of $55 million ($39 million after-tax), which is now reflected in loss from discontinued operations in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of less than $1 million. State Line was retired in March 2012 and sold in the second quarter of 2012.
As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of State Line’s long-lived assets. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs including estimates of future power and other commodity prices.
In the second quarter of 2012, an agreement was reached to sell Salem Harbor and the assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell. This resulted in a pre-tax charge of $27 million ($16 million after-tax), which is included in loss from discontinued operations in Dominion’s Consolidated Statement of Income. This was considered a Level 2 fair value measurement as it was based on the negotiated sales price. Salem Harbor was sold in the third quarter of 2012. EMISSIONS ALLOWANCES
In the third quarter of 2011, Dominion and Virginia Power evaluated their SO2 emissions allowances not expected to be consumed by generating units for potential impairment due to the EPA’s issuance of CSAPR as discussed in Note 22. Prior to the issuance of CSAPR, Dominion and Virginia Power held $57 million and $43 million, respectively, of SO2 emissions allowances obtained for ARP and CAIR compliance. Due to CSAPR’s establishment of a new allowance program and the elimination of CAIR, Dominion and Virginia Power had more SO2 emissions allowances than needed for ARP compliance. As a result of this evaluation, Dominion and Virginia Power recorded an impairment charge to write down these emissions allowances to their estimated fair value of less than $1 million. For Dominion, the $57 million ($34 million after-tax) charge was recorded partially in other operations and maintenance expense ($43 million, $26 million after-tax) and partially in loss from discontinued operations ($14 million, $8 million after-tax) in its Consolidated Statement of Income. For Virginia Power, the $43 million ($26 million after-tax) charge was recorded in other operations and maintenance expense in its Consolidated Statement of Income.
To estimate the value of these emissions allowances, Dominion utilized a market approach by obtaining broker quotes to validate CSAPR’s impact on emissions allowance prices. How-
Combined Notes to Consolidated Financial Statements, Continued
ever, due to limited market activity for future SO2 vintage year allowances, this was considered a Level 3 fair value measurement.
Recurring Fair Value Measurements Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion’s and Dominion Gas’ pension and other postretirement benefit plans are presented in Note 21. DOMINION The following table presents Dominion’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions: | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | At December 31, 2014 | | | | | | | | | | Assets: | | | | | | | | | | Derivatives: | | | | | | | | | | Commodity | | | $ | 3 | | | $ | 567 | | | $ | 125 | | | $ | 695 | | Interest rate | | | | — | | | | 24 | | | | — | | | | 24 | | Investments(1): | | | | | | | | | | Equity securities: | | | | | | | | | | U.S.: | | | | | | | | | | Large Cap | | | | 2,669 | | | | — | | | | — | | | | 2,669 | | Other | | | | 6 | | | | — | | | | — | | | | 6 | | Non-U.S.: | | | | | | | | | | Large Cap | | | | 12 | | | | — | | | | — | | | | 12 | | Fixed Income: | | | | | | | | | | Corporate debt instruments | | | | — | | | | 441 | | | | — | | | | 441 | | U.S. Treasury securities and agency debentures | | | | 419 | | | | 190 | | | | — | | | | 609 | | State and municipal | | | | — | | | | 395 | | | | — | | | | 395 | | Other | | | | — | | | | 74 | | | | — | | | | 74 | | Cash equivalents and other | | | | 3 | | | | 10 | | | | — | | | | 13 | | Total assets | | | $ | 3,112 | | | $ | 1,701 | | | $ | 125 | | | $ | 4,938 | | Liabilities: | | | | | | | | | | Derivatives: | | | | | | | | | | Commodity | | | $ | 3 | | | $ | 571 | | | $ | 18 | | | $ | 592 | | Interest rate | | | | — | | | | 202 | | | | — | | | | 202 | | Total liabilities | | | $ | 3 | | | $ | 773 | | | $ | 18 | | | $ | 794 | | At December 31, 2013 | | | | | | | | | | | | | | | | | Assets: | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | 3 | | | $ | 718 | | | $ | 32 | | | $ | 753 | | | $ | 3 | | | $ | 718 | | | $ | 32 | | | $ | 753 | | Interest rate | | | — | | | | 137 | | | | — | | | | 137 | | | | — | | | | 137 | | | | — | | | | 137 | | Investments(1): | | | | | | | | | | | | | | | | | Equity securities: | | | | | | | | | | | | | | | | | U.S.: | | | | | | | | | | | | | | | | | Large Cap | | | 2,417 | | | | — | | | | — | | | | 2,417 | | | | 2,417 | | | | — | | | | — | | | | 2,417 | | Other | | | 79 | | | | — | | | | — | | | | 79 | | | | 79 | | | | — | | | | — | | | | 79 | | Non-U.S.: | | | | | | | | | | | | | | | | | Large Cap | | | 13 | | | | — | | | | — | | | | 13 | | | | 13 | | | | — | | | | — | | | | 13 | | Fixed Income: | | | | | | | | | | | | | | | | | Corporate debt instruments | | | — | | | | 345 | | | | — | | | | 345 | | | | — | | | | 345 | | | | — | | | | 345 | | U.S. Treasury securities and agency debentures | | | 415 | | | | 175 | | | | — | | | | 590 | | | | 415 | | | | 175 | | | | — | | | | 590 | | State and municipal | | | — | | | | 343 | | | | — | | | | 343 | | | | — | | | | 343 | | | | — | | | | 343 | | Other | | | — | | | | 3 | | | | — | | | | 3 | | | | — | | | | 3 | | | | — | | | | 3 | | Cash equivalents and other | | | — | | | | 103 | | | | — | | | | 103 | | | | — | | | | 103 | | | | — | | | | 103 | | Restricted cash equivalents | | | — | | | | 8 | | | | — | | | | 8 | | | | — | | | | 8 | | | | — | | | | 8 | | Total assets | | $ | 2,927 | | | $ | 1,832 | | | $ | 32 | | | $ | 4,791 | | | $ | 2,927 | | | $ | 1,832 | | | $ | 32 | | | $ | 4,791 | | Liabilities: | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | 3 | | | $ | 1,051 | | | $ | 48 | | | $ | 1,102 | | | $ | 3 | | | $ | 1,051 | | | $ | 48 | | | $ | 1,102 | | Total liabilities | | $ | 3 | | | $ | 1,051 | | | $ | 48 | | | $ | 1,102 | | | $ | 3 | | | $ | 1,051 | | | $ | 48 | | | $ | 1,102 | | At December 31, 2012 | | | | | | | | | | Assets: | | | | | | | | | | Derivatives: | | | | | | | | | | Commodity | | $ | 12 | | | $ | 639 | | | $ | 84 | | | $ | 735 | | | Interest rate | | | — | | | | 93 | | | | — | | | | 93 | | | Investments(1): | | | | | | | | | | Equity securities: | | | | | | | | | | U.S.: | | | | | | | | | | Large Cap | | | 1,973 | | | | — | | | | — | | | | 1,973 | | | Other | | | 59 | | | | — | | | | — | | | | 59 | | | Non-U.S.: | | | | | | | | | | Large Cap | | | 12 | | | | — | | | | — | | | | 12 | | | Fixed Income: | | | | | | | | | | Corporate debt instruments | | | — | | | | 325 | | | | — | | | | 325 | | | U.S. Treasury securities and agency debentures | | | 391 | | | | 152 | | | | — | | | | 543 | | | State and municipal | | | — | | | | 315 | | | | — | | | | 315 | | | Other | | | — | | | | 7 | | | | — | | | | 7 | | | Cash equivalents and other | | | 13 | | | | 67 | | | | — | | | | 80 | | | Restricted cash equivalents | | | — | | | | 33 | | | | — | | | | 33 | | | Total assets | | $ | 2,460 | | | $ | 1,631 | | | $ | 84 | | | $ | 4,175 | | | Liabilities: | | | | | | | | | | Derivatives: | | | | | | | | | | Commodity | | $ | 8 | | | $ | 528 | | | $ | 59 | | | $ | 595 | | | Interest rate | | | — | | | | 66 | | | | — | | | | 66 | | | Total liabilities | | $ | 8 | | | $ | 594 | | | $ | 59 | | | $ | 661 | | |
| (1) | Includes investments held in the nuclear decommissioning and rabbi trusts. |
The following table presents the net change in Dominion’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category: | | | | 2013 | | 2012 | | 2011 | | | 2014 | | 2013 | | 2012 | | | (millions) | | | | | | | | | | | | | | | Balance at January 1, | | $ | 25 | | | $ | (71 | ) | | $ | (50 | ) | | $ | (16 | ) | | $ | 25 | | | $ | (71 | ) | Total realized and unrealized gains (losses): | | | | | | | | | | | | | Included in earnings | | | (9 | ) | | | (15 | ) | | | (77 | ) | | | 97 | | | | (9 | ) | | | (15 | ) | Included in other comprehensive income (loss) | | | 1 | | | | 101 | | | | 14 | | | | 7 | | | | 1 | | | | 101 | | Included in regulatory assets/liabilities | | | (9 | ) | | | 30 | | | | (42 | ) | | | 109 | | | | (9 | ) | | | 30 | | Settlements | | | (23 | ) | | | 47 | | | | 88 | | | | (88 | ) | | | (23 | ) | | | 47 | | Transfers out of Level 3 | | | (1 | ) | | | (67 | ) | | | (4 | ) | | | (2 | ) | | | (1 | ) | | | (67 | ) | Balance at December 31, | | $ | (16 | ) | | $ | 25 | | | $ | (71 | ) | | $ | 107 | | | $ | (16 | ) | | $ | 25 | | The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | | $ | — | | | $ | 42 | | | $ | 22 | | | $ | 6 | | | $ | — | | | $ | 42 | |
The following table presents Dominion’s gains and losses included in earnings in the Level 3 fair value category: | | | | Operating
Revenue | | Electric Fuel
and Energy
Purchases | | Purchased
Gas | | Total | | | Operating
Revenue | | Electric Fuel
and Energy
Purchases | | Purchased
Gas | | Total | | | (millions) | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2014 | | | | | | | | | | Total gains (losses) included in earnings | | | $ | 4 | | | $ | 97 | | | $ | (4 | ) | | $ | 97 | | The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | | | | 4 | | | | 1 | | | | 1 | | | | 6 | | Year Ended December 31, 2013 | | | | | | | | | | | | | | | | | Total gains (losses) included in earnings | | $ | 11 | | | $ | (19 | ) | | $ | (1 | ) | | $ | (9 | ) | | $ | 11 | | | $ | (19 | ) | | $ | (1 | ) | | $ | (9 | ) | The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | | | 1 | | | | — | | | | (1 | ) | | | — | | | | 1 | | | | — | | | | (1 | ) | | | — | | Year Ended December 31, 2012 | | | | | | | | | | | | | | | | | Total gains (losses) included in earnings | | $ | 35 | | | $ | (50 | ) | | $ | — | | | $ | (15 | ) | | $ | 35 | | | $ | (50 | ) | | $ | — | | | $ | (15 | ) | The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | | | 42 | | | | — | | | | — | | | | 42 | | | | 42 | | | | — | | | | — | | | | 42 | | Year Ended December 31, 2011 | | | | | | | | | | Total gains (losses) included in earnings | | $ | (32 | ) | | $ | (45 | ) | | $ | — | | | $ | (77 | ) | | The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | | | 22 | | | | — | | | | — | | | | 22 | | |
Combined Notes to Consolidated Financial Statements, Continued VIRGINIA POWER The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2014. The range and weighted average are presented in dollars for market price inputs and percentages for credit spreads. | | | | | | | | | | | | | | | | | | | | | | | | Fair Value
(millions) | | | Valuation Techniques | | | Unobservable Input | | | Range | | | Weighted Average(1) | | Assets: | | | | | | | | | | | | | | | | | | | | | Physical and Financial Forwards and Futures: | | | | | | | | | | | | | | | | | | | | | FTRs | | $ | 44 | | | | Discounted Cash Flow | | | | Market Price (per MWh)(3) | | | | (1) – 21 | | | | 3 | | Natural gas(2) | | | 62 | | | | Discounted Cash Flow | | | | Market Price (per Dth)(3) | | | | (2) – 7 | | | | (1 | ) | | | | | | | | | | | | | Credit Spread(4) | | | | 1% – 5% | | | | 2 | % | Total assets | | $ | 106 | | | | | | | | | | | | | | | | | | Liabilities: | | | | | | | | | | | | | | | | | | | | | Physical and Financial Forwards and Futures: | | | | | | | | | | | | | | | | | | | | | FTRs | | $ | 4 | | | | Discounted Cash Flow | | | | Market Price (per MWh)(3) | | | | (21) – 21 | | | | — | | Total liabilities | | $ | 4 | | | | | | | | | | | | | | | | | |
| (1) | Averages weighted by volume. |
| (3) | Represents market prices beyond defined terms for Levels 1 and 2. |
| (4) | Represents credit spreads unrepresented in published markets. |
VIRGINIA POWERSensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
| | | | | | | | | Significant Unobservable
Inputs | | Position | | Change to Input | | Impact on Fair Value
Measurement | | Market Price | | Buy | | Increase (decrease) | | | Gain (loss) | | Market Price | | Sell | | Increase (decrease) | | | Loss (gain) | | Credit Spread | | Asset | | Increase (decrease) | | | Loss (gain) | |
The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions: | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | At December 31, 2014 | | | | | | | | | | Assets: | | | | | | | | | | Derivatives: | | | | | | | | | | Commodity | | | $ | — | | | $ | 7 | | | $ | 106 | | | $ | 113 | | Investments(1): | | | | | | | | | | Equity securities: | | | | | | | | | | U.S.: | | | | | | | | | | Large Cap | | | | 1,157 | | | | — | | | | — | | | | 1,157 | | Fixed Income: | | | | | | | | | | Corporate debt instruments | | | | — | | | | 250 | | | | — | | | | 250 | | U.S. Treasury securities and agency debentures | | | | 137 | | | | 61 | | | | — | | | | 198 | | State and municipal | | | | — | | | | 211 | | | | — | | | | 211 | | Other | | | | — | | | | 23 | | | | — | | | | 23 | | Total assets | | | $ | 1,294 | | | $ | 552 | | | $ | 106 | | | $ | 1,952 | | Liabilities: | | | | | | | | | | Derivatives: | | | | | | | | | | Commodity | | | $ | — | | | $ | 11 | | | $ | 4 | | | $ | 15 | | Interest rate | | | | — | | | | 72 | | | | — | | | | 72 | | Total liabilities | | | $ | — | | | $ | 83 | | | $ | 4 | | | $ | 87 | | At December 31, 2013 | | | | | | | | | | | | | | | | | Assets: | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 3 | | | $ | 2 | | | $ | 5 | | | $ | — | | | $ | 3 | | | $ | 2 | | | $ | 5 | | Interest rate | | | — | | | | 48 | | | | — | | | | 48 | | | | — | | | | 48 | | | | — | | | | 48 | | Investments(1): | | | | | | | | | | | | | | | | | Equity securities: | | | | | | | | | | | | | | | | | U.S.: | | | | | | | | | | | | | | | | | Large Cap | | | 1,021 | | | | — | | | | — | | | | 1,021 | | | | 1,021 | | | | — | | | | — | | | | 1,021 | | Other | | | 36 | | | | — | | | | — | | | | 36 | | | | 36 | | | | — | | | | — | | | | 36 | | Fixed Income: | | | | | | | | | | | | | | | | | Corporate debt instruments | | | — | | | | 191 | | | | — | | | | 191 | | | | — | | | | 191 | | | | — | | | | 191 | | U.S. Treasury securities and agency debentures | | | 146 | | | | 66 | | | | — | | | | 212 | | | | 146 | | | | 66 | | | | — | | | | 212 | | State and municipal | | | — | | | | 164 | | | | — | | | | 164 | | | | — | | | | 164 | | | | — | | | | 164 | | Cash equivalents and other | | | — | | | | 31 | | | | — | | | | 31 | | | | — | | | | 31 | | | | — | | | | 31 | | Restricted cash equivalents | | | — | | | | 8 | | | | — | | | | 8 | | | | — | | | | 8 | | | | — | | | | 8 | | Total assets | | $ | 1,203 | | | $ | 511 | | | $ | 2 | | | $ | 1,716 | | | $ | 1,203 | | | $ | 511 | | | $ | 2 | | | $ | 1,716 | | Liabilities: | | | | | | | | | | | | | | | | | Derivatives: | | | | | | | | | | | | | | | | | Commodity | | $ | — | | | $ | 3 | | | $ | 9 | | | $ | 12 | | | $ | — | | | $ | 3 | | | $ | 9 | | | $ | 12 | | Total Liabilities | | $ | — | | | $ | 3 | | | $ | 9 | | | $ | 12 | | | At December 31, 2012 | | | | | | | | | | Assets: | | | | | | | | | | Derivatives: | | | | | | | | | | Commodity | | $ | — | | | $ | 1 | | | $ | 5 | | | $ | 6 | | | Investments(1): | | | | | | | | | | Equity securities: | | | | | | | | | | U.S.: | | | | | | | | | | Large Cap | | | 779 | | | | — | | | | — | | | | 779 | | | Other | | | 27 | | | | — | | | | — | | | | 27 | | | Fixed Income: | | | | | | | | | | Corporate debt instruments | | | — | | | | 196 | | | | — | | | | 196 | | | U.S. Treasury securities and agency debentures | | | 168 | | | | 66 | | | | — | | | | 234 | | | State and municipal | | | — | | | | 118 | | | | — | | | | 118 | | | Other | | | — | | | | 1 | | | | — | | | | 1 | | | Cash equivalents and other | | | 7 | | | | 31 | | | | — | | | | 38 | | | Restricted cash equivalents | | | — | | | | 10 | | | | — | | | | 10 | | | Total assets | | $ | 981 | | | $ | 423 | | | $ | 5 | | | $ | 1,409 | | | Liabilities: | | | | | | | | | | Derivatives: | | | | | | | | | | Commodity | | $ | — | | | $ | 6 | | | $ | 3 | | | $ | 9 | | | Interest rate | | | — | | | | 25 | | | | — | | | | 25 | | | Total Liabilities | | $ | — | | | $ | 31 | | | $ | 3 | | | $ | 34 | | | Total liabilities | | | $ | — | | | $ | 3 | | | $ | 9 | | | $ | 12 | |
| (1) | Includes investments held in the nuclear decommissioning and rabbi trusts. |
The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category: | | | | 2013 | | 2012 | | 2011 | | | 2014 | | 2013 | | 2012 | | | (millions) | | | | | | | | | | | | | | | Balance at January 1, | | $ | 2 | | | $ | (28 | ) | | $ | 14 | | | $ | (7 | ) | | $ | 2 | | | $ | (28 | ) | Total realized and unrealized gains (losses): | | | | | | | | | | | | | Included in earnings | | | (17 | ) | | | (50 | ) | | | (45 | ) | | | 96 | | | | (17 | ) | | | (50 | ) | Included in regulatory assets/liabilities | | | (9 | ) | | | 30 | | | | (42 | ) | | | 109 | | | | (9 | ) | | | 30 | | Settlements | | | 17 | | | | 50 | | | | 45 | | | | (96 | ) | | | 17 | | | | 50 | | Balance at December 31, | | $ | (7 | ) | | $ | 2 | | | $ | (28 | ) | | $ | 102 | | | $ | (7 | ) | | $ | 2 | |
The gains and losses included in earnings in the Level 3 fair value category including any attributable to the change in unrealized gains and losses relating to assets still held at the reporting date, were classified in electric fuel and other energy-related purchases expense in Virginia Power’s Consolidated Statements of Income for the years ended December 31, 2014, 2013 2012 and 2011.2012. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2014, 2013 2012 and 2011.2012. DOMINION GAS The following table presents Dominion Gas’ assets and liabilities for commodity and interest rate derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions: | | | | | | | | | | | | | | | | | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | (millions) | | | | At December 31, 2014 | | | | | Assets: | | | | | Commodity | | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | | Total assets | | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | | Liabilities: | | | | | Interest rate | | $ | — | | | $ | 9 | | | $ | — | | | $ | 9 | | Total liabilities | | $ | — | | | $ | 9 | | | $ | — | | | $ | 9 | | At December 31, 2013 | | | | | Assets: | | | | | Commodity | | $ | — | | | $ | — | | | $ | 6 | | | $ | 6 | | Interest rate | | | — | | | | 34 | | | | — | | | | 34 | | Total assets | | $ | — | | | $ | 34 | | | $ | 6 | | | $ | 40 | | Liabilities: | | | | | Commodity | | $ | — | | | $ | 13 | | | $ | 12 | | | $ | 25 | | Total liabilities | | $ | — | | | $ | 13 | | | $ | 12 | | | $ | 25 | |
Combined Notes to Consolidated Financial Statements, Continued The following table presents the net change in Dominion Gas’ derivative assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category: | | | | | | | | | | | | | | | | 2014 | | | 2013 | | | 2012 | | | (millions) | | | | | | | | | | Balance at January 1, | | $ | (6 | ) | | $ | (12 | ) | | $ | (98 | ) | Total realized and unrealized gains (losses): | | | | | | | | | | | | | Included in earnings | | | 2 | | | | 1 | | | | (15 | ) | Included in other comprehensive income (loss) | | | 10 | | | | 3 | | | | 86 | | Settlements | | | (4 | ) | | | 2 | | | | 15 | | Balance at December 31, | | $ | 2 | | | $ | (6 | ) | | $ | (12 | ) |
The gains and losses included in earnings in the Level 3 fair value category were classified in operating revenue in Dominion Gas’ Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2014, 2013 and 2012. Fair Value of Financial Instruments Substantially all of Dominion’s and Virginia Power’sthe Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, thatwhich are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, restricted cash (which is recorded in other current assets), customer and other receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For Dominion’s and Virginia Power’sthe Companies’ financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows: | | At December 31, | | 2013 | | | 2012 | | | 2014 | | 2013 | | | | | Carrying
Amount | | | Estimated
Fair Value(1) | | | Carrying
Amount | | | Estimated
Fair Value(1) | | | Carrying
Amount | | Estimated
Fair Value(1) | | Carrying
Amount | | Estimated
Fair Value(1) | | | (millions) | | | | | | | | | | | | | | | | | | | | | | Dominion | | | | | | | | | | | | | | | | | Long-term debt, including securities due within one year(2) | | $ | 18,396 | | | $ | 19,887 | | | $ | 16,841 | | | $ | 19,898 | | | $ | 19,723 | | | $ | 21,881 | | | $ | 18,396 | | | $ | 19,887 | | Long-term debt, including securities due within one year—VIE(3) | | | — | | | | — | | | | 860 | | | | 864 | | | Junior subordinated notes(3) | | | 1,373 | | | | 1,394 | | | | 1,373 | | | | 1,430 | | | | 1,374 | | | | 1,396 | | | | 1,373 | | | | 1,394 | | Remarketable subordinated notes(3) | | | 1,080 | | | | 1,192 | | | | — | | | | — | | | | 2,083 | | | | 2,362 | | | | 1,080 | | | | 1,192 | | Subsidiary preferred stock(4) | | | 257 | | | | 261 | | | | 257 | | | | 255 | | | | — | | | | — | | | | 257 | | | | 261 | | Virginia Power | | | | | | | | | | | | | | | | | Long-term debt, including securities due within one year(2) | | $ | 8,032 | | | $ | 8,897 | | | $ | 6,669 | | | $ | 8,270 | | | Long-term debt, including securities due within one year(3) | | | $ | 8,937 | | | $ | 10,293 | | | $ | 8,032 | | | $ | 8,897 | | Preferred stock(4) | | | 257 | | | | 261 | | | | 257 | | | | 255 | | | | — | | | | — | | | | 257 | | | | 261 | | Dominion Gas | | | | | | | | | | Long-term debt(3) | | | $ | 2,594 | | | $ | 2,672 | | | $ | 1,198 | | | $ | 1,169 | |
| (1) | Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and |
Combined Notes to Consolidated Financial Statements, Continued
| remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value. |
| (2) | Carrying amount includes amounts which represent the unamortized discount andand/or premium. At December 31, 2013,2014, and 2012,2013, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt, of approximately $55$19 million and $93$55 million, respectively. |
| (3) | Carrying amount includes amounts which represent the unamortized discount and/or premium. |
| (4) | Includes deferred issuance expenses of $2 million at December 31, 2013 and 2012.2013. See Note 18 for information about the redemption of preferred stock in 2014. |
NOTE 7. DERIVATIVES AANDND HEDGE ACCOUNTING ACTIVITIES Dominion and Virginia PowerThe Companies are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as currency exchange and interest rate risks of their business operations. The Companies use derivative instruments to manage exposure to these risks, and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes. As discussed in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivatives are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives.
Derivative assets and liabilities are presented gross on Dominion’s and Virginia Power’sthe Companies’ Consolidated Balance Sheets. Dominion’s and Virginia Power’s derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Dominion Gas’ derivative contracts include over-the- counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions. In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and in some cases other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on Dominion’s and Virginia Power’sthe Companies’ Consolidated Balance Sheets, as well as letters of credit and other forms of security, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure.
Combined Notes to Consolidated Financial Statements, Continued DOMINION Balance Sheet Presentation The tables below present Dominion’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting: | | | | December 31, 2013 | | | December 31, 2012 | | | December 31, 2014 | | | December 31, 2013 | | | | | Gross
Amounts of
Recognized
Assets | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Assets | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Assets Presented
in the Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Assets | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Assets
Presented in the
Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Assets | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Assets
Presented in the
Consolidated
Balance Sheet | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 137 | | | $ | — | | | $ | 137 | | | $ | 93 | | | $ | — | | | $ | 93 | | | $ | 24 | | | $ | — | | | $ | 24 | | | $ | 137 | | | $ | — | | | $ | 137 | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 240 | | | | — | | | | 240 | | | | 290 | | | | — | | | | 290 | | | | 382 | | | | — | | | | 382 | | | | 240 | | | | — | | | | 240 | | Exchange | | | 506 | | | | — | | | | 506 | | | | 416 | | | | — | | | | 416 | | | | 298 | | | | — | | | | 298 | | | | 506 | | | | — | | | | 506 | | Total derivatives, subject to a master netting or similar arrangement | | | 883 | | | | — | | | | 883 | | | | 799 | | | | — | | | | 799 | | | | 704 | | | | — | | | | 704 | | | | 883 | | | | — | | | | 883 | | Total derivatives, not subject to a master netting or similar arrangement | | | 7 | | | | — | | | | 7 | | | | 29 | | | | — | | | | 29 | | | | 15 | | | | — | | | | 15 | | | | 7 | | | | — | | | | 7 | | Total(1) | | $ | 890 | | | $ | — | | | $ | 890 | | | $ | 828 | | | $ | — | | | $ | 828 | | | $ | 719 | | | $ | — | | | $ | 719 | | | $ | 890 | | | $ | — | | | $ | 890 | |
(1) | At December 31, 2013, the total derivative asset balance contains $687 million of current assets, which is presented in current derivative assets, in Dominion’s Consolidated Balance Sheet, and $203 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $518 million of current assets, which is presented in current derivative assets in Dominion’s Consolidated Balance Sheet and $310 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | | | | December 31, 2013 | | | | | | | | Gross Amounts Not Offset in the
Consolidated Balance Sheet | | | | | | Gross Amounts Not Offset in the
Consolidated Balance Sheet | | | | | Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Received | | | Net
Amounts | | | Net Amounts of
Assets Presented in
the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Received | | | Net
Amounts | | | (millions) | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 24 | | | $ | 16 | | | $ | — | | | $ | 8 | | | $ | 137 | | | $ | — | | | $ | — | | | $ | 137 | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 382 | | | | 34 | | | | 34 | | | | 314 | | | | 240 | | | | 63 | | | | — | | | | 177 | | Exchange | | | 298 | | | | 298 | | | | — | | | | — | | | | 506 | | | | 505 | | | | — | | | | 1 | | Total | | $ | 704 | | | $ | 348 | | | $ | 34 | | | $ | 322 | | | $ | 883 | | | $ | 568 | | | $ | — | | | $ | 315 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | December 31, 2013 | | | | | Gross
Amounts of
Recognized
Liabilities | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Liabilities | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | (millions) | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 202 | | | $ | — | | | $ | 202 | | | $ | — | | | $ | — | | | $ | — | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 87 | | | | — | | | | 87 | | | | 262 | | | | — | | | | 262 | | Exchange | | | 493 | | | | — | | | | 493 | | | | 838 | | | | — | | | | 838 | | Total derivatives, subject to a master netting or similar arrangement | | | 782 | | | | — | | | | 782 | | | | 1,100 | | | | — | | | | 1,100 | | Total derivatives, not subject to a master netting or similar arrangement | | | 12 | | | | — | | | | 12 | | | | 2 | | | | — | | | | 2 | | Total | | $ | 794 | | | $ | — | | | $ | 794 | | | $ | 1,102 | | | $ | — | | | $ | 1,102 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2013 | | | | | | December 31, 2012 | | | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | Net Amounts of
Assets Presented
in the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Received | | | Net
Amounts | | | Net Amounts of
Assets Presented in
the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash Collateral
Received | | | Net Amounts | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 137 | | | $ | — | | | $ | — | | | $ | 137 | | | $ | 93 | | | $ | 19 | | | $ | — | | | $ | 74 | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 240 | | | | 63 | | | | — | | | | 177 | | | | 290 | | | | 97 | | | | — | | | | 193 | | Exchange | | | 506 | | | | 505 | | | | — | | | | 1 | | | | 416 | | | | 350 | | | | 4 | | | | 62 | | Total | | $ | 883 | | | $ | 568 | | | $ | — | | | $ | 315 | | | $ | 799 | | | $ | 466 | | | $ | 4 | | | $ | 329 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2013 | | | December 31, 2012 | | | | | Gross
Amounts of
Recognized
Liabilities | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Liabilities | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | (millions) | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | — | | | $ | — | | | $ | — | | | $ | 66 | | | $ | — | | | $ | 66 | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 262 | | | | — | | | | 262 | | | | 191 | | | | — | | | | 191 | | Exchange | | | 838 | | | | — | | | | 838 | | | | 393 | | | | — | | | | 393 | | Total derivatives, subject to a master netting or similar arrangement | | | 1,100 | | | | — | | | | 1,100 | | | | 650 | | | | — | | | | 650 | | Total derivatives, not subject to a master netting or similar arrangement | | | 2 | | | | — | | | | 2 | | | | 11 | | | | — | | | | 11 | | Total(1) | | $ | 1,102 | | | $ | — | | | $ | 1,102 | | | $ | 661 | | | $ | — | | | $ | 661 | |
(1) | At December 31, 2013, the total derivative liability balance contains $828 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet, and $274 million of noncurrent liabilities, which is presented in the other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $510 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet and $151 million of noncurrent liabilities, which is presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet. |
| | | | | | | December 31, 2013 | | | | | | December 31, 2012 | | | | | | December 31, 2014 | | | | | | December 31, 2013 | | | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | | Gross Amounts Not Offset
in the Consolidated Balance
Sheet | | | | | | Gross Amounts Not Offset in
the Consolidated Balance
Sheet | | | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Paid | | | Net
Amounts | | | Net Amounts of
Liabilities Presented
in the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash Collateral
Paid | | | Net Amounts | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Paid | | | Net
Amounts | | | Net Amounts of
Liabilities Presented
in the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash Collateral
Paid | | | Net Amounts | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 66 | | | $ | 19 | | | $ | — | | | $ | 47 | | | $ | 202 | | | $ | 16 | | | $ | — | | | $ | 186 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 262 | | | | 63 | | | | 69 | | | | 130 | | | | 191 | | | | 97 | | | | 20 | | | | 74 | | | | 87 | | | | 34 | | | | 1 | | | | 52 | | | | 262 | | | | 63 | | | | 69 | | | | 130 | | Exchange | | | 838 | | | | 505 | | | | 333 | | | | — | | | | 393 | | | | 350 | | | | 43 | | | | — | | | | 493 | | | | 298 | | | | 195 | | | | — | | | | 838 | | | | 505 | | | | 333 | | | | — | | Total | | $ | 1,100 | | | $ | 568 | | | $ | 402 | | | $ | 130 | | | $ | 650 | | | $ | 466 | | | $ | 63 | | | $ | 121 | | | $ | 782 | | | $ | 348 | | | $ | 196 | | | $ | 238 | | | $ | 1,100 | | | $ | 568 | | | $ | 402 | | | $ | 130 | |
Combined Notes to Consolidated Financial Statements, Continued
The following table presents the volume of Dominion’s derivative activity as of December 31, 2013.2014. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions. | | | | Current | | | Noncurrent | | | Current | | | Noncurrent | | Natural Gas (bcf): | | | | | | | | | Fixed price(1) | | | 116 | | | | 19 | | | | 52 | | | | 13 | | Basis(1) | | | 466 | | | | 281 | | | | 227 | | | | 575 | | Electricity (MWh): | | | | | | | | | Fixed price(1) | | | 14,814,767 | | | | 14,935,144 | | | Fixed price | | | | 14,689,432 | | | | 6,148,800 | | FTRs | | | 41,316,345 | | | | 437,384 | | | | 35,786,150 | | | | — | | Capacity (MW) | | | 83,050 | | | | 18,300 | | | | 10,700 | | | | 7,600 | | Liquids (gallons)(2) | | | 151,200,000 | | | | — | | | Liquids (Gals)(2) | | | | 39,984,000 | | | | 1,260,000 | | Interest rate | | $ | 2,050,000,000 | | | $ | 750,000,000 | | | $ | 1,300,000,000 | | | $ | 4,450,000,000 | |
| (2) | Includes NGLs and oil. |
Ineffectiveness and AOCI For the years ended December 31, 2014, 2013 2012 and 2011,2012, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices. The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at December 31, 2013:2014: | | | | AOCI
After-Tax | | Amounts Expected
to be Reclassified
to Earnings during
the next 12
Months After-Tax | | Maximum
Term | | | AOCI
After-Tax | | Amounts Expected to
be Reclassified
to Earnings during
the next 12
Months After-Tax | | Maximum
Term | | | (millions) | | | | | | | | | | | | | | | Commodities: | | | | | | | | | | | | | Gas | | $ | (3 | ) | | $ | (3 | ) | | | 28 months | | | $ | (8 | ) | | $ | (7 | ) | | | 27 months | | Electricity | | | (172 | ) | | | (124 | ) | | | 36 months | | | | 56 | | | | 46 | | | | 24 months | | Other | | | (3 | ) | | | (3 | ) | | | 29 months | | | | — | | | | — | | | | 17 months | | Interest rate | | | (110 | ) | | | (7 | ) | | | 364 months | | | | (226 | ) | | | (6 | ) | | | 384 months | | Total | | $ | (288 | ) | | $ | (137 | ) | | | $ | (178 | ) | | $ | 33 | | |
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.
Combined Notes to Consolidated Financial Statements, Continued Fair Value and Gains and Losses on Derivative Instruments The following tables present the fair values of Dominion’s derivatives and where they are presented in its Consolidated Balance Sheets: | | | | Fair Value - Derivatives
under Hedge
Accounting | | | Fair Value - Derivatives
not under
Hedge
Accounting | | | Total Fair Value | | | Fair Value -
Derivatives
under
Hedge
Accounting | | | Fair Value -
Derivatives
not under
Hedge
Accounting | | | Total
Fair
Value | | | (millions) | | | | | | | | | | | | | | | | | | | At December 31, 2014 | | | | | | | | ASSETS | | | | | | | | Current Assets | | | | | | | | Commodity | | | $ | 281 | | | $ | 242 | | | $ | 523 | | Interest rate | | | | 13 | | | | — | | | | 13 | | Total current derivative assets | | | | 294 | | | | 242 | | | | 536 | | Noncurrent Assets | | | | | | | | Commodity | | | | 71 | | | | 101 | | | | 172 | | Interest rate | | | | 11 | | | | — | | | | 11 | | Total noncurrent derivative assets(1) | | | | 82 | | | | 101 | | | | 183 | | Total derivative assets | | | $ | 376 | | | $ | 343 | | | $ | 719 | | LIABILITIES | | | | | | | | Current Liabilities | | | | | | | | Commodity | | | $ | 224 | | | $ | 267 | | | $ | 491 | | Interest rate | | | | 100 | | | | — | | | | 100 | | Total current derivative liabilities | | | | 324 | | | | 267 | | | | 591 | | Noncurrent Liabilities | | | | | | | | Commodity | | | | 55 | | | | 46 | | | | 101 | | Interest rate | | | | 102 | | | | — | | | | 102 | | Total noncurrent derivative liabilities(2) | | | | 157 | | | | 46 | | | | 203 | | Total derivative liabilities | | | $ | 481 | | | $ | 313 | | | $ | 794 | | At December 31, 2013 | | | | | | | | | | | | | ASSETS | | | | | | | | | | | | | Current Assets | | | | | | | | | | | | | Commodity | | $ | 49 | | | $ | 522 | | | $ | 571 | | | $ | 49 | | | $ | 522 | | | $ | 571 | | Interest rate | | | 116 | | | | — | | | | 116 | | | | 116 | | | | — | | | | 116 | | Total current derivative assets | | | 165 | | | | 522 | | | | 687 | | | | 165 | | | | 522 | | | | 687 | | Noncurrent Assets | | | | | | | | | | | | | Commodity | | | 28 | | | | 154 | | | | 182 | | | | 28 | | | | 154 | | | | 182 | | Interest rate | | | 21 | | | | — | | | | 21 | | | | 21 | | | | — | | | | 21 | | Total noncurrent derivative assets(1) | | | 49 | | | | 154 | | | | 203 | | | | 49 | | | | 154 | | | | 203 | | Total derivative assets | | $ | 214 | | | $ | 676 | | | $ | 890 | | | $ | 214 | | | $ | 676 | | | $ | 890 | | LIABILITIES | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | | | | Commodity | | $ | 267 | | | $ | 561 | | | $ | 828 | | | $ | 267 | | | $ | 561 | | | $ | 828 | | Total current derivative liabilities | | | 267 | | | | 561 | | | | 828 | | | | 267 | | | | 561 | | | | 828 | | Noncurrent Liabilities | | | | | | | | | | | | | Commodity | | | 119 | | | | 155 | | | | 274 | | | | 119 | | | | 155 | | | | 274 | | Total noncurrent derivative liabilities(2) | | | 119 | | | | 155 | | | | 274 | | | | 119 | | | | 155 | | | | 274 | | Total derivative liabilities | | $ | 386 | | | $ | 716 | | | $ | 1,102 | | | $ | 386 | | | $ | 716 | | | $ | 1,102 | | At December 31, 2012 | | | | | | | | ASSETS | | | | | | | | Current Assets | | | | | | | | Commodity | | $ | 103 | | | $ | 379 | | | $ | 482 | | | Interest rate | | | 36 | | | | — | | | | 36 | | | Total current derivative assets | | | 139 | | | | 379 | | | | 518 | | | Noncurrent Assets | | | | | | | | Commodity | | | 130 | | | | 123 | | | | 253 | | | Interest rate | | | 57 | | | | — | | | | 57 | | | Total noncurrent derivative assets(1) | | | 187 | | | | 123 | | | | 310 | | | Total derivative assets | | $ | 326 | | | $ | 502 | | | $ | 828 | | | LIABILITIES | | | | | | | | Current Liabilities | | | | | | | | Commodity | | $ | 103 | | | $ | 341 | | | $ | 444 | | | Interest rate | | | 66 | | | | — | | | | 66 | | | Total current derivative liabilities | | | 169 | | | | 341 | | | | 510 | | | Noncurrent Liabilities | | | | | | | | Commodity | | | 58 | | | | 93 | | | | 151 | | | Total noncurrent derivative liabilities(2) | | | 58 | | | | 93 | | | | 151 | | | Total derivative liabilities | | $ | 227 | | | $ | 434 | | | $ | 661 | | |
| (1) | Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheets. |
| (2) | Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheets. |
The following tables present the gains and losses on Dominion’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income: | Derivatives in cash flow hedging
relationships | | Amount of
Gain (Loss)
Recognized
in AOCI on
Derivatives
(Effective
Portion)(1) | | Amount of
Gain (Loss)
Reclassified
from AOCI
to Income | | Increase
(Decrease) in
Derivatives
Subject to
Regulatory
Treatment(2) | | | Amount of
Gain (Loss)
Recognized
in AOCI on
Derivatives
(Effective
Portion)(1) | | Amount of
Gain (Loss)
Reclassified
from AOCI
to Income | | Increase
(Decrease) in
Derivatives
Subject to
Regulatory
Treatment(2) | | | (millions) | | | | | | | | | | | | | | | | Year Ended December 31, 2014 | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | Commodity: | | | | | | | | Operating revenue | | | | | $ | (130 | ) | | | Purchased gas | | | | | | (13 | ) | | | Electric fuel and other energy-related purchases | | | | 7 | | | Total commodity | | | $ | 245 | | | $ | (136 | ) | | $ | (4 | ) | Interest rate(3) | | | | (208 | ) | | | (16 | ) | | | (81 | ) | Total | | | $ | 37 | | | $ | (152 | ) | | $ | (85 | ) | | Year Ended December 31, 2013 | | | | | | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Operating revenue | | | | $ | (58 | ) | | | | | | $ | (58 | ) | | | Purchased gas | | | | | (47 | ) | | | | | | | (47 | ) | | | Electric fuel and other energy-related purchases | | | | (10 | ) | | | | (10 | ) | | Total commodity | | $ | (481 | ) | | $ | (115 | ) | | $ | 5 | | | $ | (481 | ) | | $ | (115 | ) | | $ | 5 | | Interest rate(3) | | | 77 | | | | (15 | ) | | | 81 | | | | 77 | | | | (15 | ) | | | 81 | | Total | | $ | (404 | ) | | $ | (130 | ) | | $ | 86 | | | $ | (404 | ) | | $ | (130 | ) | | $ | 86 | | | Year Ended December 31, 2012 | | | | | | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Operating revenue | | | | $ | 188 | | | | | | | $ | 188 | | | | Purchased gas | | | | | (75 | ) | | | | | | | (75 | ) | | | Electric fuel and other energy-related purchases | | | | (17 | ) | | | | (17 | ) | | Total commodity | | $ | 71 | | | $ | 96 | | | $ | 10 | | | $ | 71 | | | $ | 96 | | | $ | 10 | | Interest rate(3) | | | (84 | ) | | | (2 | ) | | | (35 | ) | | | (84 | ) | | | (2 | ) | | | (35 | ) | Total | | $ | (13 | ) | | $ | 94 | | | $ | (25 | ) | | $ | (13 | ) | | $ | 94 | | | $ | (25 | ) | | Year Ended December 31, 2011 | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | Commodity: | | | | | | | | Operating revenue | | | | $ | 153 | | | | | Purchased gas | | | | | (78 | ) | | | | Electric fuel and other energy-related purchases | | | | | (2 | ) | | | | Purchased electric capacity | | | | 1 | | | | Total commodity | | $ | 137 | | | $ | 74 | | | $ | (20 | ) | | Interest rate(3) | | | (252 | ) | | | (8 | ) | | | (143 | ) | | Total | | $ | (115 | ) | | $ | 66 | | | $ | (163 | ) | |
| (1) | Amounts deferred into AOCI have no associated effect in Dominion’s Consolidated Statements of Income. |
| (2) | Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income. |
| (3) | Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges. |
| | | | | | | | | | | | | Derivatives not designated as hedging instruments | | Amount of Gain (Loss) Recognized in
Income on Derivatives(1) | | | Year Ended December 31, | | 2014 | | | 2013 | | | 2012 | | | (millions) | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Operating revenue | | $ | (310 | ) | | $ | (45 | ) | | $ | 168 | | Purchased gas | | | (51 | ) | | | (9 | ) | | | (14 | ) | Electric fuel and other energy-related purchases | | | 113 | | | | (29 | ) | | | (40 | ) | Interest rate(2) | | | — | | | | — | | | | 17 | | Total | | $ | (248 | ) | | $ | (83 | ) | | $ | 131 | |
| | | | | | | | | | | | | Derivatives not designated as hedging instruments | | Amount of Gain (Loss) Recognized in
Income on Derivatives(1) | | | Year Ended December 31, | | 2013 | | | 2012 | | | 2011 | | | (millions) | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Operating revenue | | $ | (45 | ) | | $ | 168 | | | $ | 111 | | Purchased gas | | | (9 | ) | | | (14 | ) | | | (35 | ) | Electric fuel and other energy-related purchases | | | (29 | ) | | | (40 | ) | | | (45 | ) | Interest rate(2) | | | — | | | | 17 | | | | (5 | ) | Total | | $ | (83 | ) | | $ | 131 | | | $ | 26 | |
| (1) | Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income. |
| (2) | Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges. |
Combined Notes to Consolidated Financial Statements, Continued
VIRGINIA POWER Balance Sheet Presentation The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting: | | | | December 31, 2013 | | | December 31, 2012 | | | December 31, 2014 | | | December 31, 2013 | | | | | Gross
Amounts of
Recognized
Assets | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Assets | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Assets Presented
in the Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Assets | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Assets | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 48 | | | $ | — | | | $ | 48 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 48 | | | $ | — | | | $ | 48 | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 4 | | | | — | | | | 4 | | | | 6 | | | | — | | | | 6 | | | | 106 | | | | — | | | | 106 | | | | 4 | | | | — | | | | 4 | | Exchange | | | 1 | | | | — | | | | 1 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1 | | | | — | | | | 1 | | Total derivatives, subject to a master netting or similar arrangement | | | 53 | | | | — | | | | 53 | | | | 6 | | | | — | | | | 6 | | | | 106 | | | | — | | | | 106 | | | | 53 | | | | — | | | | 53 | | Total derivatives, not subject to a master netting or similar arrangement | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 7 | | | | — | | | | 7 | | | | — | | | | — | | | | — | | Total(1) | | $ | 53 | | | $ | — | | | $ | 53 | | | $ | 6 | | | $ | — | | | $ | 6 | | | $ | 113 | | | $ | — | | | $ | 113 | | | $ | 53 | | | $ | — | | | $ | 53 | |
(1) | At December 31, 2013, the total derivative asset balance contains $53 million of current assets, which is presented in other current assets in Virginia Power’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $6 million of current assets, which is presented in other current assets in Virginia Power’s Consolidated Balance Sheet. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | | | | | | | December 31, 2013 | | | | | | | | | | | Gross Amounts Not Offset
in the Consolidated Balance
Sheet | | | | | | | | | Gross Amounts Not Offset in
the Consolidated Balance
Sheet | | | | | | | | Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Received | | | Net
Amounts | | | Net Amounts of
Assets Presented in
the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash Collateral
Received | | | Net Amounts | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 48 | | | $ | — | | | $ | — | | | $ | 48 | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 106 | | | | 4 | | | | — | | | | 102 | | | | 4 | | | | 4 | | | | — | | | | — | | Exchange | | | — | | | | — | | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | 1 | | Total | | $ | 106 | | | $ | 4 | | | $ | — | | | $ | 102 | | | $ | 53 | | | $ | 4 | | | $ | — | | | $ | 49 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2013 | | | | | | December 31, 2012 | | | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | Net Amounts of
Assets Presented
in the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Received | | | Net
Amounts | | | Net Amounts of
Assets Presented in
the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash Collateral
Received | | | Net Amounts | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 48 | | | $ | — | | | $ | — | | | $ | 48 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 4 | | | | 4 | | | | — | | | | — | | | | 6 | | | | 3 | | | | — | | | | 3 | | Exchange | | | 1 | | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | — | | | | — | | Total | | $ | 53 | | | $ | 4 | | | $ | — | | | $ | 49 | | | $ | 6 | | | $ | 3 | | | $ | — | | | $ | 3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2013 | | | December 31, 2012 | | | | | Gross
Amounts of
Recognized
Liabilities | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Liabilities | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | (millions) | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | — | | | $ | — | | | $ | — | | | $ | 25 | | | $ | — | | | $ | 25 | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 12 | | | | — | | | | 12 | | | | 7 | | | | — | | | | 7 | | Exchange | | | — | | | | — | | | | — | | | | 2 | | | | — | | | | 2 | | Total derivatives, subject to a master netting or similar arrangement | | | 12 | | | | — | | | | 12 | | | | 34 | | | | — | | | | 34 | | Total derivatives, not subject to a master netting or similar arrangement | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | Total(1) | | $ | 12 | | | $ | — | | | $ | 12 | | | $ | 34 | | | $ | — | | | $ | 34 | |
(1) | At December 31, 2013, the total derivative liability balance contains $12 million of current liabilities, which is presented in current derivative liabilities in Virginia Power’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $33 million of current liabilities, which is presented in current derivative liabilities in Virginia Power’s Consolidated Balance Sheet and $1 million of noncurrent derivative liabilities, which is presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheet. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | December 31, 2013 | | | | | Gross
Amounts of
Recognized
Liabilities | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Liabilities | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | (millions) | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 72 | | | $ | — | | | $ | 72 | | | $ | — | | | $ | — | | | $ | — | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 8 | | | | — | | | | 8 | | | | 12 | | | | — | | | | 12 | | Total derivatives, subject to a master netting or similar arrangement | | | 80 | | | | — | | | | 80 | | | | 12 | | | | — | | | | 12 | | Total derivatives, not subject to a master netting or similar arrangement | | | 7 | | | | — | | | | 7 | | | | — | | | | — | | | | — | | Total | | $ | 87 | | | $ | — | | | $ | 87 | | | $ | 12 | | | $ | — | | | $ | 12 | |
Combined Notes to Consolidated Financial Statements, Continued | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2013 | | | | | | December 31, 2012 | | | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Paid | | | Net
Amounts | | | Net Amounts of
Liabilities Presented
in the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash Collateral
Paid | | | Net Amounts | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 25 | | | $ | — | | | $ | — | | | $ | 25 | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 12 | | | | 4 | | | | 7 | | | | 1 | | | | 7 | | | | 3 | | | | — | | | | 4 | | Exchange | | | — | | | | — | | | | — | | | | — | | | | 2 | | | | — | | | | 2 | | | | — | | Total | | $ | 12 | | | $ | 4 | | | $ | 7 | | | $ | 1 | | | $ | 34 | | | $ | 3 | | | $ | 2 | | | $ | 29 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | | | | | | | December 31, 2013 | | | | | | | | | | | Gross Amounts Not Offset
in the Consolidated Balance
Sheet | | | | | | | | | Gross Amounts Not Offset in the Consolidated Balance
Sheet | | | | | | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Paid | | | Net
Amounts | | | Net Amounts of
Liabilities Presented
in the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash Collateral
Paid | | | Net Amounts | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 72 | | | $ | — | | | $ | — | | | $ | 72 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 8 | | | | 4 | | | | — | | | | 4 | | | | 12 | | | | 4 | | | | 7 | | | | 1 | | Total | | $ | 80 | | | $ | 4 | | | $ | — | | | $ | 76 | | | $ | 12 | | | $ | 4 | | | $ | 7 | | | $ | 1 | |
Volumes The following table presents the volume of Virginia Power’s derivative activity at December 31, 2013.2014. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions. | | | | Current | | | Noncurrent | | | Current | | | Noncurrent | | Natural Gas (bcf): | | | | | | | | | Fixed price | | | 15 | | | | — | | | | 7 | | | | — | | Basis | | | 7 | | | | — | | | | 51 | | | | 493 | | Electricity (MWh): | | | | | | | | | Fixed price | | | 624,800 | | | | — | | | FTRs | | | 39,186,609 | | | | — | | | | 33,709,386 | | | | — | | Capacity (MW) | | | 75,500 | | | | 18,300 | | | | 10,700 | | | | 7,600 | | Interest rate | | $ | 600,000,000 | | | $ | — | | | $ | 550,000,000 | | | $ | 900,000,000 | |
Ineffectiveness For the years ended December 31, 2014, 2013 2012 and 2011,2012, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to the time value of options and changes in the differences between spot prices and forward prices.
Combined Notes to Consolidated Financial Statements, Continued
Fair Value and Gains and Losses on Derivative Instruments The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets: | | | | Fair Value - Derivatives
under Hedge
Accounting | | | Fair Value - Derivatives
not under
Hedge
Accounting | | | Total
Fair
Value | | | Fair Value - Derivatives under Hedge Accounting | | | Fair Value - Derivatives not under Hedge Accounting | | | Total Fair Value | | | (millions) | | | | | | | | | | | | | | | | | | | At December 31, 2014 | | | | | | | | ASSETS | | | | | | | | Current Assets | | | | | | | | Commodity | | | $ | — | | | $ | 51 | | | $ | 51 | | Total current derivative assets(1) | | | | — | | | | 51 | | | | 51 | | Noncurrent Assets | | | | | | | | Commodity | | | | — | | | | 62 | | | | 62 | | Total noncurrent derivative assets(2) | | | | — | | | | 62 | | | | 62 | | Total derivative assets | | | $ | — | | | $ | 113 | | | $ | 113 | | LIABILITIES | | | | | | | | Current Liabilities | | | | | | | | Commodity | | | $ | 3 | | | $ | 12 | | | $ | 15 | | Interest rate | | | | 45 | | | | — | | | | 45 | | Total current derivative liabilities | | | | 48 | | | | 12 | | | | 60 | | Noncurrent Liabilities | | | | | | | | Interest rate | | | | 27 | | | | — | | | | 27 | | Total noncurrent derivative liabilities(3) | | | | 27 | | | | — | | | | 27 | | Total derivative liabilities | | | $ | 75 | | | $ | 12 | | | $ | 87 | | | At December 31, 2013 | | | | | | | | | | | | | | | | ASSETS | | | | | | | | | | | | | Current Assets | | | | | | | | | | | | | Commodity | | $ | 2 | | | $ | 3 | | | $ | 5 | | | $ | 2 | | | $ | 3 | | | $ | 5 | | Interest rate | | | 48 | | | | — | | | | 48 | | | | 48 | | | | — | | | | 48 | | Total current derivative
assets(1) | | | 50 | | | | 3 | | | | 53 | | | | 50 | | | | 3 | | | | 53 | | Total derivative assets | | $ | 50 | | | $ | 3 | | | $ | 53 | | | $ | 50 | | | $ | 3 | | | $ | 53 | | LIABILITIES | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | | | | Commodity | | $ | 1 | | | $ | 11 | | | $ | 12 | | | $ | 1 | | | $ | 11 | | | $ | 12 | | Total current derivative liabilities | | | 1 | | | | 11 | | | | 12 | | | | 1 | | | | 11 | | | | 12 | | Total derivative liabilities | | $ | 1 | | | $ | 11 | | | $ | 12 | | | $ | 1 | | | $ | 11 | | | $ | 12 | | | At December 31, 2012 | | | | | | | | | | | ASSETS | | | | | | | | Current Assets | | | | | | | | Commodity | | $ | 1 | | | $ | 5 | | | $ | 6 | | | Total current derivative
assets(1) | | | 1 | | | | 5 | | | | 6 | | | Total derivative assets | | $ | 1 | | | $ | 5 | | | $ | 6 | | | LIABILITIES | | | | | | | | Current Liabilities | | | | | | | | Commodity | | $ | 5 | | | $ | 3 | | | $ | 8 | | | Interest rate | | | 25 | | | | — | | | | 25 | | | Total current derivative liabilities | | | 30 | | | | 3 | | | | 33 | | | Noncurrent Liabilities | | | | | | | | Commodity | | | 1 | | | | — | | | | 1 | | | Total noncurrent derivative
liabilities(2) | | | 1 | | | | — | | | | 1 | | | Total derivative liabilities | | $ | 31 | | | $ | 3 | | | $ | 34 | | |
| (1) | Current derivative assets are presented in other current assets in Virginia Power’s Consolidated Balance Sheets. |
| (2) | Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Power’s Consolidated Balance Sheets. |
| (3) | Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheets. |
The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income: | | | | | | | | | | | | | Derivatives in cash flow hedging relationships | | Amount of Gain
(Loss)
Recognized in
AOCI on
Derivatives
(Effective
Portion)(1) | | | Amount of
Gain (Loss)
Reclassified
from AOCI to
Income | | | Increase
(Decrease) in
Derivatives
Subject to
Regulatory
Treatment(2) | | | (millions) | | | | | | | | | | | Year Ended December 31, 2013 | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | | | | $ | — | | | | | | Total commodity | | $ | — | | | $ | — | | | $ | 5 | | Interest rate(3) | | | 9 | | | | — | | | | 81 | | Total | | $ | 9 | | | $ | — | | | $ | 86 | | | Year Ended December 31, 2012 | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | | | | $ | (4 | ) | | | | | Total commodity | | $ | (2 | ) | | $ | (4 | ) | | $ | 10 | | Interest rate(3) | | | (6 | ) | | | — | | | | (35 | ) | Total | | $ | (8 | ) | | $ | (4 | ) | | $ | (25 | ) | | Year Ended December 31, 2011 | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | | | | $ | (1 | ) | | | | | Purchased electric capacity | | | | | | | 1 | | | | | | Total commodity | | $ | (3 | ) | | $ | — | | | $ | (20 | ) | Interest rate(3) | | | (6 | ) | | | 1 | | | | (143 | ) | Total | | $ | (9 | ) | | $ | 1 | | | $ | (163 | ) |
| | | | | | | | | | | | | Derivatives in cash flow hedging relationships | | Amount of Gain (Loss) Recognized
in AOCI on Derivatives (Effective Portion)(1) | | | Amount of Gain (Loss) Reclassified from AOCI to Income | | | Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2) | | | (millions) | | | | | | | | | | | Year Ended December 31, 2014 | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | | | | $ | 5 | | | | | | Total commodity | | $ | 4 | | | $ | 5 | | | $ | (4 | ) | Interest rate(3) | | | (10 | ) | | | — | | | | (81 | ) | Total | | $ | (6 | ) | | $ | 5 | | | $ | (85 | ) | | Year Ended December 31, 2013 | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | | | | $ | — | | | | | | Total commodity | | $ | — | | | $ | — | | | $ | 5 | | Interest rate(3) | | | 9 | | | | — | | | | 81 | | Total | | $ | 9 | | | $ | — | | | $ | 86 | | | Year Ended December 31, 2012 | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | Electric fuel and other energy-related purchases | | | | | | $ | (4 | ) | | | | | Total commodity | | $ | (2 | ) | | $ | (4 | ) | | $ | 10 | | Interest rate(3) | | | (6 | ) | | | — | | | | (35 | ) | Total | | $ | (8 | ) | | $ | (4 | ) | | $ | (25 | ) |
| (1) | Amounts deferred into AOCI have no associated effect in Virginia Power’s Consolidated Statements of Income. |
| (2) | Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income. |
| (3) | Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges. |
| Derivatives not designated as hedging instruments | | Amount of Gain (Loss) Recognized
in Income on Derivatives(1) | | | Amount of Gain (Loss) Recognized in
Income on Derivatives(1) | | | Year Ended December 31, | | 2013 | | 2012 | | 2011 | | | 2014 | | | 2013 | | 2012 | | | (millions) | | | | | | | | | | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | | | | | Commodity(2) | | $ | (16 | ) | | $ | (50 | ) | | $ | (45 | ) | | $ | 105 | | | $ | (16 | ) | | $ | (50 | ) | Interest rate(3) | | | — | | | | — | | | | (5 | ) | | Total | | $ | (16 | ) | | $ | (50 | ) | | $ | (50 | ) | | $ | 105 | | | $ | (16 | ) | | $ | (50 | ) |
| (1) | Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income. |
| (2) | Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases. |
DOMINION GAS Balance Sheet Presentation The tables below present Dominion Gas’ derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting: | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | December 31, 2013 | | | | | Gross
Amounts of
Recognized
Assets | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet | | | Gross Amounts of
Recognized
Assets | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Assets Presented in the Consolidated
Balance Sheet | | | (millions) | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | — | | | $ | — | | | $ | — | | | $ | 34 | | | $ | — | | | $ | 34 | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 2 | | | | — | | | | 2 | | | | 6 | | | | — | | | | 6 | | Total derivatives, subject to a master netting or similar arrangement | | $ | 2 | | | $ | — | | | $ | 2 | | | $ | 40 | | | $ | — | | | $ | 40 | |
Combined Notes to Consolidated Financial Statements, Continued | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | | | | | | | December 31, 2013 | | | | | | | | | | | Gross Amounts Not Offset
in the Consolidated Balance Sheet | | | | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | | | | Net Amounts of
Assets Presented
in the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Received | | | Net
Amounts | | | Net Amounts of
Assets Presented in
the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash Collateral
Received | | | Net Amounts | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 34 | | | $ | — | | | $ | — | | | $ | 34 | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | 2 | | | | — | | | | — | | | | 2 | | | | 6 | | | | 6 | | | | — | | | | — | | Total | | $ | 2 | | | $ | — | | | $ | — | | | $ | 2 | | | $ | 40 | | | $ | 6 | | | $ | — | | | $ | 34 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | December 31, 2013 | | | | | Gross
Amounts of
Recognized
Liabilities | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | Gross
Amounts of
Recognized
Liabilities | | | Gross Amounts
Offset in the
Consolidated
Balance Sheet | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | (millions) | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 9 | | | $ | — | | | $ | 9 | | | $ | — | | | $ | — | | | $ | — | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | — | | | | — | | | | — | | | | 25 | | | | — | | | | 25 | | Total derivatives, subject to a master netting or similar arrangement | | $ | 9 | | | $ | — | | | $ | 9 | | | $ | 25 | | | $ | — | | | $ | 25 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | | | | | | | December 31, 2013 | | | | | | | | | | | Gross Amounts Not Offset
in the Consolidated Balance
Sheet | | | | | | | | | Gross Amounts Not Offset in the Consolidated Balance
Sheet | | | | | | | | Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash
Collateral
Paid | | | Net
Amounts | | | Net Amounts of Liabilities Presented
in the Consolidated
Balance Sheet | | | Financial
Instruments | | | Cash Collateral
Paid | | | Net Amounts | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 9 | | | $ | — | | | $ | — | | | $ | 9 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Commodity contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | | — | | | | — | | | | — | | | | — | | | | 25 | | | | 6 | | | | — | | | | 19 | | Total | | $ | 9 | | | $ | — | | | $ | — | | | $ | 9 | | | $ | 25 | | | $ | 6 | | | $ | — | | | $ | 19 | |
Volumes The following table presents the volume of Dominion Gas’ derivative activity at December 31, 2014. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions. | | | | | | | | | | | | Current | | | Noncurrent | | NGLs (Gals) | | | 32,340,000 | | | | — | | Interest rate | | $ | — | | | $ | 250,000,000 | |
Ineffectiveness and AOCI For the years ended December 31, 2014, 2013 and 2012, gains or losses on hedging instruments determined to be ineffective were not material. The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Gas’ Consolidated Balance Sheet at December 31, 2014: | | | | | | | | | | | | | | | | AOCI
After-Tax | | | Amounts Expected
to be Reclassified
to Earnings during
the next 12
Months After-Tax | | | Maximum
Term | | | (millions) | | | | | | | | | | Commodities: | | | | | | | | | | | | | Natural Gas | | $ | — | | | $ | — | | | | 3 months | | NGLs | | | — | | | | — | | | | 12 months | | Interest rate | | | (20 | ) | | | — | | | | 360 months | | Total | | $ | (20 | ) | | $ | — | | | | | |
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.
Fair Value and Gains and Losses on Derivative Instruments The following tables present the fair values of Dominion Gas’ derivatives and where they are presented in its Consolidated Balance Sheets: | | | | | | | | | | | | | | | | Fair Value - Derivatives under Hedge Accounting | | | Fair Value - Derivatives not under Hedge Accounting | | | Total Fair Value | | | (millions) | | | | | | | | | | At December 31, 2014 | | | | | | | | | | | | | ASSETS | | | | | | | | | | | | | Current Assets | | | | | | | | | | | | | Commodity | | $ | 2 | | | $ | — | | | $ | 2 | | Total current derivative assets(1) | | | 2 | | | | — | | | | 2 | | Total derivative assets | | $ | 2 | | | $ | — | | | $ | 2 | | LIABILITIES | | | | | | | | | | | | | Noncurrent Liabilities | | | | | | | | | | | | | Interest rate | | $ | 9 | | | $ | — | | | $ | 9 | | Total noncurrent derivative liabilities(2) | | | 9 | | | | — | | | | 9 | | Total derivative liabilities | | $ | 9 | | | $ | — | | | $ | 9 | | At December 31, 2013 | | | | | | | | | | | | | ASSETS | | | | | | | | | | | | | Current Assets | | | | | | | | | | | | | Commodity | | $ | 6 | | | $ | — | | | $ | 6 | | Interest rate | | | 34 | | | | — | | | | 34 | | Total current derivative assets(1) | | | 40 | | | | — | | | | 40 | | Total derivative assets | | $ | 40 | | | $ | — | | | $ | 40 | | LIABILITIES | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | | | | Commodity | | $ | 25 | | | $ | — | | | $ | 25 | | Total current derivative liabilities(3) | | | 25 | | | | — | | | | 25 | | Total derivative liabilities | | $ | 25 | | | $ | — | | | $ | 25 | |
| (1) | Current derivative assets are presented in other current assets in Dominion Gas’ Consolidated Balance Sheets. |
| (2) | Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Gas’ Consolidated Balance Sheets. |
| (3) | Current derivative liabilities are presented in other current liabilities in Dominion Gas’ Consolidated Balance Sheets. |
The following tables present the gains and losses on Dominion Gas’ derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income: | | | | | | | | | Derivatives in cash flow hedging relationships | | Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1) | | | Amount of Gain (Loss) Reclassified from AOCI to Income | | | (millions) | | | | | | | | Year Ended December 31, 2014 | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | Commodity: | | | | | | | | | Operating revenue | | | | | | $ | 2 | | Purchased gas | | | | | | | (14 | ) | Total commodity | | $ | 12 | | | $ | (12 | ) | Interest rate(2) | | | (62 | ) | | | (1 | ) | Total | | $ | (50 | ) | | $ | (13 | ) | | Year Ended December 31, 2013 | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | Commodity: | | | | | | | | | Operating revenue | | | | | | $ | (2 | ) | Purchased gas | | | | | | | (14 | ) | Total commodity | | $ | (2 | ) | | $ | (16 | ) | Interest rate(2) | | | 68 | | | | — | | Total | | $ | 66 | | | $ | (16 | ) | | Year Ended December 31, 2012 | | | | | | | Derivative Type and Location of Gains (Losses) | | | | | | | | | Commodity: | | | | | | | | | Operating revenue | | | | | | $ | (15 | ) | Purchased gas | | | | | | | (18 | ) | Total commodity | | $ | 64 | | | $ | (33 | ) | Interest rate(2) | | | (41 | ) | | | — | | Total | | $ | 23 | | | $ | (33 | ) |
| (1) | Amounts deferred into AOCI have no associated effect in Dominion Gas’ Consolidated Statements of Income. |
| (2) | Amounts recorded in Virginia Power’sDominion Gas’ Consolidated Statements of Income are classified in interest and related charges. |
NOTE 8. EARNINGS PER SHARE The following table presents the calculation of Dominion’s basic and diluted EPS: | | | | 2013 | | | 2012 | | | 2011 | | | 2014 | | | 2013 | | | 2012 | | | (millions, except EPS) | | | | | | | | | | | | | | | | | | | Net income attributable to Dominion | | $ | 1,697 | | | $ | 302 | | | $ | 1,408 | | | $ | 1,310 | | | $ | 1,697 | | | $ | 302 | | Average shares of common stock outstanding-Basic | | | 578.7 | | | | 572.9 | | | | 573.1 | | | | 582.7 | | | | 578.7 | | | | 572.9 | | Net effect of dilutive securities(1) | | | 0.8 | | | | 1.0 | | | | 1.5 | | | | 1.8 | | | | 0.8 | | | | 1.0 | | Average shares of common stock outstanding-Diluted | | | 579.5 | | | | 573.9 | | | | 574.6 | | | | 584.5 | | | | 579.5 | | | | 573.9 | | Earnings Per Common Share-Basic | | $ | 2.93 | | | $ | 0.53 | | | $ | 2.46 | | | $ | 2.25 | | | $ | 2.93 | | | $ | 0.53 | | Earnings Per Common Share-Diluted | | $ | 2.93 | | | $ | 0.53 | | | $ | 2.45 | | | $ | 2.24 | | | $ | 2.93 | | | $ | 0.53 | |
| (1) | Dilutive securities consist primarily of contingently convertible senior notes.notes and the 2013 Equity Units for 2014 and contingently convertible senior notes for 2013 and 2012. Dominion redeemed all of its contingently convertible senior notes in 2014. See Note 17 for more information. |
Dominion’s 2013 Series AThe 2014 Equity Units andare potentially dilutive securities but were excluded from the calculation of diluted EPS for the year ended December 31, 2014, as the dilutive stock price threshold was not met. The 2013 Series B Equity Units issued in June 2013 are potentially dilutive securities but were excluded from the calculation of diluted EPS for the year ended December 31, 2013. See Note 17 for more information. There were no potentially dilutive securities excluded from the calculation of diluted EPS for the yearsyear ended December 31, 2012 and 2011.2012.
Combined Notes to Consolidated Financial Statements, Continued NOTE 9. INVESTMENTS DOMINION Equity and Debt Securities RABBI TRUST SECURITIES Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled $107$110 million and $95$107 million at December 31, 20132014 and 2012,2013, respectively. Cost-method investments held in Dominion’s rabbi trusts totaled $10$6 million and $14$10 million at December 31, 20132014 and 2012,2013, respectively. DECOMMISSIONING TRUST SECURITIES Dominion holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below: | | | | Amortized
Cost | | | Total
Unrealized
Gains(1) | | | Total
Unrealized
Losses(1) | | Fair
Value | | | Amortized Cost | | | Total Unrealized Gains(1) | | | Total Unrealized Losses(1) | | Fair Value | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | 2014 | | | | | | | | | | Marketable equity securities: | | | | | | | | | | U.S. large cap | | | $ | 1,273 | | | $ | 1,353 | | | $ | — | | | $ | 2,626 | | Marketable debt securities: | | | | | | | | | | Corporate debt instruments | | | | 424 | | | | 19 | | | | (2 | ) | | | 441 | | U.S. Treasury securities and agency debentures | | | | 597 | | | | 13 | | | | (4 | ) | | | 606 | | State and municipal | | | | 332 | | | | 23 | | | | — | | | | 355 | | Other | | | | 66 | | | | — | | | | — | | | | 66 | | Cost method investments | | | | 86 | | | | — | | | | — | | | | 86 | | Cash equivalents and other(2) | | | | 16 | | | | — | | | | — | | | | 16 | | Total | | | $ | 2,794 | | | $ | 1,408 | | | $ | (6 | )(3) | | $ | 4,196 | | 2013 | | | | | | | | | | | | | | | | | Marketable equity securities: | | | | | | | | | | | | | | | | | U.S.: | | | | | | | | | | | | | | | | | Large Cap | | $ | 1,183 | | | $ | 1,194 | | | $ | — | | | $ | 2,377 | | | $ | 1,183 | | | $ | 1,194 | | | $ | — | | | $ | 2,377 | | Other | | | 49 | | | | 23 | | | | — | | | | 72 | | | | 49 | | | | 23 | | | | — | | | | 72 | | Marketable debt securities: | | | | | | | | | | | | | | | | | Corporate debt instruments | | | 332 | | | | 16 | | | | (3 | ) | | | 345 | | | | 332 | | | | 16 | | | | (3 | ) | | | 345 | | U.S. Treasury securities and agency debentures | | | 589 | | | | 8 | | | | (10 | ) | | | 587 | | | | 589 | | | | 8 | | | | (10 | ) | | | 587 | | State and municipal | | | 297 | | | | 11 | | | | (5 | ) | | | 303 | | | | 297 | | | | 11 | | | | (5 | ) | | | 303 | | Other | | | 3 | | | | — | | | | — | | | | 3 | | | | 3 | | | | — | | | | — | | | | 3 | | Cost method investments | | | 106 | | | | — | | | | — | | | | 106 | | | | 106 | | | | — | | | | — | | | | 106 | | Cash equivalents and other(2) | | | 110 | | | | — | | | | — | | | | 110 | | | | 110 | | | | — | | | | — | | | | 110 | | Total | | $ | 2,669 | | | $ | 1,252 | | | $ | (18 | )(3) | | $ | 3,903 | | | $ | 2,669 | | | $ | 1,252 | | | $ | (18 | )(3) | | $ | 3,903 | | 2012 | | | | | | | | | | Marketable equity securities: | | | | | | | | | | U.S.: | | | | | | | | | | Large Cap | | $ | 1,210 | | | $ | 732 | | | $ | — | | | $ | 1,942 | | | Other | | | 40 | | | | 13 | | | | — | | | | 53 | | | Marketable debt securities: | | | | | | | | | | Corporate debt instruments | | | 295 | | | | 30 | | | | — | | | | 325 | | | U.S. Treasury securities and agency debentures | | | 523 | | | | 19 | | | | (2 | ) | | | 540 | | | State and municipal | | | 248 | | | | 26 | | | | — | | | | 274 | | | Other | | | 6 | | | | 1 | | | | — | | | | 7 | | | Cost method investments | | | 117 | | | | — | | | | — | | | | 117 | | | Cash equivalents and other(2) | | | 72 | | | | — | | | | — | | | | 72 | | | Total | | $ | 2,511 | | | $ | 821 | | | $ | (2 | )(3) | | $ | 3,330 | | |
| (1) | Included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
| (2) | Includes pending sales of securities of $11$3 million and pending purchases of securities of $6$11 million at December 31, 20132014 and 2012,2013, respectively. |
| (3) | The fair value of securities in an unrealized loss position was $604$379 million and $195$604 million at December 31, 20132014 and 2012,2013, respectively. |
Combined Notes to Consolidated Financial Statements, Continued
The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at December 31, 20132014 by contractual maturity is as follows: | | | | Amount | | | Amount | | | (millions) | | | | | | | Due in one year or less | | $ | 128 | | | $ | 169 | | Due after one year through five years | | | 357 | | | | 390 | | Due after five years through ten years | | | 362 | | | | 426 | | Due after ten years | | | 391 | | | | 483 | | Total | | $ | 1,238 | | | $ | 1,468 | |
Presented below is selected information regarding Dominion’s marketable equity and debt securities held in nuclear decommissioning trust funds: | | Year Ended December 31, | | 2013 | | | 2012 | | | 2011 | | | 2014 | | | 2013 | | | 2012 | | | (millions) | | | | | | | | | | | | | | | | | | | Proceeds from sales | | $ | 1,476 | | | $ | 1,356 | | | $ | 1,757 | | | $ | 1,235 | | | $ | 1,476 | | | $ | 1,356 | | Realized gains(1) | | | 157 | | | | 98 | | | | 79 | | | | 171 | | | | 157 | | | | 98 | | Realized losses(1) | | | 33 | | | | 33 | | | | 92 | | | | 30 | | | | 33 | | | | 33 | |
| (1) | Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows: | | Year Ended December 31, | | 2013 | | 2012 | | 2011 | | | 2014 | | 2013 | | 2012 | | | (millions) | | | | | | | | | | | | | | | Total other-than-temporary impairment losses(1) | | $ | 31 | | | $ | 26 | | | $ | 75 | | | $ | 21 | | | $ | 31 | | | $ | 26 | | Losses recorded to decommissioning trust regulatory liability | | | (13 | ) | | | (10 | ) | | | (24 | ) | | Losses recorded to nuclear decommissioning trust regulatory liability | | | | (5 | ) | | | (13 | ) | | | (10 | ) | Losses recognized in other comprehensive income (before taxes) | | | (10 | ) | | | (2 | ) | | | (3 | ) | | | (3 | ) | | | (10 | ) | | | (2 | ) | Net impairment losses recognized in earnings | | $ | 8 | | | $ | 14 | | | $ | 48 | | | $ | 13 | | | $ | 8 | | | $ | 14 | |
| (1) | Amounts include other-than-temporary impairment losses for debt securities of $3 million, $18 million $4 million and $6$4 million at December 31, 2014, 2013 2012 and 2011,2012, respectively. |
Equity Method Investments
Investments that Dominion accounts for under the equity method of accounting are as follows:
| | | | | | | | | | | | | | | | Company | | Ownership% | | | Investment
Balance | | | Description | | As of December 31, | | | | | 2013 | | | 2012 | | | | | (millions) | | | | | | | | | | | | Blue Racer Midstream LLC | | | 50 | % | | $ | 510 | | | $ | 39 | | | Midstream gas and
related services | Fowler I Holdings LLC | | | 50 | % | | | 149 | | | | 158 | | | Wind-powered merchant
generation facility | NedPower Mount Storm LLC | | | 50 | % | | | 131 | | | | 137 | | | Wind-powered merchant
generation facility | Iroquois Gas Transmission System, LP | | | 24.72 | % | | | 105 | | | | 102 | | | Gas transmission
system | Elwood Energy LLC(1) | | | — | % | | | — | | | | 117 | | | Natural gas-fired
merchant generation
peaking facility | Other(2) | | | various | | | | 21 | | | | 5 | | | | Total | | | | | | $ | 916 | | | $ | 558 | | | |
(1) | Following the 2013 sale of Elwood, at December 31, 2013, Dominion retained a 0.5% cost method investment. At December 31, 2012, Dominion owned 50% and Elwood was therefore considered an equity method investment. |
(2) | Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018. |
Dominion’s equity earnings on these investments totaled $14 million, $25 million and $35 million in 2013, 2012 and 2011, respectively. Dominion received distributions from these investments of $33 million, $58 million and $55 million in 2013, 2012, and 2011, respectively. As of December 31, 2013 and 2012, the carrying amount of Dominion’s investments exceeded Dominion’s share of underlying equity in net assets by approximately $36 million and $30 million, respectively. $28 million of the differences relate to Dominion’s investments in wind projects and primarily reflect its capitalized interest during construction and the excess of its cash contributions over the book value of development assets contributed by Dominion’s partners for these projects, which are being amortized over the useful lives of the underlying assets. The remaining $8 million of differences reflect equity method goodwill and are not being amortized.
BLUE RACER
In December 2012, Dominion formed a joint venture with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. The joint venture, Blue Racer, is an equal partnership between Dominion and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital. In return for its December 2012 contribution of assets to the joint venture, Dominion received a 50% interest in Blue Racer and received $115 million in cash proceeds, resulting in a gain of $72 million ($43 million after-tax), net of transaction fees of $9 million, which is recorded in other operations and maintenance expense in Dominion’s Consolidated Statement of Income.
In March 2013, Dominion sold Line TL-404 to Blue Racer and received approximately $47 million in cash proceeds resulting in an approximately $25 million ($14 million after-tax) gain. Phase 1 of the Natrium natural gas processing and fractionation facility was completed in the second quarter of 2013 and was contributed to Blue Racer in the third quarter of 2013, resulting in an increased equity method investment in Blue Racer of $473 million. Also in the third quarter of 2013, Dominion sold Line TPL-2A and Line TL-388 to Blue Racer and received approximately $83 million in cash proceeds resulting in an approximately $75 million ($42 million after-tax) gain. In the fourth quarter of 2013, Dominion sold the Western System to Blue Racer for $30 million in cash proceeds resulting in an approximately $4 million ($2 million after-tax) gain. Dominion NGL Pipelines, LLC was contributed in January 2014 to Blue Racer prior to commencement of service, resulting in an increased equity method investment of $155 million.
The joint venture is leveraging Dominion’s existing presence in the Utica region with significant additional new capacity designed to meet producer needs as the Utica Shale acreage is developed. Midstream services offered include gathering, processing, fractionation, and NGL transportation and marketing. In addition to the assets already sold or contributed, Dominion expects to sell additional East Ohio gathering assets to Blue Racer.
VIRGINIA POWER Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below: | | | | Amortized
Cost | | | Total
Unrealized
Gains(1) | | | Total
Unrealized
Losses(1) | | Fair
Value | | | Amortized Cost | | | Total Unrealized Gains(1) | | | Total Unrealized Losses(1) | | Fair Value | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | 2014 | | | | | | | | | | Marketable equity securities: | | | | | | | | | | U.S. large cap | | | $ | 563 | | | $ | 594 | | | $ | — | | | $ | 1,157 | | Marketable debt securities: | | | | | | | | | | Corporate debt instruments | | | | 242 | | | | 9 | | | | (1 | ) | | | 250 | | U.S. Treasury securities and agency debentures | | | | 197 | | | | 3 | | | | (2 | ) | | | 198 | | State and municipal | | | | 197 | | | | 13 | | | | — | | | | 210 | | Other | | | | 23 | | | | — | | | | — | | | | 23 | | Cost method investments | | | | 86 | | | | — | | | | — | | | | 86 | | Cash equivalents and other(2) | | | | 6 | | | | — | | | | — | | | | 6 | | Total | | | $ | 1,314 | | | $ | 619 | | | $ | (3 | )(3) | | $ | 1,930 | | 2013 | | | | | | | | | | | | | | | | | Marketable equity securities: | | | | | | | | | | | | | | | | | U.S.: | | | | | | | | | | | | | | | | | Large Cap | | $ | 506 | | | $ | 514 | | | $ | — | | | $ | 1,020 | | | $ | 506 | | | $ | 514 | | | $ | — | | | $ | 1,020 | | Other | | | 25 | | | | 11 | | | | — | | | | 36 | | | | 25 | | | | 11 | | | | — | | | | 36 | | Marketable debt securities: | | | | | | | | | | | | | | | | | Corporate debt instruments | | | 185 | | | | 8 | | | | (2 | ) | | | 191 | | | | 185 | | | | 8 | | | | (2 | ) | | | 191 | | U.S. Treasury securities and agency debentures | | | 214 | | | | 1 | | | | (3 | ) | | | 212 | | | | 214 | | | | 1 | | | | (3 | ) | | | 212 | | State and municipal | | | 163 | | | | 4 | | | | (4 | ) | | | 163 | | | | 163 | | | | 4 | | | | (4 | ) | | | 163 | | Cost method investments | | | 106 | | | | — | | | | — | | | | 106 | | | | 106 | | | | — | | | | — | | | | 106 | | Cash equivalents and other(2) | | | 37 | | | | — | | | | — | | | | 37 | | | | 37 | | | | — | | | | — | | | | 37 | | Total | | $ | 1,236 | | | $ | 538 | | | $ | (9 | )(3) | | $ | 1,765 | | | $ | 1,236 | | | $ | 538 | | | $ | (9 | )(3) | | $ | 1,765 | | 2012 | | | | | | | | | | Marketable equity securities: | | | | | | | | | | U.S.: | | | | | | | | | | Large Cap | | $ | 481 | | | $ | 298 | | | $ | — | | | $ | 779 | | | Other | | | 20 | | | | 7 | | | | — | | | | 27 | | | Marketable debt securities: | | | | | | | | | | Corporate debt instruments | | | 179 | | | | 17 | | | | — | | | | 196 | | | U.S. Treasury securities and agency debentures | | | 231 | | | | 4 | | | | (1 | ) | | | 234 | | | State and municipal | | | 106 | | | | 11 | | | | — | | | | 117 | | | Other | | | 1 | | | | — | | | | — | | | | 1 | | | Cost method investments | | | 117 | | | | — | | | | — | | | | 117 | | | Cash equivalents and other(2) | | | 44 | | | | — | | | | — | | | | 44 | | | Total | | $ | 1,179 | | | $ | 337 | | | $ | (1 | )(3) | | $ | 1,515 | | |
| (1) | Included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
| (2) | Includes pending sales of securities of $6 million at December 31, 20132014 and 2012.2013. |
| (3) | The fair value of securities in an unrealized loss position was $299$170 million and $104$299 million at December 31, 20132014 and 2012,2013, respectively. |
The fair value of Virginia Power’s marketable debt securities at December 31, 2013,2014, by contractual maturity is as follows: | | | | Amount | | | Amount | | | (millions) | | | | | | | Due in one year or less | | $ | 31 | | | $ | 40 | | Due after one year through five years | | | 163 | | | | 180 | | Due after five years through ten years | | | 196 | | | | 242 | | Due after ten years | | | 176 | | | | 219 | | Total | | $ | 566 | | | $ | 681 | |
Presented below is selected information regarding Virginia Power’s marketable equity and debt securities. | | Year Ended December 31, | | 2013 | | | 2012 | | | 2011 | | | 2014 | | | 2013 | | | 2012 | | | (millions) | | | | | | | | | | | | | | | | | | | Proceeds from sales | | $ | 572 | | | $ | 626 | | | $ | 1,030 | | | $ | 549 | | | $ | 572 | | | $ | 626 | | Realized gains(1) | | | 52 | | | | 42 | | | | 34 | | | | 73 | | | | 52 | | | | 42 | | Realized losses(1) | | | 14 | | | | 11 | | | | 34 | | | | 12 | | | | 14 | | | | 11 | |
| (1) | Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
Virginia Power recorded other-than-temporary impairment losses on investments as follows: | | Year Ended December 31, | | 2013 | | 2012 | | 2011 | | | 2014 | | 2013 | | 2012 | | | (millions) | | | | | | | | | | | | | | | Total other-than-temporary impairment losses(1) | | $ | 15 | | | $ | 11 | | | $ | 29 | | | $ | 8 | | | $ | 15 | | | $ | 11 | | Losses recorded to decommissioning trust regulatory liability | | | (13 | ) | | | (10 | ) | | | (24 | ) | | Losses recorded to nuclear decommissioning trust regulatory liability | | | | (4 | ) | | | (13 | ) | | | (10 | ) | Losses recorded in other comprehensive income (before taxes) | | | (1 | ) | | | — | | | | (1 | ) | | | (2 | ) | | | (1 | ) | | | — | | Net impairment losses recognized in earnings | | $ | 1 | | | $ | 1 | | | $ | 4 | | | $ | 2 | | | $ | 1 | | | $ | 1 | |
| (1) | Amounts include other-than-temporary impairment losses for debt securities of $2 million, $9 million $2 million and $4$2 million at December 31, 2014, 2013 2012 and 2011,2012, respectively. |
OETHERQUITY METHOD INVESTMENTS
Dominion and Virginia Power hold restricted cashDominion Gas Investments that Dominion and cash equivalent balances that primarily consistDominion Gas account for under the equity method of money market fund investments held in trust for the purpose of funding certain qualifying construction projects. At December 31, 2013 and 2012, Dominion had $11 million and $37 million, respectively, and Virginia Power had $8 million and $10 million, respectively, of restricted cash and cash equivalents. These balancesaccounting are presented in Other Current Assets and Other Investments in the Consolidated Balance Sheets.as follows: | | | | | | | | | | | | | | | | Company | | Ownership% | | | Investment
Balance | | | Description | | As of December 31, | | | | | 2014 | | | 2013 | | | | | (millions) | | | | | | | | | | | | Dominion | | | | | | | | | | | | | | | Blue Racer Midstream, LLC | | | 50 | % | | $ | 671 | | | $ | 510 | | | Midstream gas and
related services | Fowler I Holdings LLC | | | 50 | % | | | 134 | | | | 149 | | | Wind-powered merchant
generation facility | NedPower Mount Storm LLC | | | 50 | % | | | 128 | | | | 131 | | | Wind-powered merchant
generation facility | Iroquois Gas Transmission System, LP | | | 24.72 | % | | | 107 | | | | 105 | | | Gas transmission system | Other(1) | | | various | | | | 41 | | | | 21 | | | | Total | | | | | | $ | 1,081 | | | $ | 916 | | | | Dominion Gas | | | | | | | | | | | | | | | Iroquois Gas Transmission System, LP | | | 24.72 | % | | $ | 107 | | | $ | 105 | | | Gas transmission system | Total | | | | | | $ | 107 | | | $ | 105 | | | |
| (1) | Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018. Includes Dominion’s investment in Atlantic Coast Pipeline. See Note 15 for more information. |
Combined Notes to Consolidated Financial Statements, Continued Dominion’s equity earnings on its investments totaled $46 million, $14 million and $25 million in 2014, 2013 and 2012, respectively. Dominion received distributions from these investments of $60 million, $33 million and $58 million in 2014, 2013, and 2012, respectively. As of December 31, 2014 and 2013, the carrying amount of Dominion’s investments exceeded its share of underlying equity in net assets by approximately $126 million and $36 million, respectively. $87 million of the differences relate to basis differences from Dominion’s investments in Blue Racer and wind projects, which are being amortized over the useful lives of the underlying assets. The remaining $39 million of differences reflect equity method goodwill and are not being amortized. Dominion Gas’ equity earnings on its investment totaled $21 million, $22 million and $23 million in 2014, 2013 and 2012, respectively. Dominion Gas received distributions from its investment of $20 million, $19 million and $25 million in 2014, 2013, and 2012, respectively. As of December 31, 2014 and 2013, the carrying amount of Dominion Gas’ investment exceeded its share of underlying equity in net assets by approximately $8 million. The differences reflect equity method goodwill and are not being amortized. Equity earnings are recorded in other income in Dominion’s and Dominion Gas’ Consolidated Statements of Income. BLUE RACER In December 2012, Dominion formed a joint venture with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. Blue Racer is an equal partnership between Dominion and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital. In December 2012, East Ohio sold two pipeline systems to an affiliate who then contributed those systems to Blue Racer. East Ohio received consideration of $248 million, consisting of $61 million in cash proceeds and the extinguishment of affiliated long term debt of $187 million. The transaction resulted in a gain of approximately $176 million ($110 million after-tax) that is recognized in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. Dominion recorded a 50% interest in Blue Racer and cash proceeds of $115 million for the contribution of the assets to the joint venture. Dominion recognized a gain of $72 million ($43 million after-tax), net of transaction fees of $9 million, which is recorded in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. In March 2013, DTI sold Line TL-404 to an affiliate, that subsequently sold line TL-404 to Blue Racer for cash proceeds of approximately $47 million. The sale resulted in a gain of approximately $25 million ($14 million after-tax) net of a $2 million write-off of goodwill, and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statements of Income. Phase 1 of Natrium was completed in the second quarter of 2013 and was contributed by Dominion to Blue Racer in the third quarter of 2013, resulting in an increased equity method investment in Blue Racer of $473 million. Also in the third quarter of 2013, DTI sold Line TPL-2A to an affiliate, that subsequently sold Line TPL-2A to Blue Racer, and sold LineTL-388 to Blue Racer and received approximately $78 million in cash proceeds. The sales resulted in an approximately $74 million ($41 million after-tax) gain which is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statements of Income. In the fourth quarter of 2013, DTI sold the Western System to an affiliate, that subsequently sold the Western System to Blue Racer for cash proceeds of approximately $30 million. The sale resulted in a gain of approximately $3 million ($2 million after-tax) for DTI and $4 million ($2 million after-tax) for Dominion and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statement of Income. Dominion NGL Pipelines, LLC was contributed in January 2014 by Dominion to Blue Racer, prior to commencement of service, resulting in an increased equity method investment of $155 million, including $6 million of goodwill allocated from Dominion’s goodwill balance to its equity method investment in Blue Racer. In March 2014, Dominion Gas sold the Northern System to an affiliate, that subsequently sold the Northern System to Blue Racer for consideration of approximately $84 million. Dominion Gas’ consideration consisted of $17 million in cash proceeds and the extinguishment of affiliated current borrowings of $67 million and Dominion’s consideration consisted of cash proceeds of approximately $84 million. The sale resulted in a gain of approximately $59 million ($35 million after-tax for Dominion Gas and $34 million after-tax for Dominion) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statement of Income. Dominion ATLANTIC COAST PIPELINE In September 2014, Dominion, along with Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc., announced the formation of Atlantic Coast Pipeline. The members, which are subsidiaries of the above-referenced parent companies, hold the following membership interests: Dominion, 45%; Duke Energy Corporation, 40%; Piedmont Natural Gas Company, Inc., 10%; and AGL Resources Inc., 5%. Atlantic Coast Pipeline is focused on constructing an approximately 550-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Subsidiaries and affiliates of all four members plan to be customers of the pipeline under 20-year contracts, pending regulatory approvals. PSNC Energy also plans to be a customer of the pipeline under a 20-year contract, pending regulatory approvals. Atlantic Coast Pipeline is considered an equity method investment as Dominion has the ability to exercise significant influence, but not control, over the investee. See Note 15 for more information.
NOTE 10. PROPERTY, PLANTAND EQUIPMENT Major classes of property, plant and equipment and their respective balances for the Companies are as follows: | | At December 31, | | 2013 | | | 2012 | | | 2014 | | | 2013 | | | (millions) | | | | | | | | | | | | | Dominion | | | | | | | | | Utility: | | | | | | | | | Generation | | $ | 14,018 | | | $ | 13,707 | | | $ | 15,193 | | | $ | 14,018 | | Transmission | | | 8,686 | | | | 7,799 | | | | 9,897 | | | | 8,686 | | Distribution | | | 11,714 | | | | 11,071 | | | | 12,354 | | | | 11,714 | | Storage | | | 2,190 | | | | 2,137 | | | | 2,350 | | | | 2,190 | | Nuclear fuel | | | 1,375 | | | | 1,277 | | | | 1,411 | | | | 1,375 | | Gas gathering and processing | | | 787 | | | | 803 | | | | 791 | | | | 787 | | General and other | | | 812 | | | | 803 | | | | 845 | | | | 812 | | Other-including plant under construction | | | 3,261 | | | | 2,232 | | | | 3,633 | | | | 3,261 | | Total utility | | | 42,843 | | | | 39,829 | | | | 46,474 | | | | 42,843 | | Nonutility: | | | | | | | | | Merchant generation—nuclear | | | 1,153 | | | | 1,163 | | | Merchant generation—other(1) | | | 1,328 | | | | 1,289 | | | Merchant generation-nuclear | | | | 1,267 | | | | 1,153 | | Merchant generation-other | | | | 2,023 | | | | 1,328 | | Nuclear fuel | | | 770 | | | | 775 | | | | 860 | | | | 770 | | Other-including plant under construction | | | 875 | | | | 1,265 | | | | 782 | | | | 875 | | Total nonutility | | | 4,126 | | | | 4,492 | | | | 4,932 | | | | 4,126 | | Total property, plant and equipment | | $ | 46,969 | | | $ | 44,321 | | | $ | 51,406 | | | $ | 46,969 | | | Virginia Power | | | | | | | | | Utility: | | | | | | | | | Generation | | $ | 14,018 | | | $ | 13,707 | | | $ | 15,193 | | | $ | 14,018 | | Transmission | | | 4,959 | | | | 4,261 | | | | 5,884 | | | | 4,959 | | Distribution | | | 9,103 | | | | 8,701 | | | | 9,526 | | | | 9,103 | | Nuclear fuel | | | 1,375 | | | | 1,277 | | | | 1,411 | | | | 1,375 | | General and other | | | 668 | | | | 659 | | | | 697 | | | | 668 | | Other-including plant under construction | | | 2,719 | | | | 2,017 | | | | 2,464 | | | | 2,719 | | Total utility | | | 32,842 | | | | 30,622 | | | | 35,175 | | | | 32,842 | | Nonutility-other | | | 6 | | | | 9 | | | | 5 | | | | 6 | | Total property, plant and equipment | | $ | 32,848 | | | $ | 30,631 | | | $ | 35,180 | | | $ | 32,848 | | | Dominion Gas | | | | | | Utility: | | | | | | Transmission | | | $ | 3,690 | | | $ | 3,407 | | Distribution | | | | 2,530 | | | | 2,333 | | Storage | | | | 1,466 | | | | 1,314 | | Gas gathering and processing | | | | 786 | | | | 783 | | General and other | | | | 111 | | | | 103 | | Plant under construction | | | | 179 | | | | 175 | | Total utility | | | | 8,762 | | | | 8,115 | | Nonutility: | | | | | | E&P properties being amortized and other | | | | 140 | | | | 125 | | Total nonutility | | | | 140 | | | | 125 | | Total property, plant and equipment | | | $ | 8,902 | | | $ | 8,240 | |
There were no significant E&P properties under development, as defined by the SEC, excluded from Dominion Gas’ amortization at December 31, 2014. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation. (1) | 2012 amount includes $957 million due to consolidation of a VIE. See Note 15 for further information. |
Jointly-Owned Power Stations Dominion’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 20132014 is as follows: | | | | Bath
County
Pumped
Storage
Station(1) | | North
Anna
Units 1
and 2(1) | | Clover
Power
Station(1) | | Millstone
Unit 3(2) | | | Bath County Pumped Storage Station(1) | | North Anna
Units 1
and 2(1) | | Clover Power Station(1) | | Millstone Unit 3(2) | | | (millions, except percentages) | | | | | | | | | | | | | | | | | | | Ownership interest | | | 60 | % | | | 88.4 | % | | | 50 | % | | | 93.5 | % | | | 60 | % | | | 88.4 | % | | | 50 | % | | | 93.5 | % | Plant in service | | $ | 1,038 | | | $ | 2,486 | | | $ | 568 | | | $ | 1,007 | | | $ | 1,039 | | | $ | 2,426 | | | $ | 573 | | | $ | 1,104 | | Accumulated depreciation | | | (536 | ) | | | (1,109 | ) | | | (199 | ) | | | (262 | ) | | | (542 | ) | | | (1,137 | ) | | | (206 | ) | | | (290 | ) | Nuclear fuel | | | — | | | | 597 | | | | — | | | | 388 | | | | — | | | | 627 | | | | — | | | | 480 | | Accumulated amortization of nuclear fuel | | | — | | | | (434 | ) | | | — | | | | (283 | ) | | | — | | | | (486 | ) | | | — | | | | (342 | ) | Plant under construction | | | 23 | | | | 76 | | | | 6 | | | | 69 | | | | 11 | | | | 114 | | | | 11 | | | | 71 | |
| (1) | Units jointly owned by Virginia Power. |
| (2) | Unit jointly owned by Dominion. |
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income. AssignmentAssignments of Marcellus Acreage
In December 2013, DTI closed on agreements with two natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. The agreements provide for payments to DTI, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013, DominionDTI received approximately $100 million in cash proceeds, resulting in an approximately $20 million ($12 million-after tax)million after-tax) gain, recorded to operations and approximately $80maintenance expense in Dominion Gas’ Consolidated Statements of Income. During the twelve months ended December 31, 2014, DTI received $16 million in additional cash proceeds resulting from post-closing adjustments. At December 31, 2014, deferred revenue totaled approximately $85 million, which willis expected to be recognized over the remaining termsterm of the agreements.agreement. In November 2014, DTI closed an agreement with a natural gas producer to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provides for payments to DTI, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas produced from the acreage. In November 2014, DTI closed on the agreement and received proceeds of approximately $60 million associated with an initial conveyance of approximately 12,000 acres, resulting in an approximately $60 million ($36 million after-tax) gain, recorded to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. In November 2014, DTI signed an agreement with a natural gas producer to convey approximately 11,000 acres of Marcellus
Combined Notes to Consolidated Financial Statements, Continued Shale development rights underneath one of its natural gas storage fields. The agreement provides for a payment to DTI, subject to customary adjustments, of approximately $27 million, and an overriding royalty interest in gas produced from the acreage. DTI expects to close on the agreement in March 2015. NOTE 11. GOODWILLAND INTANGIBLE ASSETS Goodwill The changes in Dominion’s and Dominion Gas’ carrying amount and segment allocation of goodwill are presented below: | | | | Dominion
Generation | | Dominion
Energy | | DVP | | Corporate
and
Other(1) | | | Total | | | Dominion Generation | | Dominion Energy | | DVP | | | Corporate
and Other(1) | | | Total | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2011(2) | | $ | 1,503 | (3) | | $ | 712 | | | $ | 926 | (3) | | $ | — | | | $ | 3,141 | | | Asset disposition adjustment | | | — | | | | (11 | )(5) | | | — | | | | — | | | | (11 | ) | | Dominion | | | | | | | | | | | | Balance at December 31, 2012(2) | | $ | 1,503 | | | $ | 701 | | | $ | 926 | | | $ | — | | | $ | 3,130 | | | $ | 1,503 | | | $ | 701 | | | $ | 926 | | | $ | — | | | $ | 3,130 | | Asset disposition adjustment | | | (19 | )(4) | | | (25 | )(5) | | | — | | | | — | | | | (44 | ) | | | (19 | )(3) | | | (25 | )(4) | | | — | | | | — | | | | (44 | ) | Balance at December 31, 2013(2) | | $ | 1,484 | | | $ | 676 | | | $ | 926 | | | $ | — | | | $ | 3,086 | | | $ | 1,484 | | | $ | 676 | | | $ | 926 | | | $ | — | | | $ | 3,086 | | Asset disposition adjustment | | | | (32 | )(3) | | | (10 | )(4) | | | — | | | | — | | | | (42 | ) | Balance at December 31, 2014(2) | | | $ | 1,452 | | | $ | 666 | | | $ | 926 | | | $ | — | | | $ | 3,044 | | Dominion Gas | | | | | | | | | | | | Balance at December 31, 2012(2) | | | $ | — | | | $ | 552 | | | $ | — | | | $ | — | | | $ | 552 | | Asset disposition adjustment | | | | — | | | | (7 | )(4) | | | — | | | | — | | | | (7 | ) | Balance at December 31, 2013(2) | | | $ | — | | | $ | 545 | | | $ | — | | | $ | — | | | $ | 545 | | Asset disposition adjustment | | | | — | | | | (3 | )(4) | | | — | | | | — | | | | (3 | ) | Balance at December 31, 2014(2) | | | $ | — | | | $ | 542 | | | $ | — | | | $ | — | | | $ | 542 | |
| (1) | Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes. |
| (2) | Goodwill amounts do not contain any accumulated impairment losses. |
| (3) | Recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment. |
(4) | See Note 3 for a discussion of Dominion’s dispositions and related goodwill write-offs. |
(5)(4) | Related to assets sold or contributed to an affiliate or Blue Racer. |
Other Intangible Assets Dominion’s and Virginia Power’sThe Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion’s amortization expense for intangible assets was $71 million, $72 million and $82 million for 2014, 2013 and $78 million for 2013, 2012, and 2011, respectively. In 2013,2014, Dominion acquired $81$115 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 1015 years. Amortization expense for Virginia Power’s intangible assets was $24 million for 2014 and $22 million each year for 2013 2012, and 2011.2012. In 2013,2014, Virginia Power acquired $14$45 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 514 years. Dominion Gas’ amortization expense for intangible assets was $17 million, $16 million and $15 million for 2014, 2013 and 2012, respectively. In 2014, Dominion Gas acquired $8 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 7 years. The components of intangible assets are as follows:
| | At December 31, | | 2013 | | | 2012 | | | 2014 | | | 2013 | | | | | Gross
Carrying
Amount | | | Accumulated
Amortization | | | Gross
Carrying
Amount | | | Accumulated
Amortization | | | Gross Carrying Amount | | | Accumulated Amortization | | | Gross Carrying Amount | | | Accumulated Amortization | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Dominion | | | | | | | | | | | | | | | | | Software, licenses and other | | $ | 867 | | | $ | 308 | | | $ | 859 | | | $ | 327 | | | $ | 877 | | | $ | 312 | | | $ | 867 | | | $ | 308 | | Emissions allowances | | | 3 | | | | 2 | | | | 5 | | | | 1 | | | | 10 | | | | 5 | | | | 3 | | | | 2 | | Total | | $ | 870 | | | $ | 310 | | | $ | 864 | | | $ | 328 | | | $ | 887 | | | $ | 317 | | | $ | 870 | | | $ | 310 | | | Virginia Power | | | | | | | | | | | | | | | | | Software, licenses and other | | $ | 271 | | | $ | 78 | | | $ | 303 | | | $ | 122 | | | $ | 286 | | | $ | 81 | | | $ | 271 | | | $ | 78 | | Total | | $ | 271 | | | $ | 78 | | | $ | 303 | | | $ | 122 | | | $ | 286 | | | $ | 81 | | | $ | 271 | | | $ | 78 | | | Dominion Gas | | | | | | | | | | Software, licenses and other | | | $ | 192 | | | $ | 113 | | | $ | 180 | | | $ | 98 | | Total | | | $ | 192 | | | $ | 113 | | | $ | 180 | | | $ | 98 | |
Annual amortization expense for these intangible assets is estimated to be as follows: | | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | 2018 | | | 2015 | | | 2016 | | | 2017 | | | 2018 | | | 2019 | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion | | $ | 69 | | | $ | 59 | | | $ | 50 | | | $ | 40 | | | $ | 29 | | | $ | 72 | | | $ | 67 | | | $ | 58 | | | $ | 45 | | | $ | 36 | | | Virginia Power | | $ | 21 | | | $ | 15 | | | $ | 12 | | | $ | 9 | | | $ | 5 | | | $ | 21 | | | $ | 18 | | | $ | 15 | | | $ | 12 | | | $ | 8 | | | Dominion Gas | | | $ | 17 | | | $ | 16 | | | $ | 13 | | | $ | 11 | | | $ | 11 | |
NOTE 12. REGULATORY ASSETSAND LIABILITIES Regulatory assets and liabilities include the following: | | At December 31, | | 2013 | | | 2012 | | | 2014 | | | 2013 | | | (millions) | | | | | | | | | | | | | Dominion | | | | | | | | | Regulatory assets: | | | | | | | | | Deferred rate adjustment clause costs(1) | | $ | 89 | | | $ | 55 | | | $ | 124 | | | $ | 89 | | Unrecovered gas costs(2) | | | 50 | | | | 59 | | | Virginia sales taxes(3) | | | 46 | | | | 37 | | | Derivatives(4) | | | 16 | | | | — | | | Plant retirement(5) | | | 1 | | | | 25 | | | Deferred cost of fuel used in electric generation(2) | | | | 79 | | | | — | | Deferred nuclear refueling outage costs(3) | | | | 44 | | | | — | | Unrecovered gas costs(4) | | | | 36 | | | | 50 | | Other | | | 15 | | | | 27 | | | | 64 | | | | 78 | | Regulatory assets-current(6) | | | 217 | | | | 203 | | | Unrecognized pension and other postretirement benefit costs(7) | | | 706 | | | | 1,210 | | | Regulatory assets-current | | | | 347 | | | | 217 | | Unrecognized pension and other postretirement benefit costs(5) | | | | 1,050 | | | | 706 | | Deferred rate adjustment clause costs(1) | | | 287 | | | | 173 | | | | 250 | | | | 287 | | Income taxes recoverable through future rates(8) | | | 155 | | | | 140 | | | Derivatives(4) | | | 16 | | | | 105 | | | Other postretirement benefit costs(9) | | | 12 | | | | 21 | | | Plant retirement(5) | | | 10 | | | | 11 | | | Income taxes recoverable through future rates(6) | | | | 133 | | | | 155 | | Derivatives(7) | | | | 101 | | | | 16 | | Other | | | 42 | | | | 57 | | | | 108 | | | | 64 | | Regulatory assets-non-current | | | 1,228 | | | | 1,717 | | | | 1,642 | | | | 1,228 | | Total regulatory assets | | $ | 1,445 | | | $ | 1,920 | | | $ | 1,989 | | | $ | 1,445 | | Regulatory liabilities: | | | | | | | | | PIPP(10) | | $ | 76 | | | $ | 100 | | | Deferred cost of fuel used in electric generation(11) | | | 24 | | | | 7 | | | PIPP(8) | | | $ | 71 | | | $ | 76 | | Other | | | 28 | | | | 29 | | | | 99 | | | | 52 | | Regulatory liabilities-current(12) | | | 128 | | | | 136 | | | Provision for future cost of removal and AROs(13) | | | 1,028 | | | | 985 | | | Decommissioning trust(14) | | | 693 | | | | 501 | | | Unrecognized pension and other postretirement benefit costs(7) | | | 174 | | | | 2 | | | Deferred cost of fuel used in electric generation(11) | | | 90 | | | | 13 | | | Regulatory liabilities-current(9) | | | | 170 | | | | 128 | | Provision for future cost of removal and AROs(10) | | | | 1,072 | | | | 1,028 | | Nuclear decommissioning trust(11) | | | | 815 | | | | 693 | | Deferred cost of fuel used in electric generation(2) | | | | 6 | | | | 90 | | Other | | | 16 | | | | 13 | | | | 98 | | | | 190 | | Regulatory liabilities-non-current | | | 2,001 | | | | 1,514 | | | | 1,991 | | | | 2,001 | | Total regulatory liabilities | | $ | 2,129 | | | $ | 1,650 | | | $ | 2,161 | | | $ | 2,129 | | | Virginia Power | | | | | | | | | Regulatory assets: | | | | | | | | | Deferred rate adjustment clause costs(1) | | $ | 62 | | | $ | 51 | | | $ | 117 | | | $ | 62 | | Virginia sales taxes(3) | | | 46 | | | | 37 | | | Derivatives(4) | | | 16 | | | | — | | | Plant retirement(5) | | | 1 | | | | 25 | | | Deferred cost of fuel used in electric generation(2) | | | | 79 | | | | — | | Deferred nuclear refueling outage costs(3) | | | | 44 | | | | — | | Other | | | 3 | | | | 6 | | | | 58 | | | | 66 | | Regulatory assets-current | | | 128 | | | | 119 | | | | 298 | | | | 128 | | Deferred rate adjustment clause costs(1) | | | 227 | | | | 127 | | | | 179 | | | | 227 | | Income taxes recoverable through future rates(8) | | | 124 | | | | 110 | | | Derivatives(4) | | | 16 | | | | 105 | | | Plant retirement(5) | | | 10 | | | | 11 | | | Derivatives(7) | | | | 101 | | | | 16 | | Income taxes recoverable through future rates(6) | | | | 100 | | | | 124 | | Other | | | 40 | | | | 43 | | | | 59 | | | | 50 | | Regulatory assets-non-current | | | 417 | | | | 396 | | | | 439 | | | | 417 | | Total regulatory assets | | $ | 545 | | | $ | 515 | | | $ | 737 | | | $ | 545 | | Regulatory liabilities: | | | | | | | | | Deferred cost of fuel used in electric generation(11) | | $ | 24 | | | $ | 7 | | | Other | | | 17 | | | | 25 | | | $ | 90 | | | $ | 41 | | Regulatory liabilities-current | | | 41 | | | | 32 | | | | 90 | | | | 41 | | Provision for future cost of removal(13) | | | 807 | | | | 763 | | | Decommissioning trust(14) | | | 693 | | | | 501 | | | Deferred cost of fuel used in electric generation(11) | | | 90 | | | | 14 | | | Provision for future cost of removal(10) | | | | 852 | | | | 807 | | Nuclear decommissioning trust(11) | | | | 815 | | | | 693 | | Deferred cost of fuel used in electric generation(2) | | | | 6 | | | | 90 | | Other | | | 7 | | | | 7 | | | | 10 | | | | 7 | | Regulatory liabilities-non-current | | | 1,597 | | | | 1,285 | | | | 1,683 | | | | 1,597 | | Total regulatory liabilities | | $ | 1,638 | | | $ | 1,317 | | | $ | 1,773 | | | $ | 1,638 | | Dominion Gas | | | | | | Regulatory assets: | | | | | | Unrecovered gas costs(4) | | | $ | 29 | | | $ | 40 | | Deferred rate adjustment clause costs(1) | | | | 7 | | | | 27 | | UEX Rider(12) | | | | — | | | | 11 | | Other | | | | 2 | | | | 1 | |
| | | | | | | | | At December 31, | | 2014 | | | 2013 | | | (millions) | | | | | | | Regulatory assets-current | | | 38 | | | | 79 | | Unrecognized pension and other postretirement benefit costs(5) | | | 242 | | | | 194 | | Deferred rate adjustment clause costs(1) | | | 71 | | | | 59 | | Income taxes recoverable through future rates(6) | | | 24 | | | | 24 | | Other | | | 42 | | | | 8 | | Regulatory assets-non-current | | | 379 | | | | 285 | | Total regulatory assets | | $ | 417 | | | $ | 364 | | Regulatory liabilities: | | | | | | | | | PIPP(8) | | $ | 71 | | | $ | 76 | | Other | | | 4 | | | | 3 | | Regulatory liabilities-current | | | 75 | | | | 79 | | Provision for future cost of removal and AROs(10) | | | 172 | | | | 177 | | Unrecognized pension and other postretirement benefit costs(5) | | | — | | | | 18 | | Other | | | 20 | | | | 8 | | Regulatory liabilities-non-current | | | 192 | | | | 203 | | Total regulatory liabilities | | $ | 267 | | | $ | 282 | |
| (1) | Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects.projects for Virginia Power. Reflects deferrals of costs associated with certain current and prospective rider projects for Dominion Gas. See Note 13 for more information. |
| (2) | Reflects unrecovered gas costs atPrimarily reflects deferred fuel expenses for the Virginia jurisdiction of Dominion’s regulated gas operations, which are recovered through annual filings with the applicable regulatory authority.and Virginia Power’s generation operations. See Note 13 for more information. For 2014 and 2013, amount includes approximately $5 million related to DOE claims. |
Combined Notes to Consolidated Financial Statements, Continued
| (3) | Amounts to be recovered through an annual surcharge to reimburseLegislation enacted in Virginia in April 2014 requires Virginia Power for incremental sales taxes beingto defer operation and maintenance costs incurred duein connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to the repeal of the public service company sales tax exemption in Virginia.exceed 18 months. |
| (4) | As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes inReflects unrecovered gas costs at regulated gas operations, which are recovered through filings with the fair value of derivative instruments result in the recognition ofapplicable regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.authority. |
| (5) | Reflects costs anticipated to be recovered in North Carolina base rates for certain coal units expected to be retired. |
(6) | Current regulatory assets are presented in other current assets in Dominion’s Consolidated Balance Sheets. |
(7) | Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain of Dominion’s rate-regulated subsidiaries. |
(8)(6) | Amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes. |
(9)(7) | Primarily reflects costs recognizedAs discussed under Derivative Instruments in excessNote 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of amounts includedderivative instruments result in regulated rates charged by Dominion’s regulated gas operations before rates were updatedthe recognition of regulatory assets or regulatory liabilities as they are expected to reflect a change in accounting method for other postretirement benefit costs.be recovered from or refunded to customers. |
(10) (8) | Under PIPP, eligible customers can receive energy assistancemake reduced payments based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rider according to East Ohio tariff provisions. See Note 13 for more information regarding PIPP. |
(11) | Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power’s generation operations. For 2013, amount includes approximately $5 million related to DOE claims. See Note 13 for more information. |
(12) (9) | Current regulatory liabilities are presented in other current liabilities in Dominion’s Consolidated Balance Sheets. |
(13)(10) | Rates charged to customers by the Companies’ regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement. |
(14)(11) | Primarily reflectsReflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related ARO.AROs. |
| (12) | Represents East Ohio’s deferrals for the UEX Rider which are recovered through rates which are filed annually. Most of East Ohio’s bad debt expense is recovered either through the UEX Rider or the PIPP Rider. |
| See Note 13 for more information. |
At December 31, 2013,2014, approximately $129$218 million of Dominion’s, and $63$165 million of Virginia Power’s and $45 million of Dominion Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. The majority of these expenditures are expected to be recovered within the next two years. NOTE 13. REGULATORY MATTERS Regulatory Matters Involving Potential Loss Contingencies As a result of issues generated in the ordinary course of business, Dominion and Virginia Powerthe Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters thatfor which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, and involves elements of judgment and significant uncertainties. Any estimated range of possible loss doesuncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on Dominion’s or Virginia Power’sthe Companies’ financial position, liquidity or results of operations. FERC—ElectricELECTRIC Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Dominion’s merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion’s market-based sales tariffs authorized by FERC. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in the wholesale market. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary. Rates In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure. In July 2008, Virginia Power filed an application with FERC requesting a revision to its revenue requirement to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 1.5% for four of the projects (including the Meadow Brook-to-Loudoun and Carson-to-Suffolk lines, which were completed in 2011) and an incentive of 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008, the incentives were included in the PJM Tariff, and billing for the incentives was made accordingly. In 2012, PJM canceled one of the eleven projects with an estimated cost of $7 million. The total cost for the other ten projects included in Virginia Power’s formula rate for 2014 is $857 million and the remaining projects were completed by 2012. Numerous parties sought rehearing of the FERC order in August 2008. In May 2012, FERC issued an order denying the rehearing requests. In July 2012, the North Carolina Commission filed an appeal of the FERC orders with the U.S. Court of Appeals for the Fourth Circuit. In January 2014, the court rejected the appeal and affirmed FERC’s decision granting the incentives.
In March 2010, ODEC and NCEMC filed a complaint with FERC against Virginia Power claiming that approximately $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. ODEC and NCEMC requested that FERC establish procedures to determine the amount of costs for each applicable project that should be excluded from Virginia Power’s rates. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. In February 2012, Virginia Power submitted to FERC a settlement agreement to resolve all issues set for hearing. All transmission customer parties to the proceeding joined the settlement. The Virginia Commission, North Carolina Commission and Public Staff of the North Carolina Commission, while not parties to the settlement, have agreed to not oppose the settlement. The settlement was accepted by FERC in May 2012 and provides for payment by Virginia Power to the transmission customer parties collectively of $250,000 per year for ten years and resolves all matters other than allocation of the incremental cost of certain underground transmission facilities. In March 2014, FERC issued an order excluding from Virginia Power’s transmission rates for wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable for non-Virginia wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities which has been briefed pursuantbecause the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to FERC’s May 2012benefit the citizens of Virginia. The order is retroactively effective as of March 2010 and awaitswill cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC action.determined that there was not sufficient evidence on the record to determine the magnitude of the underground increment and ordered a hearing to determine the appropriate amount of undergrounding cost to be allocated to each wholesale transmission customer in Virginia. While Virginia Power cannot predict the outcome of the briefing,hearing, it is not expected to have a material effect on results of operations. Other Regulatory Matters Electric Regulation in VirginiaELECTRIC REGULATIONIN VIRGINIA
The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers. The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs, and also constitutescontains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly proposednewly-proposed generation projects. If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.
2013 Biennial Review Pursuant to the Regulation Act, in March 2013, Virginia Power submitted its base rate filings and accompanying schedules in support of the Virginia Commission’s 2013 biennial review of VirginaVirginia Power’s rates, terms and conditions, as well as of Virginia Power’s earnings for 2011 and 2012 test periods. The Virginia Power earnings test analysis reviewed by the Virginia Commission reflected an ROE of 10.30% on its generation and distribution services earnings for the combined test periods. In November 2013, the Virginia Commission issued its 2013 Biennial Review Order. After deciding eleven contested earnings test adjustments, the Virginia Commission ruled that Virginia Power earned on average an ROE of approximately 10.25% on its generation and distribution services for the combined 2011 and 2012 test periods. Because this ROE was more than 50 basis points below Virginia Power’s authorized ROE of 10.9%, the Virginia Commission authorized the deferred recovery, for earnings test purposes, of $23 million in costs related to asset impairments with early retirement decisions, severe weather events, and natural disasters to be amortized over the 2013 calendar year. The Virginia Commission did not order a base rate increase because Virginia Power had previously waived its right to any such increase, and because it determined that Virginia Power had a revenue sufficiency of approximately $280 million when projecting the annual revenues generated by base rates to the revenues required to cover costs of service and earn a fair return. As part of its revenue sufficiency determination, the Virginia Commission also made findings on eleven rate case adjustments, in addition to changes to the cost of capital and capital structure, which resulted in changes to Virginia Power’s rate year revenues and expenses, and Virginia Power’s rate base for generation and distribution, for the rate year beginning January 1, 2014. Virginia Power incurred a $55 million ($37 million after-tax) charge in connection with the 2013 Biennial Review Order. In its 2013 Biennial Review Order, the Virginia Commission also set the ROE that will be used in Virginia Power’s 2015 biennial review earnings test analysis for earnings on generation and distribution services for the combined 2013 and 2014 test periods, and that will be applied to Riders R, S, W, B, BW, C1A, and C2A. Pursuant to the Regulation Act, Virginia Power’s authorized ROE can be no lower than the average of the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., subject to certain limitations as described in the Regulation Act. Following this statutory peer group analysis, the Virginia Commission determined that the peer group floor ROE for Virginia Power was 9.89%. It further held, declining to increase or decrease Virginia Power’s combined rate of return based on performance, that Virginia Power’s ROE for earnings test purposes in its 2015 biennial review and for rate adjustment clause purposes is 10.0%, consistent with its determination that Virginia Power’s market cost of equity is 10.0%. Virginia Fuel Expenses In May 2013,2014, Virginia Power submitted its annual fuel factor filing to the Virginia Commission proposingto recover an increase of approximately $162 millionestimated $1.9 billion in Virginia jurisdictional projected fuel revenueexpenses for the rate year beginning July 1, 2013.2014. Virginia Power also offered to defer recovery of 50% of its total estimated $268 million jurisdictional deferred fuel balance to the 2015-2016 fuel year, thereby recovering $134 million of its jurisdictional deferred fuel balance for the rate year beginning July 1, 2014. In June 2013, the Virginia Commission issued an order approving the rate. In November 2013,September 2014, the Virginia Commission approved Virginia Power’s voluntary request to reduceincreased fuel rate, which was already in effect on an interim basis since July 1, 2014. The new rate includes approval of Virginia Power’s currently-approvedoffer to defer recovery of 50% its jurisdictional deferred fuel factor rate from 2.942 ¢/kWh to 2.572 ¢/kWh effective for usage onbalance and after December 1, 2013, due torepresents an expected over-recoveryannual fuel revenue increase of fuel costs. This request is expected to reduce Virginia Power’s anticipated fuel recoveries through June 30, 2014 by more than $140approximately $300 million. At December 31,
Combined Notes to Consolidated Financial Statements, Continued
2013, Virginia Power’s Consolidated Balance Sheets reflected $24 million of other current liabilities and $85 million of noncurrent regulatory liabilities related to the over-recovered fuel costs.
Rate Adjustment Clauses Below is a discussion of significant riders associated with various Virginia Power projects: | Ÿ | | The Virginia Commission previously approved Rider T1. In 2012,July 2014, the Virginia Commission approved the conversion of the Altavista, Hopewell, and Southampton power stations to biomass, and in conjunction approved Rider B. Virginia Power proposed an approximately $16 million revenue requirement for the rate year beginning April 1, 2014. This case is pending. |
Ÿ | | In 2013, the Virginia Commission approved Virginia Power’s request to construct and operate Brunswick County, and in conjunction approved the associated transmission facilities and Rider BW. Virginia Power proposed an approximately $101$538 million revenue requirement for the rate year beginning September 1, 2014. This case is pending.2014, which represents an approximately $134 million increase over the previous year.
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| Ÿ | | The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2014, Virginia Power proposed an approximately $248$244 million revenue requirement for the rate year beginning April 1, 2014.2015. This case is pending. |
| Ÿ | | The Virginia Commission previously approved Rider W in conjunction with Warren County. In February 2015, the Virginia Power proposedCommission approved an approximately $101$135 million total revenue requirement for the rate year beginning April 1, 2014.2015. |
| Ÿ | | The Virginia Commission previously approved Rider BW in connection with Brunswick County. In October 2014, Virginia Power proposed a total revenue requirement of approximately $111 million for the rate year beginning September 1, 2015. This case is pending. |
| Ÿ | | The Virginia Commission previously approved Riders C1A and C2A in connection with variouscost recovery for DSM programs. The requestedIn August 2014, Virginia Power proposed a total revenue requirements arerequirement of approximately $1$47 million for Rider C1A andthe rate year beginning May 1, 2015. Virginia Power further proposed three new energy efficiency programs for Virginia Commission approval with a requested five-year cost cap of approximately $35$106 million for those programs. This case is pending. |
| Ÿ | | The Virginia Commission previously approved Rider C2A.R in conjunction with Bear Garden. In June 2014, Virginia Power proposed an approximately $84 million revenue requirement for the rate year beginning April 1, 2015. This case is pending. |
| Ÿ | | Virginia legislation which provides for the recovery of costs to move certain electric distribution lines underground became effective in July 2014. In October 2014, Virginia Power filed for approval of Rider U, which proposes a revenue requirement of approximately $28 million during the initial rate year beginning September 1, 2015. This case is pending. |
| Ÿ | | The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2014, Virginia Power proposed an approximately $13 million revenue requirement for the rate year beginning April 1, 2015. This case is pending. |
| Ÿ | | In May 2013,January 2015, Virginia Power filedapplied for an adjustmenta CPCN to construct and operate a new 20 MW utility-scale solar facility near its current existing Remington Power Station in Fauquier County, Virginia. Virginia Power also applied for approval of |
Combined Notes to Consolidated Financial Statements, Continued | Rider T1 withUS-1 to recover the Virginia Commission forcosts of the rate year beginning September 1, 2013, which reflects afacility. The total revenue requirementcost of the Remington Solar Facility is approximately $404 million. In July 2013, the Virginia Commission issued an order approving the rate.$47 million (excluding financing costs). This case is pending. |
Bremo Power StationBrunswick County
In SeptemberAugust 2013, three motions for reconsideration were filed with the Virginia Commission, asking that it reconsider its August 2013 final order approving a CPCN for construction of Brunswick County. In November 2013, the Virginia Commission issued its final order approving an amended and reissued CPCN that would allow Virginia Power to convert Bremo Units 3 and 4 from using coal to natural gas as their fuel source. The proposed conversion will preserve 227 MW (net) of existing capacity and is expected to cost approximately $53 million, excluding financing costs. North Anna
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. In April 2013, Virginia Power decided to replace the reactor design previously selected for a potential unit with ESBWR technology.
If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power filed the first of its two-part amendment to the COL application with the NRC in July 2013 to reflect the ESBWR technology, and filed the second part of the amendment in December 2013. A COL is expected in 2015. Virginia Power has not yet committed to building a new nuclear unit at North Anna.
In May 2013, BREDL filed a motion with the NRC ASLB to reopen the COL adjudicatory proceeding relating to North Anna based on new information, citing the change in reactor technology. The motion did not propose any new contentions but asked that either (i) the proceeding be restarted from the beginning by submittal of a new application and renoticing in the Federal Register, or (ii) the proceeding be reopened pending submittal of new contentions, which BREDL would be given an extended amount of time to file.
In July 2013, the ASLB issued an order holding BREDL’s motion in abeyance. The ASLB noted that because BREDL proposed no contentions, it could not determine whether any portion of the motion falls within the ASLB’s jurisdiction, which is currently limited to ruling on a September 2011 petition filed by BREDL to reopen the COL proceeding related to seismic issues. In January 2014, Virginia Power informed the ASLB and parties that the Company’s assessment of seismic issues was complete. Under a previous ruling of the ASLB, BREDL will have a period of 60 days from the time Virginia Power informs the NRC and parties that its seismic assessment is complete to submit a motion to reopen the proceeding on this topic.
Legislation has been proposed that would limit the portion of costs incurred by an investor-owned electric utility between July 1, 2007 and December 31, 2013, in developing a nuclear power facility or an offshore wind project that are recoverable from Virginia jurisdictional and non-jurisdictional customers through a future rate adjustment clause to a maximum of 30% of such amount. Virginia Power has deferred or capitalized costs totaling $570 million as of December 31, 2013 related to the development of a third nuclear unit site located at North Anna. If this proposed legislation is enacted, 70% of the costs previously deferred or capitalized would be recovered from Virginia jurisdictional and non-jurisdictional ratepayers as part of the 2013 and 2014 base rates. Upon enactment, Virginia Power would recognize 70% of the costs previously deferred or capitalized against net income in 2014. The remaining deferred or capitalized costs, as well as costs incurred after December 31, 2013, would continue to be eligible for inclusion in a future rate adjustment clause.
Electric Transmission Projects
In January 2013, a notice of appeal wasdenied reconsideration. Three appeals were filed with the Supreme Court of Virginia, by a private party regarding the Virginia Commission’s December 2012 order granting a CPCN and authorizing construction of the Waxpool-Brambleton-BECO line.but two were withdrawn. In October 2013,September 2014, the Supreme Court of Virginia issued an opinion affirming the Virginia Commission’s decision.
In October 2013, Virginia Power applied for a CPCN to rebuild within existing rights-of-way its existing 500 kV Loudoun-Pleasant View transmission line in Loudoun County. As stateddecision in the application, the project is needed to address NERC Reliability Standards violations projected to occur in 2016 and to replace aging transmission facilities. This case is pending.remaining appeal.
Electric Transmission Project In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry Switching Station in Surry County to a new Skiffes Creek Switching Station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed
new Skiffes Creek Switching Station to Virginia Power’s existing Whealton Substation in the City of Hampton. In December 2013,February 2014, the Virginia Commission granted reconsideration requested by Virginia Power and issued an Order Amending Certificate. Several appeals were filed with the Supreme Court of Virginia and oral arguments were heard in January 2015. The appeals are pending. North Anna Virginia Power is considering the construction of a motion for reconsiderationthird nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In April 2013, Virginia Power decided to replace the reactor design previously selected for a noticepotential unit with ESBWR technology. Virginia Power filed the first of its two-part amendment to appealthe COL application with the NRC in July 2013 to reflect the ESBWR technology and filed the second part of the amendment in December 2013. The COL is expected in 2016. Virginia Power has not yet committed to building a new nuclear unit at North Anna. In June 2012, the U.S. Court of Appeals for the D.C. Circuit vacated and remanded a 2010 NRC decision and related rulemaking that generically assessed the environmental impacts of spent fuel storage after expiration of a reactor’s license until a repository became available. In August 2012, the NRC partially granted a petition filed by BREDL and other petitioners in a number of ongoing licensing proceedings, including the North Anna COL proceedings, to withhold issuance of licenses until completion of action on the remand, and held proposed contentions accompanying the petition in abeyance. In August 2014, the NRC approved a new final rule codifying the NRC’s further generic assessment of environmental impacts of continued storage of spent fuel and lifted the suspension of final licensing decisions in pending cases and dismissed pending contentions on the subject, including the proposed contention filed by BREDL. In September 2014, BREDL filed a new petition with the NRC again seeking suspension of final decision making in the COL proceeding, along with motions to reopen and file a new contention. The new filings assert that the NRC must make a safety finding on the feasibility and capacity of geologic disposal of spent fuel as a prerequisite to issuance of a license. The filings alleged that because these safety findings are no longer made as part of the NRC’s new continued storage rule, such findings must now be made in individual licensing proceedings. In January 2015, BREDL filed another petition in the COL proceeding asking the NRC to order supplementation of the final environmental impact statement for North Anna 3 to incorporate the NRC’s generic assessment of the impacts of continued spent fuel storage, so that BREDL could then challenge that assessment. BREDL’s September 2014 filings and January 2015 petition are substantially the same as filings made by various other intervenor groups in other licensing proceedings pending before the NRC. Resolution of these filings is not expected to affect the schedule for issuance of the COL. North Anna and Offshore Wind Legislation In April 2014, legislation was enacted in Virginia that permits Virginia Power to recover 70% of the costs previously deferred or capitalized related to the development of a third nuclear unit located at North Anna and offshore wind facilities through December 31, 2013 as part of the 2013 and 2014 base rates. Virginia Power had deferred or capitalized costs totaling approximately $577 million for these projects as of December 31, 2013, substantially all of which relate to North Anna. For the 70% portion of these previously deferred or capitalized costs allocable to customers in Virginia, Virginia Power recognized such amounts that are now recoverable in 2013 and 2014 base rates as charges against net income beginning in the second quarter of 2014 and for the remainder of the year. During 2014, Virginia Power recognized $374 million ($248 million after-tax) in charges against income representing the cumulative recovery of costs from January 2013 through December 2014, which are primarily included in other operations and maintenance expense in the Consolidated Statements of Income. The remaining deferred or capitalized costs, as well as costs incurred after December 31, 2013, continue to be eligible for inclusion in a future rate adjustment clause. Regulation Act Legislation In February 2015, the Virginia Commission’s orderGovernor signed legislation into law which will keep Virginia Power’s base rates unchanged until at least December 1, 2022. In addition, no biennial reviews will be conducted by the Virginia Commission for the five successive 12-month test periods beginning January 1, 2015, and ending December 31, 2019. Virginia Power is scheduled to file its next biennial review, covering 2013 and 2014, in March 2015. The legislation allows this review to proceed for the sole purpose of determining whether any refunds are due to customers based on earnings performance during the 2013 and 2014 test periods. In addition the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility’s ROE for use in connection with rate adjustment clauses and requires utilities to file integrated resource plans annually rather
than biennially. The legislation requires Virginia Power to write-off $85 million of prior-period deferred fuel costs during the first quarter of 2015. In addition, the legislation requires the Virginia Commission to implement a fuel rate reduction for Virginia Power as soon as practicable based on this non-recovery as well as any over-recovery for the 2014-2015 fuel year and projected fuel expense for the 2015-2016 fuel year. The legislation also deems the construction or purchase of one or more utility-scale solar facilities located in Virginia up to 500 MW in total to be in the public interest. NORTH CAROLINA REGULATION In December 2012, the North Carolina Commission approved a $36 million increase in Virginia Power’s annual non-fuel base revenues based on an authorized ROE of 10.2%, and a $14 million decrease in annual base fuel revenues for a combined total base revenue increase of $22 million. These rate changes became effective on January 1, 2013 and were appealed to the North Carolina Supreme Court by multiple parties. In June 2014, the Supreme Court of Virginia. TheNorth Carolina issued an opinion reversing the portion of the North Carolina Commission’s December 2012 order from Virginia Power’s 2012 base rate case approving a 10.2% ROE for Virginia Power, and remanding the case to the North Carolina Commission granted reconsideration and orderedfor additional findings of fact in light of a hearing, which was held in2013 opinion issued after the North Carolina Commission’s order. This case is pending. In December 2014, the North Carolina Commission issued an order approving an approximately $17 million increase to the fuel component of Virginia Power’s electric rates for the rate year beginning January 2014. The matter is pending at1, 2015. This increase includes the approval of Virginia Commission. The projected in-service date for this transmission project has been delayed until December 2015 atPower’s mitigation proposal to defer recovering 50% of its estimated $17 million jurisdictional deferred fuel balance to the earliest.2016 fuel year, without interest. Ohio RegulationOHIO REGULATION
PIR Program In 2008, East Ohio began PIR, aimed at replacing approximately 20%25% of its pipeline system, orsystem. In February 2014, East Ohio filed an application requesting approval to adjust the PIR cost recovery rates for 2013 costs. The filing reflects gross plant investment for 2013 of $164 million, cumulative gross plant investment of $674 million and an estimated revenue requirement of $89 million. This application was approved by the Ohio Commission in April 2014. In February 2015, East Ohio filed an application to adjust the PIR cost recovery for 2014 costs. The filing reflects gross plant investment for 2014 of $155 million, cumulative gross plant investment of $829 million and a revenue requirement of $108 million. This case is pending. AMR Program In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. In May 2014, AMR cost recovery rates became effective as approved by the Ohio Commission in April 2014. The approval includes a revenue requirement of $8 million, which represents an approximately 4,100 miles,$3 million increase over a 25-year period. the previous year. In FebruaryJanuary 2013, East Ohio filed with the Ohio Supreme Court an appeal of a rate reduction ordered by the Ohio Commission in October 2012 and a motion seeking a stay of the AMR cost recovery rate imposed. The Ohio Supreme Court granted the stay in March 2013 and East Ohio put the higher AMR cost recovery rate filed by East Ohio into effect. In July 2014, the Ohio Supreme Court ruled in East Ohio’s favor by agreeing that the rate reduction imposed by the Ohio Commission was unreasonable. In February 2015, East Ohio filed its application with the Ohio Commission to adjust theits AMR cost recovery charge to recover costs for costscalendar year 2014 associated with PIR investments for the calendar year 2012 and cumulatively. The application includes total gross plant investment for 2012 of $148 million, cumulative gross plant investment of $511 million, and a revenue requirement of $67 million. The Ohio Commission issued an order approving the ratesAMR deployment, which was completed in April 2013. In May 2013, the approved PIR cost recovery rates became effective. In November 2013, East Ohio filed a notice to adjust the PIR cost recovery for 2013 costs.2012. The filing reflects a projected gross plant investment for 2013 of $170 million, cumulative gross plant investment of $681 million and an estimated revenue requirement of approximately $90$8 million. This case is pending.
The AMR program approved by the Ohio Commission is now complete. Although no further capital investment will be added, East Ohio is approved to recover depreciation, property taxes, carrying charges and a return until East Ohio has another rate case. PIPP Plus Program Under the Ohio PIPP Plus Program, eligible customers can receive energy assistancemake reduced payments based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP payment plan amount is deferred and collected under the PIPP riderRider in accordance with the rules of the Ohio Commission. In July 2013, the Ohio Commission approved2014, East Ohio’s annual update of the PIPP Rider whichwas automatically approved by the Ohio Commission after a 45-day waiting period from the date of the filing. The increased rider rate reflects the refund over the next year of an over-recovery of accumulated arrearages of approximately $91$82 million as of March 31, 2013,2014, net of projected deferred program costs of approximately $54$96 million for the period from April 20132014 through June 2014.2015. UEX Rider East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In July 2014, the Ohio Commission approved a decrease to East Ohio’s UEX Rider, which reflects the elimination of the over-recovered balance of accumulated bad debt expense of approximately $8 million as of March 31, 2014, and recovery of prospective bad debt expense projected to total approximately $25 million for the twelve-month period from April 2014 to March 2015. House Bill 95 Ohio enacted utility reform legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future. In July 2014, the Ohio Commission approved East Ohio’s application requesting authority to
Combined Notes to Consolidated Financial Statements, Continued implement a capital expenditure program for 2014 capital expenditures totaling $110 million. FERC RegulationREGULATION DTI Fuel Settlement In mid-2013, DTI received concerns about its fuel retainage percentages and apparent over-recovery of fuel costs during certain time periods reflected in its annual fuel reports. In December 2013, DTI submitted for FERC approval a stipulation and agreement addressing, among other things, reductions in its fuel retainage percentages. percentages and a rate moratorium through 2016. In February 2014, FERC approved the stipulation and agreement. The revised fuel retainage percentages became effective January 1, 2014. DTI will implementbegan assessing the reduced fuel retainage percentages effectiveon March 1, 2014. DTI will also provide2014, and as a result provided refunds totaling nearly $10 million. The refunds reflect, with interest, to each settling customer reflecting the value of the difference between the actual quantities of fuel retained from that party betweenfor the months of January 1, 2014and February and the March 1, 2014 implementation date. This agreement is expected to reduce DTI’s revenues by approximately $35 million in 2014.
Combined Notes to Consolidated Financial Statements, Continued
quantities that would have been retained using the reduced percentages. NOTE 14. ASSET RETIREMENT OBLIGATIONS AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of Dominion’s and Virginia Power’sthe Companies’ long-lived assets. Dominion’s and Virginia Power’s AROs are primarily associated with the decommissioning of their nuclear generation facilities. In addition, Dominion’s AROsfacilities and also include plugging and abandonment of gas and oil wells, interim retirements of natural gas gathering, transmission, distribution and storage pipeline components, andthose for the future abatement of asbestos expected to be disturbed in the Companies’their generation facilities. Dominion Gas’ AROs primarily include plugging and abandonment of gas and oil wells and the interim retirement of natural gas gathering, transmission, distribution and storage pipeline components. The Companies have also identified, but not recognized, AROs related to retirement of Dominion’s LNG facility, Dominion’sDominion Gas’ gas storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in the Companies’Dominion’s and Virginia Power’s generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 20122013 and 20132014 were as follows: | | | | | | | | Amount | | | (millions) | | | | Dominion | | | | | AROs at December 31, 2011(1) | | $ | 1,398 | | Obligations incurred during the period | | | 24 | | Obligations settled during the period | | | (13 | ) | Revisions in estimated cash flows(2) | | | 242 | | Accretion | | | 77 | | Other | | | (23 | ) | AROs at December 31, 2012(1) | | $ | 1,705 | | Obligations incurred during the period | | | 13 | | Obligations settled during the period | | | (68 | ) | Revisions in estimated cash flows(3) | | | (129 | ) | Accretion | | | 86 | | Other | | | (29 | ) | AROs at December 31, 2013(1) | | $ | 1,578 | | Virginia Power | | | | | AROs at December 31, 2011(4) | | $ | 625 | | Obligations incurred during the period | | | 18 | | Obligations settled during the period | | | (1 | ) | Revisions in estimated cash flows(5) | | | 41 | | Accretion | | | 34 | | Other | | | (12 | ) | AROs at December 31, 2012 | | $ | 705 | | Obligations incurred during the period | | | 2 | | Obligations settled during the period | | | (2 | ) | Revisions in estimated cash flows(3) | | | (52 | ) | Accretion | | | 38 | | Other | | | (2 | ) | AROs at December 31, 2013 | | $ | 689 | |
| | | | | | | | Amount | | | (millions) | | | | Dominion | | | | | AROs at December 31, 2012(1) | | $ | 1,705 | | Obligations incurred during the period | | | 13 | | Obligations settled during the period | | | (68 | ) | Revisions in estimated cash flows(2) | | | (129 | ) | Accretion | | | 86 | | Other | | | (29 | ) | AROs at December 31, 2013(1) | | $ | 1,578 | | Obligations incurred during the period | | | 40 | | Obligations settled during the period | | | (82 | ) | Revisions in estimated cash flows(3) | | | 102 | | Accretion | | | 81 | | Other | | | (5 | ) | AROs at December 31, 2014(1) | | $ | 1,714 | | Virginia Power | | | | | AROs at December 31, 2012 | | $ | 705 | | Obligations incurred during the period | | | 2 | | Obligations settled during the period | | | (2 | ) | Revisions in estimated cash flows(2) | | | (52 | ) | Accretion | | | 38 | | Other | | | (2 | ) | AROs at December 31, 2013 | | $ | 689 | | Obligations incurred during the period | | | 28 | | Obligations settled during the period | | | (1 | ) | Revisions in estimated cash flows(3) | | | 108 | | Accretion | | | 37 | | Other | | | (6 | ) | AROs at December 31, 2014(4) | | $ | 855 | | Dominion Gas | | | | | AROs at December 31, 2012 | | $ | 133 | | Obligations incurred during the period | | | 8 | | Obligations settled during the period | | | (13 | ) | Accretion | | | 8 | | Other | | | 1 | | AROs at December 31, 2013(5)(6) | | $ | 137 | | Obligations incurred during the period | | | 2 | | Obligations settled during the period | | | (8 | ) | Accretion | | | 8 | | Other | | | 8 | | AROs at December 31, 2014(5)(6) | | $ | 147 | |
| (1) | Includes $15 million, $64 million, $94 million and $94$81 million reported in other current liabilities at December 31, 2011, 2012, 2013, and 2013,2014, respectively. |
| (2) | Primarily reflects the accelerated timing of the decommissioning of Kewaunee that began in 2013. |
(3) | Primarily reflects lower anticipated nuclear decommissioning costs. |
| (3) | Relates primarily to a shift of the delayed planned date on which the DOE is expected to begin accepting spent nuclear fuel. |
| (4) | Includes $1$7 million reported in other current liabilities.liabilities at December 31, 2014. |
| (5) | Primarily reflectsIncludes $2 million and $7 million reported in other current liabilities at December 31, 2013 and 2014, respectively. |
| (6) | Includes $135 million and $140 million reported in other deferred credits and other liabilities, with the effect of higher anticipated nuclear decommissioning costs.remainder recorded in other current liabilities, at December 31, 2013 and 2014, respectively. |
Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 20132014 and 2012,2013, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $3.9$4.2 billion and $3.3$3.9 billion, respectively. At
December 31, 20132014 and 2012,2013, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.8$1.9 billion and $1.5$1.8 billion, respectively. NOTE 15. VARIABLE INTEREST ENTITIES The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE. Dominion Through August 2013, Dominion leased the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. In August 2013, the lease expired and Dominion purchased Fairless for $923 million from Juniper per the terms of the lease agreement. However, as Dominion had previously consolidated Juniper, the purchase was accounted for as an equity transaction to acquire the noncontrolling interests from Juniper for $923 million, while Dominion retained control of Fairless. The acquisition resulted in the removal of securities due within one year-VIE and noncontrolling interests from Dominion’s Consolidated Balance Sheet during 2013. Dominion has an initial 45% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the nature of this entity. Dominion concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion has concluded that it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. Dominion is obligated to provide capital contributions based on its ownership percentage. Dominion’s maximum exposure to loss is limited to its current and future investment. Dominion Gas DTI has been engaged to oversee the construction of, and to subsequently operate and maintain, the projects undertaken by Atlantic Coast Pipeline based on the overall direction and oversight of Atlantic Coast Pipeline’s members. An affiliate of DTI holds a membership interest in Atlantic Coast Pipeline, therefore DTI is considered to have a variable interest in Atlantic Coast Pipeline. The members of Atlantic Coast Pipeline hold the power to direct the construction, operations and maintenance activities of the entity. DTI has concluded it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance. DTI has no obligation to absorb any losses of the VIE. See Note 24 for information about associated related party receivable balances. Virginia Power Virginia Power has long-term power and capacity contracts with fourfive non-utility generators with an aggregate summer generation capacity of approximately 870 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $864$639 million as of December 31, 2013.2014. Virginia Power paid $223 million, $217 million, $214 million, and $211$214 million for electric capacity and $138 million, $98 million, $83 million, and $125$83 million for electric energy to these entities for the years ended December 31, 2014, 2013 and 2012, respectively. Virginia Power and 2011, respectively.Dominion Gas Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of approximately $335 million and $106 million, $331 million and $115 million, and $328 million and $389$107 million for the years ended December 31, 2014, 2013 2012 and 2011,2012, respectively. Virginia Power and Dominion Gas determined that iteach is not the most closely associated entity with DRS and therefore notneither is the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power.Power and Dominion Gas. Virginia Power hasand Dominion Gas have no obligation to absorb more than itstheir allocated shareshares of DRS costs.
Through August 2013, Dominion leased the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. Dominion made annual lease payments of approximately $53 million.
Juniper was formed in 2003 as a limited partnership and was organized for the purpose of acquiring and constructing a number of assets for lease. Such assets were financed with proceeds from the issuance of bank debt, privately placed long-term debt and partnership capital received from Juniper’s general and limited partners. Dominion had no voting equity interest in Juniper. Because Juniper had been subject to the business scope exception, Dominion was not required to evaluate whether Juniper was a VIE prior to October 2011.
Through September 30, 2011, Juniper held various power plant leases, including Fairless. In October 2011, the last lease other than Fairless expired and the related asset was sold by Juniper. With Fairless being its sole remaining asset, Juniper no longer qualified as a business as of October 2011, which required that Dominion determine whether Juniper was a VIE. Dominion concluded Juniper was a VIE because the entity’s capitalization was insufficient to support its operations, the power to direct the most significant activities of the entity was not held by the equity holders, and Dominion guaranteed a portion of the residual value of Fairless. The activities that most significantly impacted Juniper’s economic performance related to the operation of Fairless. The decisions related to the operations of Fairless were made by Dominion and as such, Dominion was considered the primary beneficiary.
Accordingly, Dominion consolidated Juniper in October 2011 and recorded, at fair value, approximately $957 million of property, plant and equipment, $896 million of debt and $61 million of noncontrolling interests. The debt was non-recourse to Dominion and was secured by Juniper’s assets. The annual lease payments made by Dominion to Juniper for Fairless were eliminated in the Consolidated Statements of Income and were excluded from the lease commitments table in Note 22 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2012. Dominion did not provide any financial or other support to Juniper that it was not previously contractually required to provide.
In August 2013, the lease expired and Dominion purchased Fairless for $923 million from Juniper per the terms of the lease agreement. However, as Dominion had previously consolidated Juniper, the purchase was accounted for as an equity transaction to acquire the noncontrolling interests from Juniper for $923 million, while Dominion retained control of Fairless. The acquisition resulted in the removal of securities due within one year-VIE and noncontrolling interests from Dominion’s Consolidated Balance Sheet during 2013.
NOTE 16. SHORT-TERM DEBTAND CREDIT AGREEMENTS Dominion and Virginia PowerThe Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.
Combined Notes to Consolidated Financial Statements, Continued DOMINIONDominion
Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows: | | | | Facility
Limit | | Outstanding
Commercial
Paper | | Outstanding
Letters of
Credit | | Facility
Capacity
Available | | | Facility
Limit | | | Outstanding
Commercial
Paper | | Outstanding
Letters of
Credit | | | Facility
Capacity
Available | | | (millions) | | | | | | | | | | | | | | | | | | | | | At December 31, 2014 | | | | | | | | | | Joint revolving credit facility(1) | | | $ | 4,000 | | | $ | 2,664 | | | $ | — | | | $ | 1,336 | | Joint revolving credit facility(2) | | | | 500 | | | | 111 | | | | 48 | | | | 341 | | Total | | | $ | 4,500 | | | $ | 2,775 | (3) | | $ | 48 | | | $ | 1,677 | | At December 31, 2013 | | | | | | | | | | | | | | | | | Joint revolving credit facility(1) | | $ | 3,000 | | | $ | 1,927 | | | $ | — | | | $ | 1,073 | | | $ | 3,000 | | | $ | 1,927 | | | $ | — | | | $ | 1,073 | | Joint revolving credit facility(2) | | | 500 | | | | — | | | | 11 | | | | 489 | | | | 500 | | | | — | | | | 11 | | | | 489 | | Total | | $ | 3,500 | | | $ | 1,927 | (3) | | $ | 11 | | | $ | 1,562 | | | $ | 3,500 | | | $ | 1,927 | (3) | | $ | 11 | | | $ | 1,562 | | At December 31, 2012 | | | | | | | | | | Joint revolving credit facility(1) | | $ | 3,000 | | | $ | 2,412 | | | $ | — | | | $ | 588 | | | Joint revolving credit facility(2) | | | 500 | | | | — | | | | 26 | | | | 474 | | | Total | | $ | 3,500 | | | $ | 2,412 | (3) | | $ | 26 | | | $ | 1,062 | | |
| (1) | Effective September 2013,In May 2014, this credit facility was amended and restated. The facility limit was increased from $3 billion to $4 billion and the maturity date was extended from September 20172018 to September 2018.April 2019. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit. |
| (2) | Effective September 2013,In May 2014, this credit facility was amended and restated and the maturity date for $400 million of the $500 million committed capacity was extended from September 20172018 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018.April 2019. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. |
| (3) | The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were 0.33%0.38% and 0.49%0.33% at December 31, 20132014 and 2012,2013, respectively. |
Combined Notes to Consolidated Financial Statements, Continued
VIRGINIA POWERVirginia Power
Virginia Power’s short-term financing is supported by two joint revolving credit facilities with Dominion.Dominion and Dominion Gas. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion and Virginia Powerthe Companies and for other general corporate purposes. Virginia Power’s share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion and Dominion Gas were as follows: | | | | | | | | | | | | | | | | | | | | Facility
Sub-limit | | | Outstanding
Commercial
Paper | | | Outstanding
Letters of
Credit | | | Facility
Sub-limit
Capacity
Available | | | (millions) | | | | | | | | | | | | | At December 31, 2013 | | | | | | | | | | | | | | | | | Joint revolving credit facility(1) | | $ | 1,000 | | | $ | 842 | | | $ | — | | | $ | 158 | | Joint revolving credit facility(2) | | | 250 | | | | — | | | | 1 | | | | 249 | | Total | | $ | 1,250 | | | $ | 842 | (3) | | $ | 1 | | | $ | 407 | | At December 31, 2012 | | | | | | | | | | | | | | | | | Joint revolving credit facility(1) | | $ | 1,000 | | | $ | 992 | | | $ | — | | | $ | 8 | | Joint revolving credit facility(2) | | | 250 | | | | — | | | | 2 | | | | 248 | | Total | | $ | 1,250 | | | $ | 992 | (3) | | $ | 2 | | | $ | 256 | |
| | | | | | | | | | | | | | | | | | | | Facility
Sub-limit | | | Outstanding
Commercial
Paper | | | Outstanding
Letters of
Credit | | | Facility
Sub-limit
Capacity
Available | | | (millions) | | | | | | | | | | | | | At December 31, 2014 | | | | | | | | | | | | | | | | | Joint revolving credit facility(1) | | $ | 1,250 | | | $ | 1,250 | | | $ | — | | | $ | — | | Joint revolving credit facility(2) | | | 250 | | | | 111 | | | | — | | | | 139 | | Total | | $ | 1,500 | | | $ | 1,361 | (3) | | $ | — | | | $ | 139 | | At December 31, 2013 | | | | | | | | | | | | | | | | | Joint revolving credit facility(1) | | $ | 1,000 | | | $ | 842 | | | $ | — | | | $ | 158 | | Joint revolving credit facility(2) | | | 250 | | | | — | | | | 1 | | | | 249 | | Total | | $ | 1,250 | | | $ | 842 | (3) | | $ | 1 | | | $ | 407 | |
| (1) | Effective September 2013,In May 2014, this credit facility was amended and restated and the maturity date was extended from September 20172018 to September 2018.April 2019. This |
| credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year. In July 2014, Virginia Power increased its sub-limit from $1.0 billion to $1.25 billion. In January 2015, Virginia Power increased its sub-limit on this facility from $1.25 billion to $1.5 billion. |
| (2) | Effective September 2013,In May 2014, this credit facility was amended and restated and the maturity date for $400 million of the $500 million committed capacity was extended from September 20172018 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018.April 2019. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year. |
| (3) | The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.33%0.36% and 0.47%0.33% at December 31, 20132014 and 2012,2013, respectively. |
In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility. Effective September 2013,In May 2014, this credit facility was amended and restated and the maturity date was extended from September 20172018 to September 2018.April 2019. As of December 31, 2013,2014, this facility supports approximately $119 million of certain variable rate tax-exempt financings of Virginia Power. Dominion Gas Dominion Gas’s short-term financing is supported by the two joint revolving credit facilities discussed above with Dominion and Virginia Power, to which Dominion Gas was added as a borrower in May 2014. Dominion Gas’ current sub-limit under the $4 billion credit facility is $500 million, all of which was available at December 31, 2014, and can be increased or decreased multiple times per year, up to a maximum of $1 billion. Dominion Gas’ current sub-limit under the $500 million credit facility is $0 and can also be increased or decreased multiple times per year. The maturity date for both facilities is April 2019. In December 2014, Dominion Gas entered into a commercial paper program pursuant to which it began accessing the commercial paper markets in January 2015. Dominion Gas’ current sub-limit under the $4 billion credit facility of $500 million is being used to support these commercial paper issuances.
NOTE 17. LONG-T-ERMTERM DEBT | | | | | | | | | | | | | | At December 31, | | 2013
Weighted-
average
Coupon(1) | | | 2013 | | | 2012 | | | (millions, except percentages) | | | | | | | | | | Virginia Electric and Power Company: | | | | | | | | | | | | | Unsecured Senior Notes: | | | | | | | | | | | | | 1.2% to 8.625%, due 2013 to 2018 | | | 5.09 | % | | $ | 2,138 | | | $ | 2,306 | | 2.75% to 8.875%, due 2019 to 2043 | | | 5.25 | % | | | 4,993 | | | | 3,408 | | Tax-Exempt Financings(2): | | | | | | | | | | | | | Variable rates, due 2016 to 2041 | | | 0.98 | % | | | 606 | | | | 454 | | 1.5% to 5.6%, due 2022 to 2040 | | | 3.16 | % | | | 306 | | | | 508 | | Virginia Electric and Power Company total principal | | | | | | $ | 8,043 | | | $ | 6,676 | | Securities due within one year | | | 4.10 | % | | | (58 | ) | | | (418 | ) | Unamortized discount and premium, net | | | | | | | (11 | ) | | | (7 | ) | Virginia Electric and Power Company total long-term debt | | | | | | $ | 7,974 | | | $ | 6,251 | | Dominion Resources, Inc.: | | | | | | | | | | | | | Unsecured Senior Notes: | | | | | | | | | | | | | Variable rates, due 2013 and 2014 | | | 0.37 | % | | $ | 400 | | | $ | 400 | | 1.4% to 7.195%, due 2013 to 2018 | | | 4.03 | % | | | 3,291 | | | | 3,541 | | 2.75% to 8.875%, due 2019 to 2042(3) | | | 5.64 | % | | | 4,599 | | | | 4,599 | | Unsecured Convertible Senior Notes, 2.125%, due 2023(4) | | | | | | | 43 | | | | 82 | | Tax-Exempt Financing, variable rate, due 2041(5) | | | 1.12 | % | | | 75 | | | | — | | Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031 | | | 8.40 | % | | | 10 | | | | 268 | | Enhanced Junior Subordinated Notes: | | | | | | | | | | | | | 7.5% and 8.375%, due 2064 and 2066 | | | 8.11 | % | | | 985 | | | | 985 | | Variable rate, due 2066 | | | 2.58 | % | | | 380 | | | | 380 | | Remarketable Subordinated Notes, 1.07% and 1.18%, due 2019 and 2021 | | | 1.13 | % | | | 1,100 | | | | — | | Unsecured Debentures and Senior Notes(6): | | | | | | | | | | | | | 5.0% and 6.625%, due 2013 and 2014 | | | 5.00 | % | | | 600 | | | | 622 | | 6.8% and 6.875%, due 2026 and 2027 | | | 6.81 | % | | | 89 | | | | 89 | | Dominion Gas Holdings, LLC: | | | | | | | | | | | | | Unsecured Senior Notes, 1.05% to 4.8%, due 2016 to 2043 | | | 3.13 | % | | | 1,200 | | | | — | | Dominion Energy, Inc.: | | | | | | | | | | | | | Secured Senior Notes: | | | | | | | | | | | | | 5.03% to 5.78%, due 2013(7) | | | | | | | — | | | | 842 | | 7.33%, due 2020(8) | | | | | | | — | | | | 145 | | Tax-Exempt Financings: | | | | | | | | | | | | | 2.25% to 5.75%, due 2033 to 2042(9) | | | 2.38 | % | | | 27 | | | | 284 | | Variable rate, due 2041(5) | | | | | | | — | | | | 75 | | Virginia Electric and Power Company total principal (from above) | | | | | | | 8,043 | | | | 6,676 | | Dominion Resources, Inc. total principal | | | | | | $ | 20,842 | | | $ | 18,988 | | Fair value hedge valuation(10) | | | | | | | 55 | | | | 93 | | Securities due within one year(11) | | | 2.95 | % | | | (1,519 | ) | | | (2,223 | ) | Unamortized discount and premium, net | | | | | | | (48 | ) | | | (7 | ) | Dominion Resources, Inc. total long-term debt | | | | | | $ | 19,330 | | | $ | 16,851 | |
| | | | | | | | | | | | | | At December 31, | | 2014
Weighted- average Coupon(1) | | | 2014 | | | 2013 | | | (millions, except percentages) | | | | | | | | | | Dominion Gas Holdings, LLC: | | | | | | | | | | | | | Unsecured Senior Notes: | | | | | | | | | | | | | 1.05% and 2.5%, due 2016 and 2019 | | | 1.82 | % | | $ | 850 | | | $ | 400 | | 3.55% to 4.8%, due 2023 to 2044 | | | 4.15 | % | | | 1,750 | | | | 800 | | Dominion Gas Holdings, LLC total principal | | | | | | $ | 2,600 | | | $ | 1,200 | | Unamortized discount | | | | | | | (6 | ) | | | (2 | ) | Dominion Gas Holdings, LLC total long-term debt | | | | | | $ | 2,594 | | | $ | 1,198 | | Virginia Electric and Power Company: | | | | | | | | | | | | | Unsecured Senior Notes: | | | | | | | | | | | | | 1.2% to 8.625%, due 2015 to 2019 | | | 5.06 | % | | $ | 2,471 | | | $ | 2,488 | | 2.75% to 8.875%, due 2022 to 2044 | | | 5.07 | % | | | 5,592 | | | | 4,643 | | Tax-Exempt Financings(2): | | | | | | | | | | | | | Variable rates, due 2016 to 2041 | | | 0.93 | % | | | 606 | | | | 606 | | 0.70% to 5.6%, due 2022 to 2040 | | | 2.86 | % | | | 266 | | | | 306 | | Virginia Electric and Power Company total principal | | | | | | $ | 8,935 | | | $ | 8,043 | | Securities due within one year | | | 5.39 | % | | | (211 | ) | | | (58 | ) | Unamortized discount and premium, net | | | | | | | 2 | | | | (11 | ) | Virginia Electric and Power Company total long-term debt | | | | | | $ | 8,726 | | | $ | 7,974 | | Dominion Resources, Inc.: | | | | | | | | | | | | | Unsecured Senior Notes: | | | | | | | | | | | | | Variable rates, due 2014 and 2015 | | | 0.36 | % | | $ | 400 | | | $ | 400 | | 1.25% to 8.875%, due 2014 to 2019 | | | 3.17 | % | | | 3,150 | | | | 4,391 | | 2.75% to 7.0%, due 2021 to 2044(3) | | | 4.93 | % | | | 4,449 | | | | 3,499 | | Unsecured Convertible Senior Notes, 2.125%, due 2023 | | | | | | | — | | | | 43 | | Tax-Exempt Financing, variable rate, due 2041 | | | 1.10 | % | | | 75 | | | | 75 | | Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 8.4%, due 2031 | | | 8.40 | % | | | 10 | | | | 10 | | Enhanced Junior Subordinated Notes: | | | | | | | | | | | | | 5.75% to 8.375%, due 2054 to 2066 | | | 6.28 | % | | | 985 | | | | 985 | | Variable rate, due 2066 | | | 2.54 | % | | | 380 | | | | 380 | | Remarketable Subordinated Notes, 1.07% to 1.50%, due 2019 to 2021 | | | 1.30 | % | | | 2,100 | | | | 1,100 | | Unsecured Debentures and Senior Notes(4): | | | | | | | | | | | | | 5.0% due 2014 | | | | | | | — | | | | 600 | | 6.8% and 6.875%, due 2026 and 2027 | | | 6.81 | % | | | 89 | | | | 89 | | Dominion Energy, Inc.: | | | | | | | | | | | | | Tax-Exempt Financing, 2.375%, due 2033 | | | 2.38 | % | | | 27 | | | | 27 | | Dominion Gas Holdings, LLC total principal (from above) | | | | | | | 2,600 | | | | 1,200 | | Virginia Electric and Power Company total principal (from above) | | | | | | | 8,935 | | | | 8,043 | | Dominion Resources, Inc. total principal | | | | | | $ | 23,200 | | | $ | 20,842 | | Fair value hedge valuation(5) | | | | | | | 19 | | | | 55 | | Securities due within one year(6) | | | 3.30 | % | | | (1,375 | ) | | | (1,519 | ) | Unamortized discount and premium, net | | | | | | | (39 | ) | | | (48 | ) | Dominion Resources, Inc. total long-term debt | | | | | | $ | 21,805 | | | $ | 19,330 | |
| (1) | Represents weighted-average coupon rates for debt outstanding as of December 31, 2013.2014. |
| (2) | These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. Certain variable rate tax-exempt financings are supported by a $120 million credit facility that terminates in September 2018.April 2019. |
| (3) | At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 and $600 million of Dominion’s 8.875% senior notes due 2019 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015 and January2015. As a result, at December 31, 2014, respectively.the notes were included in Securities due within one year in the Consolidated Balance Sheets. |
| (4) | Convertible into a combination of cash and shares of Dominion’s common stock at any time when the closing price of common stock equals 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter. At the option of holders on December 15, 2018, these securities are subject to redemption at 100% of the principal amount plus accrued interest. These senior notes have been callable by Dominion since December 15, 2011. |
(5) | Debt issued by the MDFA on behalf of Brayton Point. In connection with the sale of Brayton Point, the sole obligor under the bonds was changed from Brayton Point to Dominion in June 2013. |
Combined Notes to Consolidated Financial Statements, Continued
(6) | Represents debt assumed by Dominion from the merger of its former CNG subsidiary. |
(7) | Juniper notes issued in 2004 and consolidated in October 2011 due to Dominion becoming the primary beneficiary of this VIE. This amount excludes $18 million of unamortized premium in 2012. The debt was non-recourse to Dominion and was secured by Juniper’s assets. Dominion’s purchase of Fairless in August 2013 resulted in the removal of the debt from Dominion’s Consolidated Balance Sheet. See Note 15 for additional information. |
(8) | Represented debt associated with Kincaid. The debt was non-recourse to Dominion and was secured by the facility’s assets and revenue. In connection with the sale of Kincaid, the notes were redeemed in May 2013 for approximately $185 million, including a make-whole premium and accrued interest. |
(9) | In 2012 included debt issued by the MDFA on behalf of Brayton Point. In connection with the sale of Brayton Point, three series of bonds totaling approximately $257 million were defeased in June 2013. In June 2013, Brayton Point delivered approximately $284 million to fund an irrevocable trust for the purpose of paying maturing principal and interest due through and including the earliest redemption dates of the bonds in 2016 and 2019. |
(10)(5) | Represents the valuation of certain fair value hedges associated with Dominion’s fixed rate debt. |
(11)(6) | Includes $14$4 million fair value hedge valuation in 20132014 and $23$14 million of net unamortized premium and fair value hedge valuation in 2012.2013. |
Combined Notes to Consolidated Financial Statements, Continued Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2013,2014, were as follows: | | | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | Thereafter | | Total | | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 | | Thereafter | | Total | | | (millions, except percentages) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion Gas | | | $ | — | | | $ | 400 | | | $ | — | | | $ | — | | | $ | 450 | | | $ | 1,750 | | | $ | 2,600 | | Weighted-average Coupon | | | | | 1.05 | % | | | 2.50 | % | | | 4.15 | % | | Virginia Power | | $ | 58 | | | $ | 211 | | | $ | 476 | | | $ | 679 | | | $ | 850 | | | $ | 5,769 | | | $ | 8,043 | | | $ | 211 | | | $ | 476 | | | $ | 679 | | | $ | 850 | | | $ | 350 | | | $ | 6,369 | | | $ | 8,935 | | Weighted-average Coupon | | | 4.10 | % | | | 5.39 | % | | | 5.25 | % | | | 5.44 | % | | | 4.17 | % | | | 4.78 | % | | | | 5.39 | % | | | 5.24 | % | | | 5.43 | % | | | 4.17 | % | | | 5.00 | % | | | 4.64 | % | | | Dominion | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unsecured Senior Notes | | $ | 1,465 | | | $ | 960 | | | $ | 1,752 | | | $ | 1,303 | | | $ | 1,350 | | | $ | 10,523 | | | $ | 17,353 | | | Unsecured Senior Notes(1) | | | $ | 861 | | | $ | 1,308 | | | $ | 1,354 | | | $ | 1,350 | | | $ | 2,000 | | | $ | 11,878 | | | $ | 18,751 | | Tax-Exempt Financings | | | 40 | | | | — | | | | 19 | | | | 75 | | | | — | | | | 880 | | | | 1,014 | | | | — | | | | 19 | | | | 75 | | | | — | | | | — | | | | 880 | | | | 974 | | Unsecured Junior Subordinated Notes Payable to Affiliated Trusts | | | — | | | | — | | | | — | | | | — | | | | — | | | | 10 | | | | 10 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 10 | | | | 10 | | Enhanced Junior Subordinated Notes | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1,365 | | | | 1,365 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1,365 | | | | 1,365 | | Remarketable Subordinated Notes | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1,100 | | | | 1,100 | | | | — | | | | — | | | | — | | | | — | | | | 550 | | | | 1,550 | | | | 2,100 | | Total | | $ | 1,505 | | | $ | 960 | | | $ | 1,771 | | | $ | 1,378 | | | $ | 1,350 | | | $ | 13,878 | | | $ | 20,842 | | | $ | 861 | | | $ | 1,327 | | | $ | 1,429 | | | $ | 1,350 | | | $ | 2,550 | | | $ | 15,683 | | | $ | 23,200 | | Weighted-average Coupon | | | 2.95 | % | | | 4.45 | % | | | 3.51 | % | | | 4.55 | % | | | 4.99 | % | | | 4.90 | % | | | | 2.14 | % | | | 2.86 | % | | | 3.27 | % | | | 4.99 | % | | | 3.09 | % | | | 4.39 | % | |
Dominion’s and Virginia Power’s
| (1) | At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015. As a result, at December 31, 2014, the notes were included in Securities due within one year in the Consolidated Balance Sheets. |
The Companies short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2013,2014, there were no events of default under these covenants. Senior Note Redemptions In FebruaryAs part of Dominion’s Liability Management Exercise, in December 2014, Virginia Power issued $350Dominion redeemed the following outstanding series of senior notes: 2005 Series C 5.15% Senior Notes due 2015, 2004 Series A 5.20% Senior Notes due 2016, 2006 Series A 5.60% Senior Notes due 2016, 2007 Series A 6.0% Senior Notes due 2017, and 2008 Series D 8.875% Senior Notes due 2019 with an aggregate outstanding principal of approximately $1.9 billion. The aggregate redemption price paid in December 2014 was approximately $2.2 billion and represents the principal amount outstanding, accrued and unpaid interest and the applicable make-whole premium of $263 million. Total charges for the Liability Management Exercise of $284 million, including the make-whole premium, were recognized and recorded in interest expense in Dominion’s Consolidated Statements of 3.45%Income. Proceeds from Dominion’s issuance of senior notes and $400 millionin November 2014 were used to offset the payment of 4.45% senior notes, that mature in 2024, and 2044, respectively.the redemption price. Also see Convertible Securities called for redemption below.
Convertible Securities At December 31, 2013,As part of Dominion’s Liability Management Exercise, in November 2014, Dominion had $43provided notice to redeem all $22 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominion’s common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. The conversion rate is subject to adjustment without limitation upon certain events such as subdivisions, splits, combinations of common stock or the issuance to all common stock holders of certain common stock rights, warrants or options and certain dividend increases. As of December 31, 2013, the conversion rate had been adjusted to 29.8780 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $33.47, primarily due to individual dividend payments above the level paid at issuance. If the outstanding notes as of December 31, 2013 were all converted, it would result in the issuance of approximately 600 thousand additional shares of common stock. In January 2014, Dominion’s Board of Directors declared dividends payable March 20, 2014 of 60 cents per share of common stock which will increase the conversion rate to 29.9961 effective as of February 26, 2014.
notes. The senior notes arewere eligible for conversion during any calendar quarter when the closing price of Dominion’s common stock was equal to or higher than 120% of the conversion price for at least 20 out of the last 30 consecutive trading days of the preceding quarter, when the notes arewere called for redemption by Dominion and upon the occurrence of certain other conditions. During 2013,2014, the senior notes were eligible for conversionconversion. During the first, second and third quarters of 2014, approximately $39$21 million of the notes were converted by holders into $28$23 million of common stock. TheIn lieu of redemption, holders elected to convert the remaining $22 million of notes in December 2014 into $26 million of common stock. Proceeds from Dominion’s issuance of senior notes are eligible for conversion duringin November 2014 were used to offset the first quarter of 2014. Beginning in 2007, the notes have been eligible for contingent interest if the average trading price as defined in the indenture equals or exceeds 120%portion of the principal amountconversions paid in cash. At December 31, 2014, all of the senior notes. Holders have the right to require Dominion to purchase these senior notes for cash at 100% of the principal amount plus accrued interest in December 2018, or if Dominion undergoes certain fundamental changes. The senior notes have been callable by Dominion since December 15, 2011.converted and none remain outstanding. Junior Subordinated Notes Payable to Affiliated Trusts In previous years, Dominion established several subsidiary capital trusts, each as a finance subsidiary of Dominion, which holds 100% of the voting interests. The trusts sold capital securities representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trusts. In exchange for the funds realized from the sale of the capital securities and common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trusts, Dominion issued various junior subordinated notes. The junior subordinated notes constitute 100% of each capital trust’s assets. Each trust must redeem its capital securities when their respective junior subordinated notes are repaid at maturity or if redeemed prior to maturity.
In January 2013, Dominion repaid its $258 million 7.83% unsecured junior subordinated debentures and redeemed all 250 thousand units of the $250 million 7.83% Dominion Resources Capital Trust I capital securities due December 1, 2027. The securities were redeemed at a price of $1,019.58 per capital security plus accrued and unpaid distributions. The following table provides summary information about the capital securities and junior subordinated notes outstanding as of December 31, 2013:
| | | | | | | | | | | | | | | | | | | Date Established | | Capital Trust | | Units | | | Rate | | | Capital
Securities
Amount | | | Common
Securities
Amount | | | | | | | (thousands) | | | | | | (millions) | | January 2001 | | Dominion Resources Capital Trust III(1) | | | 10 | | | | 8.4 | % | | $ | 10 | | | $ | 0.3 | |
(1) | $10 million—Dominion Resources, Inc. 8.4% Debentures due 1/15/2031 were held as assets by the capital trust. |
Interest charges related to Dominion’s junior subordinated notes payable to affiliated trusts were $1 million for the yearyears ended December 31, 2014 and 2013 and $21 million for the yearsyear ended December 31, 2012 and 2011.2012. Enhanced Junior Subordinated Notes In June 2006 and September 2006, Dominion issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids will bear interest at 7.5% per year until June 30, 2016. Thereafter, they will bear interest at the three-month LIBOR plus 2.825%, reset quarterly. Beginning September 30, 2011, theThe September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly. Previously, interest was fixed at 6.3% per year.
In June 2009, Dominion issued $685 million of 8.375% June 2009 hybrids. The June 2009 hybrids arewere listed on the NYSE under the symbol DRU. In October 2014, Dominion issued $685 million of October 2014 hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly. Dominion may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids. Dominion executed RCCs in connection with its issuance of all of the June 2006 hybrids, described above.the September 2006 hybrids, and the June 2009 hybrids. Under the terms of the RCCs, Dominion covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. In September 2011, Dominion amended the RCCs of the June 2006 hybrids and September 2006 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock issuances from 180 days to 365 days. In July 2014, Dominion amended the RCC of the June 2009 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock or other equity-like issuances from 180 days to 365 days. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price. In December 2011, Dominion purchased and canceled approximately $16 million of the September 2006 hybrids. In February 2012, Dominion launched a tender offer to purchase up to $150 million of additional September 2006 hybrids. In the first quarter of 2012, Dominion purchased and canceled approximately $86$88 million of the September 2006 hybrids primarily as a result of this tender offer, which expired in March 2012. In the second quarterAs part of 2012,Dominion’s Liability Management Exercise, in October 2014, Dominion purchased and canceled approximately $2redeemed all $685 million of the September 2006June 2009 hybrids plus accrued interest with the net proceeds from the issuance of the October 2014 hybrids. AllThe redemption and all purchases were conducted in compliance with the RCC. From time to time, Dominion may reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity and repurchases in the open market, in privately negotiated transactions, through additional tender offers or otherwise.RCCs.
Remarketable Subordinated Notes In June 2013, Dominion issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B 6% Equity Units, initially in the form of Corporate Units. In July 2014, Dominion issued $1 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbols DCUA, DCUB and DCUB,DCUC, respectively. Each Corporate Unit consists of a stock purchase contract and 1/20 interest in a RSN issued by Dominion. The stock purchase contracts obligate the holders to purchase shares of Dominion common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is $50 per Corporate Unit and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion common stock near the settlement date. The RSNs are pledged as collateral to secure the purchase of common stock under the related stock purchase contracts. Dominion makes quarterly interest payments on the RSNs and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. Dominion may defer payments on the stock purchase contracts and the RSNs for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, Dominion may not make any cash distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the RSNs. Dominion has recorded the present value of the stock purchase contract payments as a liability offset by a charge to additional paid-in capital in equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense.
Combined Notes to Consolidated Financial Statements, Continued
In calculating diluted EPS, Dominion applies the treasury stock method to the Equity Units. These securities did not have an effect on diluted EPS for the year ended 2013. Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion will issue between 8.4 million and 9.9 million shares of its common stock in both April 2016 and July 2016.2016 and between 11.5 million and 14.3 million shares in July 2017. A total of 22.540.3 million shares of Dominion’s common stock has been reserved for issuance in connection with the stock purchase contracts. Selected information about Dominion’s Equity Units is presented below: | | Issuance Date | | Units
Issued | | | Total Net
Proceeds | | | Total Long-
term Debt | | | RSN Annual
Interest Rate | | Stock Purchase
Contract Annual
Rate | | Stock Purchase
Contract Liability(1) | | | Stock Purchase
Settlement Date | | | RSN Maturity
Date | | | Units
Issued | | | Total Net
Proceeds | | | Total
Long-term
Debt | | | RSN Annual
Interest Rate | | Stock Purchase
Contract Annual
Rate | | Stock Purchase
Contract Liability(1) | | | Stock Purchase
Settlement Date | | | RSN Maturity
Date | | | (millions, except interest rates) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6/7/2013 | | | 11 | | | $ | 533.5 | | | $ | 550.0 | | | | 1.070 | % | | | 5.055 | % | | $ | 76.7 | | | | 4/1/2016 | | | | 4/1/2021 | | | | 11 | | | $ | 533.5 | | | $ | 550.0 | | | | 1.070 | % | | | 5.055 | % | | $ | 76.7 | | | | 4/1/2016 | | | | 4/1/2021 | | 6/7/2013 | | | 11 | | | $ | 553.5 | | | $ | 550.0 | | | | 1.180 | % | | | 4.820 | % | | $ | 79.3 | | | | 7/1/2016 | | | | 7/1/2019 | | | | 11 | | | $ | 553.5 | | | $ | 550.0 | | | | 1.180 | % | | | 4.820 | % | | $ | 79.3 | | | | 7/1/2016 | | | | 7/1/2019 | | 7/1/2014 | | | | 20 | | | $ | 982.0 | | | $ | 1,000.0 | | | | 1.500 | % | | | 4.875 | % | | $ | 142.8 | | | | 7/1/2017 | | | | 7/1/2020 | |
| (1) | Payments of $66 million and $17 million were made in 2013.2014 and 2013, respectively. The stock purchase contract liability was $216 million and $139 million at December 31, 2013.2014 and 2013, respectively. |
Combined Notes to Consolidated Financial Statements, Continued Regulated NaturalDominion Gas Financing Plans
In September 2013, Dominion announced the formation ofJune 2014, Dominion Gas a first tier wholly-owned subsidiary holding company for the majority of Dominion’s regulated natural gas businesses. Specifically, Dominion transferred direct ownership of East Ohio, DTI and Dominion Iroquois, the latter of which holds a 24.72% general partnership interest in Iroquois,commenced an offer to Dominion Gas on September 30, 2013. Dominion Gas issuedexchange $1.2 billion principal amount of unsecured senior notes that were issued in a private placement in October 2013 and will be2013. The exchange offer satisfied Dominion Gas’ obligations under a registration rights agreement entered into in connection with the primary financing entity for Dominion’s regulated natural gas businesses.issuance of the Dominion Gas expects2013 Senior Notes. The exchange offer did not represent a new financing transaction and there were no proceeds to become an SEC registrant in 2014. Dominion Gas usedwhen the proceeds from this offering to acquire intercompany long-term notes from Dominion and to repay a portion of its intercompany revolving credit agreement balances with Dominion.offer settled in August 2014.
NOTE 18. PREFERRED STOCK Dominion is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 20132014 or 2012.2013. Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference, and had 2.59 million preferred shares issued and outstanding at December 31, 2013 and 2012. Upon involuntary liquidation, dissolution or winding-up of2013. During 2014, Virginia Power redeemed all outstanding series of its preferred stock. Upon redemption, each share would be entitledseries was no longer outstanding for any purpose and dividends ceased to receive $100 plus accrued cumulative dividends. Holdersaccumulate. Presented below is a summary of Virginia Power’s outstandingthe preferred stock are not entitled to voting rights except under certain provisions of the amended and restated articles of incorporation and related provisions of Virginia law restricting corporate action, upon default in dividends or in special statutory proceedings and as required by Virginia law (such as mergers, consolidations, sales of assets, dissolution and changes in voting rights or priorities of preferred stock).
Presented below are the series of Virginia Power preferred stock that were outstanding as of December 31, 2013:redemptions:
| | Dividend | | Issued and
Outstanding
Shares | | Entitled Per Share
Upon Liquidation | | | Total
Shares | | | Redemption
Price per
Share | | | | | (thousands) | | | | | (thousands) | | $5.00 | | | 107 | | | $ | 112.50 | | | | 107 | | | $ | 112.50 | (1) | 4.04 | | | 13 | | | | 102.27 | | | | 13 | | | | 102.27 | (1) | 4.20 | | | 15 | | | | 102.50 | | | | 15 | | | | 102.50 | (1) | 4.12 | | | 32 | | | | 103.73 | | | | 32 | | | | 103.73 | (1) | 4.80 | | | 73 | | | | 101.00 | | | | 73 | | | | 101.00 | (1) | 7.05 | | | 500 | | | | 100.00 | | | | 500 | | | | 100.00 | (1) | 6.98 | | | 600 | | | | 100.00 | | | | 600 | | | | 100.00 | (1) | Flex Money Market Preferred 12/02, Series A | | | 1,250 | | | | 100.00 | (1) | | | 1,250 | | | | 100.00 | (2) | Total | | | 2,590 | | | | | 2,590 | | | |
| (1) | Effective March 20, 2011As part of Dominion’s Liability Management Exercise, in September 2014, Virginia Power provided irrevocable notice to redeem all shares outstanding for each series of preferred stock. In October 2014, the ratestock was reset to 6.12% until March 20, 2014 after whichredeemed at the rate was due to be reset through an auction process. However, inapplicable price per share plus accumulated and unpaid dividends. |
| (2) | In February 2014, Virginia Power provided irrevocable notice to redeem the stock. In March 2014, the stock on March 20, 2014was redeemed at athe applicable price of $100 per share plus accumulated and unpaid dividends.dividends at a rate reset in March 2011 of 6.12%. Dividends ceased accumulating on the stock upon payment of the redemption price, thus the rate was not reset in March 2014. |
NOTE 19. SHAREHOLDERS’ EQUITY Issuance of Common Stock DOMINION Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2012, Dominion began issuing new common shares for these direct stock purchase plans. In January 2014, Dominion began purchasing its common stock on the open market for these plans. In April 2014, Dominion began issuing new common shares for these direct stock purchase plans. During 2013,2014, Dominion issued approximately 5.43.8 million shares of common stock through various programs. Dominion received cash proceeds of $278$205 million from the issuance of 4.72.9 million of such shares through Dominion Direct and employee savings plans. In January 2012,December 2014, Dominion filed a newan SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at the marketat-the-market program. Also in December 2014, Dominion entered into four separate Sales Agency Agreementssales agency agreements to effect sales under the program. However, with the exceptionprogram and pursuant to which it may offer from time to time up to $500 million aggregate amount of issuing approximately $317 million in equity through employee savings plans, direct stock purchase and dividend reinvestment plans, converted securities and other employee and director benefit plans, Dominion did not issueits common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the NYSE at market prices or in 2013.such other transactions as are agreed upon by Dominion and the sales agents and in conformance with applicable securities laws. At December 31, 2014, a total of 7 million shares of Dominion’s common stock was reserved for issuance in connection with this program. In 2015, Dominion provided sales instructions to one of the sales agents and has issued 2.7 million shares through at-the-market issuances and received cash proceeds of $207 million, net of fees and commissions paid of $2 million. Following these issuances, Dominion has the ability to issue up to $291 million of stock under the 2014 sales agency agreements.
VIRGINIA POWER In 2014, 2013 2012 and 2011,2012, Virginia Power did not issue any shares of its common stock to Dominion. DOMINION GAS On September 30, 2013, Dominion contributed its wholly-owned subsidiaries DTI, East Ohio and Dominion Iroquois to Dominion Gas in exchange for 100% of its limited liability company membership interests. Shares Reserved for Issuance At December 31, 2013,2014, Dominion had approximately 4856 million shares reserved and available for issuance for Dominion Direct®, employee stock awards, employee savings plans, director stock compensation plans, contingent convertible senior notesan at-the-market program and issuance in connection with stock purchase contracts. See Note 17 for more information. Repurchase of Common Stock Dominion did not repurchase any shares in 20132014 or 20122013 and does not plan to repurchase shares during 2014,2015, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, and purchases of common stock on the open market in 2014 for direct stock purchase plans, which do not count against its stock repurchase authorization.
Combined Notes to Consolidated Financial Statements, Continued Accumulated Other Comprehensive Income (Loss) Presented in the table below is a summary of AOCI by component: | | At December 31, | | 2013 | | 2012 | | | 2014 | | 2013 | | | (millions) | | | | | | | | | | | Dominion | | | | | | | | | Net deferred losses on derivatives-hedging activities, net of tax of $196 and $87 | | $ | (288 | ) | | $ | (122 | ) | | Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(307) and $(206) | | | 474 | | | | 326 | | | Net unrecognized pension and other postretirement benefit costs, net of tax of $365 and $745 | | | (510 | ) | | | (1,081 | ) | | Net deferred losses on derivatives-hedging activities, net of tax of $116 and $196 | | | $ | (178 | ) | | $ | (288 | ) | Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(333) and $(307) | | | | 548 | | | | 474 | | Net unrecognized pension and other postretirement benefit costs, net of tax of $530 and $365 | | | | (782 | ) | | | (510 | ) | Other comprehensive loss from equity method investees, net of tax of $3 and $— | | | | (4 | ) | | | — | | Total AOCI | | $ | (324 | ) | | $ | (877 | ) | | $ | (416 | ) | | $ | (324 | ) | | Virginia Power | | | | | | | | | Net deferred losses on derivatives-hedging activities, net of tax of $— and $3 | | $ | — | | | $ | (6 | ) | | Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(30) and $(19) | | | 48 | | | | 31 | | | Net deferred losses on derivatives-hedging activities, net of tax of $4 and $— | | | $ | (7 | ) | | $ | — | | Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(35) and $(30) | | | | 57 | | | | 48 | | Total AOCI | | $ | 48 | | | $ | 25 | | | $ | 50 | | | $ | 48 | | Dominion Gas | | | | | | Net deferred gains (losses) on derivatives-hedging activities, net of tax of $11 and $(1) | | | $ | (20 | ) | | $ | 3 | | Net unrecognized pension and other postretirement benefit costs, net of tax of $46 and $43 | | | | (66 | ) | | | (61 | ) | Total AOCI | | | $ | (86 | ) | | $ | (58 | ) |
DOMINION The following table presents Dominion’s changes in AOCI by component, net of tax: | | | | Deferred
gains and
losses on
derivatives-
hedging
activities | | Unrealized
gains and
losses on
investment
securities | | Unrecognized
pension and
other
postretirement
benefit costs | | Total | | | Deferred gains
and losses on
derivatives-
hedging
activities | | Unrealized gains and
losses on
investment
securities | | Unrecognized
pension and
other
postretirement
benefit costs | | Other
comprehensive
loss from equity method
investees | | Total | | | (millions) | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2014 | | | | | | | | | | | | Beginning balance | | | $ | (288 | ) | | $ | 474 | | | $ | (510 | ) | | $ | — | | | $ | (324 | ) | Other comprehensive income before reclassifications: gains (losses) | | | | 17 | | | | 128 | | | | (305 | ) | | | (4 | ) | | | (164 | ) | Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) | | | | 93 | | | | (54 | ) | | | 33 | | | | — | | | | 72 | | Net current period other comprehensive income (loss) | | | | 110 | | | | 74 | | | | (272 | ) | | | (4 | ) | | | (92 | ) | Ending balance | | | $ | (178 | ) | | $ | 548 | | | $ | (782 | ) | | $ | (4 | ) | | $ | (416 | ) | Year Ended December 31, 2013 | | | | | | | | | | | | | | | | | | | Beginning balance | | $ | (122 | ) | | $ | 326 | | | $ | (1,081 | ) | | $ | (877 | ) | | $ | (122 | ) | | $ | 326 | | | $ | (1,081 | ) | | $ | — | | | $ | (877 | ) | Other comprehensive income before reclassifications: gains (losses) | | | (243 | ) | | | 203 | | | | 516 | | | | 476 | | | | (243 | ) | | | 203 | | | | 516 | | | | — | | | | 476 | | Amounts reclassified from accumulated other comprehensive income (gains) losses(1): | | | 77 | | | | (55 | ) | | | 55 | | | | 77 | | | Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) | | | | 77 | | | | (55 | ) | | | 55 | | | | — | | | | 77 | | Net current period other comprehensive income (loss) | | | (166 | ) | | | 148 | | | | 571 | | | | 553 | | | | (166 | ) | | | 148 | | | | 571 | | | | — | | | | 553 | | Ending balance | | $ | (288 | ) | | $ | 474 | | | $ | (510 | ) | | $ | (324 | ) | | $ | (288 | ) | | $ | 474 | | | $ | (510 | ) | | $ | — | | | $ | (324 | ) |
| (1) | See table below for details about these reclassifications. |
The following table presents Dominion’s reclassifications out of AOCI by component: | | | | | | | | Details about AOCI components | | Amounts reclassified
from AOCI | | | Affected line item in the Consolidated Statements of
Income | | (millions) | | | | | | Year Ended December 31, 2014 | | | | | | | Deferred (gains) and losses on derivatives-hedging activities: | | | | | | | Commodity contracts | | $ | 130 | | | Operating revenue | | | | 13 | | | Purchased gas | | | | (7 | ) | | Electric fuel and other
energy-related purchases | Interest rate contracts | | | 16 | | | Interest and related
charges | Total | | | 152 | | | | Tax | | | (59 | ) | | Income tax expense | Total, net of tax | | $ | 93 | | | | Unrealized (gains) and losses on investment securities: | | | | | | | Realized (gain) loss on sale of securities | | $ | (100 | ) | | Other income | Impairment | | | 13 | | | Other income | Total | | | (87 | ) | | | Tax | | | 33 | | | Income tax expense | Total, net of tax | | $ | (54 | ) | | | Unrecognized pension and other postretirement benefit costs: | | | | | | | Prior-service costs (credits) | | $ | (12 | ) | | Other operations and
maintenance | Actuarial losses | | | 69 | | | Other operations and
maintenance | Total | | | 57 | | | | Tax | | | (24 | ) | | Income tax expense | Total, net of tax | | $ | 33 | | | | Year Ended December 31, 2013 | | | | | | | Deferred (gains) and losses on derivatives-hedging activities: | | | | | | | Commodity contracts | | $ | 58 | | | Operating revenue | | | | 47 | | | Purchased gas | | | | 10 | | | Electric fuel and other
energy-related purchases | Interest rate contracts | | | 15 | | | Interest and related
charges | Total | | | 130 | | | | Tax | | | (53 | ) | | Income tax expense | Total, net of tax | | $ | 77 | | | |
| | | | | | | | Details about AOCI components | | Amounts reclassified
from AOCI | | | Affected line item in the Consolidated Statements of
Income | | (millions) | | | | | | Unrealized (gains) and losses on investment securities: | | | | | | | Realized (gain) loss on sale of securities | | $ | (98 | ) | | Other
income | Impairment | | | 8 | | | Other
income | Total | | | (90 | ) | | | Tax | | | 35 | | | Income tax
expense | Total, net of tax | | $ | (55 | ) | | | Unrecognized pension and other postretirement benefit costs: | | | | | | | Prior-service costs (credits) | | $ | (8 | ) | | Other
operations
and
maintenance | Actuarial losses | | | 102 | | | Other
operations
and
maintenance | Total | | | 94 | | | | Tax | | | (39 | ) | | Income tax
expense | Total, net of tax | | $ | 55 | | | |
Combined Notes to Consolidated Financial Statements, Continued The following table presents Dominion’s reclassifications out of AOCI by component:VIRGINIA POWER
| | | | | | | | Details about AOCI components | | Amounts reclassified
from AOCI | | | Affected line item in the
Consolidated Statements of
Income | | (millions) | | | | | | Year Ended December 31, 2013 | | | | | | | Deferred (gains) and losses on derivatives-hedging activities: | | | | | | | Commodity contracts | | $ | 58 | | | Operating revenue | | | | 47 | | | Purchased gas | | | | 10 | | | Electric fuel and other energy-related purchases | Interest rate contracts | | | 15 | | | Interest and related charges | Total | | | 130 | | | | Tax | | | (53 | ) | | Income tax expense | Total, net of tax | | $ | 77 | | | | Unrealized (gains) and losses on investment securities: | | | | | | | Realized (gain) loss on sale of securities | | $ | (98 | ) | | Other income | Impairment | | | 8 | | | Other income | Total | | | (90 | ) | | | Tax | | | 35 | | | Income tax expense | Total, net of tax | | $ | (55 | ) | | | Unrecognized pension and other postretirement benefit costs: | | | | | | | Prior-service costs (credits) | | $ | (8 | ) | | Other operations and maintenance | Actuarial losses | | | 102 | | | Other operations and maintenance | Total | | | 94 | | | | Tax | | | (39 | ) | | Income tax expense | Total, net of tax | | $ | 55 | | | |
The following table presents Virginia Power’s changes in AOCI by component, net of tax: | | | | Deferred gains
and losses on
derivatives-
hedging
activities | | Unrealized gains
and losses on
nuclear
decommissioning
trust funds | | Total | | | Deferred gains
and losses on
derivatives-
hedging
activities | | Unrealized gains
and losses on
investment
securities | | Total | | | (millions) | | | | | | | | | | | | | | | Year Ended December 31, 2014 | | | | | | | | Beginning balance | | | $ | — | | | $ | 48 | | | $ | 48 | | Other comprehensive income before reclassifications: gains (losses) | | | | (4 | ) | | | 15 | | | | 11 | | Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) | | | | (3 | ) | | | (6 | ) | | | (9 | ) | Net current period other comprehensive income (loss) | | | | (7 | ) | | | 9 | | | | 2 | | Ending balance | | | $ | (7 | ) | | $ | 57 | | | $ | 50 | | Year Ended December 31, 2013 | | | | | | | | | | | | | Beginning balance | | $ | (6 | ) | | $ | 31 | | | $ | 25 | | | $ | (6 | ) | | $ | 31 | | | $ | 25 | | Other comprehensive income before reclassifications: gains (losses) | | | 6 | | | | 20 | | | | 26 | | | | 6 | | | | 20 | | | | 26 | | Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) | | | — | | | | (3 | ) | | | (3 | ) | | Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) | | | | — | | | | (3 | ) | | | (3 | ) | Net current period other comprehensive income (loss) | | | 6 | | | | 17 | | | | 23 | | | | 6 | | | | 17 | | | | 23 | | Ending balance | | $ | — | | | $ | 48 | | | $ | 48 | | | $ | — | | | $ | 48 | | | $ | 48 | |
| (1) | See table below for details about these reclassifications. |
The following table presents Virginia Power’s reclassifications out of AOCI by component: | | Details about AOCI components | | Amounts
reclassified
from AOCI | | Affected line item in the
Consolidated Statements of
Income | | Amounts reclassified
from AOCI | | Affected line item in the
Consolidated Statements of
Income | | (millions) | | | | | | | Year Ended December 31, 2014 | | | | | | (Gains) losses on cash flow hedges: | | | | | | Commodity contracts | | | $ | (5 | ) | | Electric fuel and other energy related purchases | Total | | | | (5 | ) | | | Tax | | | | 2 | | | Income tax expense | Total, net of tax | | | $ | (3 | ) | | Unrealized (gains) and losses on investment securities: | | | | | | Realized (gain) loss on sale of securities | | | $ | (10 | ) | | Other income | Total | | | | (10 | ) | | | Tax | | | | 4 | | | Income tax expense | Total, net of tax | | | $ | (6 | ) | | Year Ended December 31, 2013 | | | | | | | | | Unrealized (gains) and losses on investment securities: | | | | | | | | | Realized (gain) loss on sale of securities | | $ | (6 | ) | | Other income | | $ | (6 | ) | | Other income | Impairment | | | 1 | | | Other income | | | 1 | | | Other income | Total | | | (5 | ) | | | | | (5 | ) | | | Tax | | | 2 | | | Income tax expense | | | 2 | | | Income tax expense | Total, net of tax | | $ | (3 | ) | | | $ | (3 | ) | |
DOMINION GAS The following table presents Dominion Gas’ changes in AOCI by component, net of tax: | | | | | | | | | | | | | | | | Deferred gains
and losses on
derivatives-
hedging
activities | | | Unrecognized pension and
other
postretirement
benefit costs | | | Total | | | (millions) | | | | | | | | | | Year Ended December 31, 2014 | | | | | | | | | | | | | Beginning balance | | $ | 3 | | | $ | (61 | ) | | $ | (58 | ) | Other comprehensive income before reclassifications: gains (losses) | | | (31 | ) | | | (10 | ) | | | (41 | ) | Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) | | | 8 | | | | 5 | | | | 13 | | Net current period other comprehensive income (loss) | | | (23 | ) | | | (5 | ) | | | (28 | ) | Ending balance | | $ | (20 | ) | | $ | (66 | ) | | $ | (86 | ) | Year Ended December 31, 2013 | | | | | | | | | | | | | Beginning balance | | $ | (47 | ) | | $ | (93 | ) | | $ | (140 | ) | Other comprehensive income before reclassifications: gains (losses) | | | 39 | | | | 26 | | | | 65 | | Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) | | | 11 | | | | 6 | | | | 17 | | Net current period other comprehensive income (loss) | | | 50 | | | | 32 | | | | 82 | | Ending balance | | $ | 3 | | | $ | (61 | ) | | $ | (58 | ) |
| (1) | See table below for details about these reclassifications. |
The following table presents Dominion Gas’ reclassifications out of AOCI by component: | | | | | | | Details about AOCI
components | | Amounts reclassified
from AOCI | | | Affected line item in the
Consolidated Statements of Income | | (millions) | | | | | | Year Ended December 31, 2014 | | | | | | | Deferred (gains) and losses on derivatives-hedging activities: | | | | | | | Commodity contracts | | $ | (2 | ) | | Operating revenue | | | | 14 | | | Purchased gas | | | | | 1 | | | Interest and related charges | Total | | | 13 | | | | Tax | | | (5 | ) | | Income tax expense | Total, net of tax | | $ | 8 | | | | Unrecognized pension and other postretirement benefit costs: | | | | | | | Prior service costs | | $ | 1 | | | Other operations and maintenance | Actuarial losses | | | 7 | | | Other operations and maintenance | Total | | | 8 | | | | Tax | | | (3 | ) | | Income tax expense | Total, net of tax | | $ | 5 | | | | Year Ended December 31, 2013 | | | | | | | Deferred (gains) and losses on derivatives-hedging activities: Commodity contracts | | $ | 2 | | | Operating revenue | | | | | 14 | | | Purchased gas | Total | | | 16 | | | | Tax | | | (5 | ) | | Income tax expense | Total, net of tax | | $ | 11 | | | | Unrecognized pension and other postretirement benefit costs: | | | | | | | Prior service costs | | $ | 1 | | | Other operations and maintenance | Actuarial losses | | | 9 | | | Other operations and maintenance | Total | | | 10 | | | | Tax | | | (4 | ) | | Income tax expense | Total, net of tax | | $ | 6 | | | |
Combined Notes to Consolidated Financial Statements, Continued Stock-Based Awards The 2005 and 2014 Incentive Compensation Plan permitsPlans permit stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of boththese plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. At December 31, 2013,2014, approximately 3231 million shares were available for future grants under these plans. Dominion measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion’s results for the years ended December 31, 2014, 2013 and 2012 and 2011 include $39 million, $31 million, $25 million, and $39$25 million, respectively, of compensation costs and $14 million, $11 million, $8 million, and $13$8 million, respectively of income tax benefits related to Dominion’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. Excess tax benefits are classified as a financing cash flow. During the years ended December 31, 2014, 2013, 2012 and 2011,2012, Dominion realized less than $1 million, $10less than $1 million and $2$10 million, respectively, of excess tax benefits from the vesting of restricted stock awards and exercise of stock options.
STOCK OPTIONS
The following table provides a summary of changes in amounts of stock options outstanding as of and for the years ended December 31, 2012 and 2011. There were no stock options outstanding in 2013. No options were granted under any plan in 2013, 2012 or 2011.
| | | | | | | | | | | | | | | | | | Shares | | | Weighted - average
Exercise Price | | | Weighted - average Remaining Contractual Life | | Aggregated
Intrinsic
Value(1) | | | | | (thousands) | | | (years) | | (millions) | | Outstanding and exercisable at December 31, 2010 | | | 1,810 | | | $ | 31.76 | | | | | | 20 | | Exercised | | | (1,174 | ) | | $ | 32.46 | | | | | $ | 17 | | Forfeited/expired | | | (8 | ) | | $ | 31.57 | | | | | | | | Outstanding and exercisable at December 31, 2011 | | | 628 | | | $ | 30.81 | | | | | $ | 14 | | Exercised | | | (622 | ) | | $ | 30.79 | | | | | $ | 13 | | Forfeited/expired | | | (6 | ) | | $ | 32.26 | | | | | | | | Outstanding and exercisable at December 31, 2012 | | | — | | | $ | — | | | | | $ | — | |
(1) | Intrinsic value represents the difference between the exercise price of the option and the market value of Dominion’s stock. |
Dominion issues new shares to satisfy any stock option exercises. Dominion received cash proceeds from the exercise of stock options of approximately $19 million, and $38 million in the years ended December 31, 2012 and 2011, respectively.
RESTRICTED STOCK Restricted stock grants are made to officers under Dominion’s LTIP and may also be granted to certain key non-officer employees from time to time. The fair value of Dominion’s restricted stock awards is equal to the closing price of Dominion’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2014, 2013 2012 and 2011:2012: | | | | Shares | | Weighted
- average
Grant Date
Fair Value | | | Shares | | Weighted - average Grant Date Fair Value | | | | | (thousands) | | | | | (thousands) | | | | Nonvested at December 31, 2010 | | | 1,476 | | | $ | 38.20 | | | Granted | | | 299 | | | | 43.68 | | | Vested | | | (617 | ) | | | 40.72 | | | Cancelled and forfeited | | | (25 | ) | | | 36.29 | | | Converted from goal-based stock to restricted stock | | | 168 | | | | 30.99 | | | Nonvested at December 31, 2011 | | | 1,301 | | | $ | 37.37 | | | | 1,301 | | | $ | 37.37 | | Granted | | | 390 | | | | 51.14 | | | | 390 | | | | 51.14 | | Vested | | | (596 | ) | | | 33.31 | | | | (596 | ) | | | 33.31 | | Cancelled and forfeited | | | (10 | ) | | | 42.99 | | | | (10 | ) | | | 42.99 | | Nonvested at December 31, 2012 | | | 1,085 | | | $ | 44.46 | | | | 1,085 | | | $ | 44.46 | | Granted | | | 312 | | | | 54.70 | | | | 312 | | | | 54.70 | | Vested | | | (356 | ) | | | 39.00 | | | | (356 | ) | | | 39.00 | | Cancelled and forfeited | | | (34 | ) | | | 51.11 | | | | (34 | ) | | | 51.11 | | Nonvested at December 31, 2013 | | | 1,007 | | | $ | 49.35 | | | | 1,007 | | | $ | 49.35 | | Granted | | | | 354 | | | | 67.98 | | Vested | | | | (278 | ) | | | 44.50 | | Cancelled and forfeited | | | | (18 | ) | | | 53.61 | | Nonvested at December 31, 2014 | | | | 1,065 | | | $ | 56.74 | |
As of December 31, 2013,2014, unrecognized compensation cost related to nonvested restricted stock awards totaled $21$27 million and is expected to be recognized over a weighted-average period of 1.8 years. The fair value of restricted stock awards that vested was $19 million, $20 million, and $30 million in 2014, 2013 and $28 million in 2013, 2012, and 2011, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion stock and the applicable federal, state and local tax withholding rates. GOAL-BASED STOCK Goal-based stock awards are granted under Dominion’s LTIP to officers who have not achieved a certain targeted level of share ownership, in lieu of cash-based performance grants. Goal-based stock awards may also be made to certain key non-officer employees from time to time. Current outstanding goal-based shares include awards granted to officers in February 20122013 and February 2013.2014. The issuance of awards is based on the achievement of two performance metrics during a two-year period: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The actual number of shares issued will vary between zero and 200% of targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is equal to the closing price of Dominion’s stock on the date of grant. Goal-based stock awards granted to key non-officer employees convert to restricted stock at the end of the two-year performance period and generally vest three years from the original grant date. Awards to officers vest at the end of the two-year performance period. All goal-based stock awards are settled by issuing new shares. After the performance period for the February 2010 grants ended on December 31, 2011, the CGN Committee determined the actual performance against metrics established for those awards. For awards to officers, 9 thousand shares of the outstanding goal-based stock awards were converted to 15 thousand non-restricted shares and issued to the officers.
After the performance period for the February 2011 grants ended on December 31, 2012, the CGN Committee determined the actual performance against metrics established for those awards. For awards to officers, 3 thousand shares of the outstanding goal-based stock awards were converted to 2 thousand non-restricted shares and issued to the officers.
Combined Notes to Consolidated Financial Statements, Continued
The following table provides a summary of goal-based stock activity for the years ended December 31, 2014, 2013 2012 and 2011:2012: | | | | Targeted
Number of
Shares | | Weighted
- average
Grant Date
Fair Value | | | Targeted Number of Shares | | Weighted - average Grant Date Fair Value | | | | | (thousands) | | | | | (thousands) | | | | Nonvested at December 31, 2010 | | | 161 | | | $ | 31.79 | | | Granted | | | 3 | | | | 43.54 | | | Vested | | | (20 | ) | | | 34.62 | | | Cancelled and forfeited | | | (132 | ) | | | 30.99 | | | Nonvested at December 31, 2011 | | | 12 | | | $ | 39.19 | | | | 12 | | | $ | 39.19 | | Granted | | | 1 | | | | 52.48 | | | | 1 | | | | 52.48 | | Vested | | | (9 | ) | | | 37.46 | | | | (9 | ) | | | 37.46 | | Nonvested at December 31, 2012 | | | 4 | | | $ | 45.60 | | | | 4 | | | $ | 45.60 | | Granted | | | 4 | | | | 54.17 | | | | 4 | | | | 54.17 | | Vested | | | (2 | ) | | | 43.54 | | | | (2 | ) | | | 43.54 | | Cancelled and forfeited | | | (1 | ) | | | 43.54 | | | | (1 | ) | | | 43.54 | | Nonvested at December 31, 2013 | | | 5 | | | $ | 53.85 | | | | 5 | | | $ | 53.85 | | Granted | | | | 13 | | | | 68.83 | | Vested | | | | (1 | ) | | | 52.48 | | Nonvested at December 31, 2014 | | | | 17 | | | $ | 65.15 | |
At December 31, 2013,2014, the targeted number of shares expected to be issued under the February 20122013 and February 20132014 awards was approximately 517 thousand. In January 2014,2015, the CGN Committee determined the actual performance against metrics established for the February 20122013 awards with a performance period that ended December 31, 2013.2014. Based on that determination, the total number of shares to be issued under the February 20122013 goal-based stock awards was approximately 17 thousand.
As of December 31, 2013,2014, unrecognized compensation cost related to nonvested goal-based stock awards was not material. CASH-BASED PERFORMANCE GRANTS Cash-based performance grants are made to Dominion’s officers under Dominion’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved. In February 2010, a cash-based performance grant was made to officers. A portion of the grant, representing $14 million was paid in December 2011, based on the achievement of two performance metrics during 2010 and 2011: ROIC and TSR relative to that of a peer group of companies. The total amount of the award under the grant was $20 million and the remaining $6 million of the grant was paid in February 2012.
In February 2011, a cash-based performance grant was made to officers. A portion of the grant, representing $6 million was paid in December 2012, based on the achievement of two performance metrics during 2011 and 2012: ROIC and TSR relative to that of a peer group of companies. The total amount of the award under the grant was $8 million and the remaining $2 million of the grant was paid in February 2013. In February 2012, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $8 million was paid in December 2013, based on the achievement of two performance metrics during 2012 and 2013: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total expectedamount of the award under the grant iswas $12 million and the remaining portion of the grant is expected to bewas paid by March 15,in January 2014. At December 31, 2013, a liability of $4 million had been accrued for the remaining portion of the award.
In February 2013, a cash-based performance grant was made to officers. PayoutA portion of the performance grant, is expected to occur by March 15, 2015representing the initial payout of $14 million was paid in December 2014, based on the achievement of two performance metrics during 2013 and 2014: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total expected award under the grant is $21 million and the remaining portion of the grant is expected to be paid by March 15, 2015. At December 31, 2013,2014, a liability of $7 million had been accrued for the remaining portion of the award. In February 2014, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2016 based on the achievement of two performance metrics during 2014 and 2015: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. At December 31, 2014, the targeted amount of the grant was $13 million and a liability of $6$3 million had been accrued for this award. NOTE 20. DIVIDEND RESTRICTIONS The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2013,2014, the Virginia Commission had not restricted the payment of dividends by Virginia Power. The Ohio Commission may prohibit any public service company, including East Ohio, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2014, the Ohio Commission had not restricted the payment of dividends by East Ohio. Certain agreements associated with Dominion’s and Virginia Power’sthe Companies’ credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s or Virginia Power’sthe Companies’ ability to pay dividends or receive dividends from their subsidiaries at December 31, 2013.2014. See Note 17 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes and equity units, initially in the form of corporate units. NOTE 21. EMPLOYEE BENEFIT PLANS DOMINIONDominion and Dominion Gas - Defined Benefit Plans
Dominion provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Gas participates in a number of the Dominion-sponsored retirement plans. Under the terms of its benefit plans, Dominion reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits. Dominion maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension program also provides benefits to certain retired executives under a company-sponsored nonqualified employee benefit plan. The nonqualified plan is funded through contributions to a grantor trust. Dominion also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service. Pension benefits for Dominion Gas employees not represented by collective bargaining units are covered by the Dominion Pension Plan, a defined benefit pension plan sponsored by Dominion that provides benefits to multiple Dominion subsidiaries. Pension benefits for Dominion Gas employees represented by collective bargaining units are covered by separate pension plans for East Ohio and, for DTI, a plan that provides benefits to employees of both DTI and Hope. Employee compensation is the basis for allocating pension costs and obligations between DTI and Hope and determining East Ohio’s share of total pension costs. Retiree healthcare and life insurance benefits for Dominion Gas employees not represented by collective bargaining units are covered by the Dominion Retiree Health and Welfare Plan, a plan sponsored by Dominion that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Retiree healthcare and life insurance benefits for Dominion Gas employees represented by collective bargaining units are covered by separate other postretirement benefit plans for East Ohio and, for DTI, a plan that provides benefits to both DTI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DTI and Hope and determining East Ohio’s share of total other postretirement benefit costs. Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates, mortality rates and the rate of compensation increases.
Combined Notes to Consolidated Financial Statements, Continued Dominion uses December 31 as the measurement date for all of its employee benefit plans.plans, including those in which Dominion Gas participates. Dominion uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost.cost, for all pension plans, including those in which Dominion Gas participates. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized. Dominion’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Aggregate actual returns for Dominion’s pension and other postretirement plan assets were $706 million in 2014 and $959 million in 2013, and $743 million in 2012, versus expected returns of $610 million and $554 million, respectively. Aggregate actual returns for pension and $509other postretirement benefit plan assets for Dominion Gas employees represented by collective bargaining units were $157 million in 2014 and $214 million in 2013, versus expected returns of $138 million and $125 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. The Medicare Act introduced a federal subsidy to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Dominion determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D. Dominion received a federal subsidy of $4 million and $5 million for 2014 and 2013, respectively. Dominion Gas received a federal subsidy of $1 million for each of 20132014 and 2012.2013. Effective January 1, 2013, Dominion changed its method of receiving the subsidy under Medicare Part D for retiree prescription drug coverage from the Retiree Drug Subsidy to the EGWP. This change reduced other postretirement benefit costs by approximately $20 million annually beginning in 2012. As a result of the adoption of the EGWP, Dominion will begin to receive an increased level of Medicare Part D subsidies, in the form of reduced costs rather than a direct reimbursement, over the next few years. In October 2014, the Society of Actuaries published new mortality tables and mortality improvement scales. Such tables and scales are used to develop mortality assumptions for use in determining pension and other postretirement benefit liabilities and expense. Following evaluation of the new tables, Dominion changed its assumption for mortality rates to reflect a generational improvement scale. As a result of this change in assumption, at December 31, 2014 Dominion and Dominion Gas (for employ- ees represented by collective bargaining units) increased their pension benefit obligations by $131 million and $10 million, respectively, and increased their accumulated postretirement benefit obligations by $32 million and $7 million, respectively. This change is expected to increase net periodic benefit cost for Dominion and Dominion Gas (for employees represented by collective bargaining units) by approximately $25 million and $3 million, respectively, for 2015. Dominion remeasured all of its pension and other postretirement benefit plans in the second quarter of 2013. The remeasurement resulted in a reduction in the pension benefit obligation of approximately $354 million and a reduction in the accumulated postretirement benefit obligation of approximately $78 million. For Dominion Gas employees represented by collective bargaining units, the remeasurement resulted in a reduction in the pension benefit obligation of approximately $28 million and a reduction in the accumulated postretirement benefit obligation of approximately $9 million. The impact of the remeasurement on net periodic benefit (credit) cost (credit) was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by approximately $36 million, excluding the impacts of curtailments.curtailments, and for Dominion Gas employees represented by collective bargaining units by approximately $2 million. The discount rate used for the remeasurement was 4.80% for the pension plans and 4.70% for the other postretirement benefit plans. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012. In the fourth quarter of 2013, Dominion remeasured its other postretirement benefit plans as a result of a plan amendment that changed medical coverage for certain Medicare-eligible retirees effective April 2014. The remeasurement resulted in a reduction in the accumulated postretirement benefit obligation of approx- imatelyapproximately $220 million. The impact of the remeasurement on net periodic benefit (credit) cost (credit) was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by approximately $8 million. The amendment is expected to reduce net periodic benefit cost by $40 million to $60 million for each of the next five years. The discount rate used for the remeasurement was 4.80%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.
In the third quarter of 2014, East Ohio remeasured its other postretirement benefit plan as a result of an amendment that changed medical coverage upon the attainment of age 65 for certain future retirees effective January 1, 2016. For employees represented by collective bargaining units, the remeasurement resulted in an increase in the accumulated postretirement benefit obligation of approximately $22 million. The impact of the remeasurement on net periodic benefit credit was recognized prospectively from the remeasurement date and reduced net periodic benefit credit for 2014, for employees represented by collective bargaining units, by less than $1 million. The discount rate used for the remeasurement was 4.20% and the expected long-term rate of return used was 8.50%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2013.
Funded Status The following table summarizes the changes in Dominion’s pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status:status for Dominion and Dominion Gas (for employees represented by collective bargaining units): | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | Other Postretirement
Benefits | | | Year Ended December 31, | | 2013 | | | 2012 | | | 2013 | | | 2012 | | (millions, except percentages) | | | | | | | | | | | | | | | | | Changes in benefit obligation: | | | | | | | | | | | | | | | | | Benefit obligation at beginning of year | | $ | 6,125 | | | $ | 4,981 | | | $ | 1,719 | | | $ | 1,493 | | Service cost | | | 131 | | | | 116 | | | | 43 | | | | 44 | | Interest cost | | | 271 | | | | 268 | | | | 73 | | | | 79 | | Benefits paid | | | (229 | ) | | | (208 | ) | | | (75 | ) | | | (88 | ) | Actuarial (gains) losses during the year | | | (650 | ) | | | 967 | | | | (170 | ) | | | 191 | | Plan amendments(1) | | | 1 | | | | 1 | | | | (220 | ) | | | 1 | | Settlements and curtailments(2) | | | (24 | ) | | | — | | | | (16 | ) | | | (6 | ) | Special termination benefits | | | — | | | | — | | | | 1 | | | | — | | Medicare Part D reimbursement | | | — | | | | — | | | | 5 | | | | 5 | | Benefit obligation at end of year | | $ | 5,625 | | | $ | 6,125 | | | $ | 1,360 | | | $ | 1,719 | | Changes in fair value of plan assets: | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of year | | $ | 5,553 | | | $ | 5,145 | | | $ | 1,156 | | | $ | 1,042 | | Actual return on plan assets | | | 781 | | | | 611 | | | | 178 | | | | 132 | | Employer contributions | | | 8 | | | | 5 | | | | 12 | | | | 16 | | Benefits paid | | | (229 | ) | | | (208 | ) | | | (31 | ) | | | (34 | ) | Fair value of plan assets at end of year | | $ | 6,113 | | | $ | 5,553 | | | $ | 1,315 | | | $ | 1,156 | | Funded status at end of year | | $ | 488 | | | $ | (572 | ) | | $ | (45 | ) | | $ | (563 | ) | Amounts recognized in the Consolidated Balance Sheets at December 31: | | | | | | | | | | | | | | | | | Noncurrent pension and other postretirement benefit assets | | $ | 913 | | | $ | 701 | | | $ | 29 | | | $ | 1 | | Other current liabilities | | | (15 | ) | | | (2 | ) | | | (3 | ) | | | (4 | ) | Noncurrent pension and other postretirement benefit
liabilities | | | (410 | ) | | | (1,271 | ) | | | (71 | ) | | | (560 | ) | Net amount recognized | | $ | 488 | | | $ | (572 | ) | | $ | (45 | ) | | $ | (563 | ) | Significant assumptions used to determine benefit obligations as of December 31: | | | | | | | | | | | | | | | | | Discount rate(3) | |
| 5.20%/
5.30% |
| | | 4.40 | % | |
| 5.00%/
5.10% |
| | | 4.40 | % | Weighted average rate of increase for compensation | | | 4.21% | | | | 4.21 | % | | | 4.22% | | | | 4.22 | % |
(1) | Relates to a plan amendment that changed medical coverage for certain Medicare-eligible retirees. |
| | | | | | | | | | | | | | | | | | | | Pension Benefits | | | Other Postretirement Benefits | | | Year Ended December 31, | | 2014 | | | 2013 | | | 2014 | | | 2013 | | | (millions, except percentages) | | | | | | | | | | | | | DOMINION | | | | | | | | | | | | | | | | | Changes in benefit obligation: | | | | | | | | | | | | | | | | | Benefit obligation at beginning of year | | $ | 5,625 | | | $ | 6,125 | | | $ | 1,360 | | | $ | 1,719 | | Service cost | | | 114 | | | | 131 | | | | 32 | | | | 43 | | Interest cost | | | 290 | | | | 271 | | | | 67 | | | | 73 | | Benefits paid | | | (236 | ) | | | (229 | ) | | | (78 | ) | | | (75 | ) | Actuarial (gains) losses during the year | | | 887 | | | | (650 | ) | | | 177 | | | | (170 | ) | Plan amendments(1) | | | — | | | | 1 | | | | 9 | | | | (220 | ) | Settlements and curtailments(2) | | | (13 | ) | | | (24 | ) | | | — | | | | (16 | ) | Special termination benefits | | | — | | | | — | | | | — | | | | 1 | | Medicare Part D reimbursement | | | — | | | | — | | | | 4 | | | | 5 | | Benefit obligation at end of year | | $ | 6,667 | | | $ | 5,625 | | | $ | 1,571 | | | $ | 1,360 | | Changes in fair value of plan assets: | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of year | | $ | 6,113 | | | $ | 5,553 | | | $ | 1,315 | | | $ | 1,156 | | Actual return on plan assets | | | 601 | | | | 781 | | | | 105 | | | | 178 | | Employer contributions | | | 15 | | | | 8 | | | | 12 | | | | 12 | | Benefits paid | | | (236 | ) | | | (229 | ) | | | (30 | ) | | | (31 | ) | Settlements(2) | | | (13 | ) | | | — | | | | — | | | | — | | Fair value of plan assets at end of year | | $ | 6,480 | | | $ | 6,113 | | | $ | 1,402 | | | $ | 1,315 | | Funded status at end of year | | $ | (187 | ) | | $ | 488 | | | $ | (169 | ) | | $ | (45 | ) | Amounts recognized in the Consolidated Balance Sheets at December 31: | | | | | | | | | | | | | | | | | Noncurrent pension and other postretirement benefit assets | | $ | 946 | | | $ | 913 | | | $ | 10 | | | $ | 29 | | Other current liabilities | | | (13 | ) | | | (15 | ) | | | (3 | ) | | | (3 | ) | Noncurrent pension and other postretirement benefit liabilities | | | (1,120 | ) | | | (410 | ) | | | (176 | ) | | | (71 | ) | Net amount recognized | | $ | (187 | ) | | $ | 488 | | | $ | (169 | ) | | $ | (45 | ) | Significant assumptions used to determine benefit obligations as of December 31: | | | | | | | | | | | | | | | | | Discount rate(3) | | | 4.40% | | | | 5.20%/5.30% | | | | 4.40% | | | | 5.00%/5.10% | | Weighted average rate of increase for compensation | | | 4.22% | | | | 4.21% | | | | 4.22% | | | | 4.22% | | Expected long-term rate of return on plan assets | | | 8.75% | | | | 8.50% | | | | 8.50% | | | | 7.75% | | DOMINION GAS | | | | | | | | | | | | | | | | | Changes in benefit obligation: | | | | | | | | | | | | | | | | | Benefit obligation at beginning of year | | $ | 563 | | | $ | 607 | | | $ | 269 | | | $ | 287 | | Service cost | | | 12 | | | | 13 | | | | 6 | | | | 7 | | Interest cost | | | 28 | | | | 27 | | | | 13 | | | | 12 | | Benefits paid | | | (29 | ) | | | (27 | ) | | | (16 | ) | | | (17 | ) | Actuarial (gains) losses during the year | | | 64 | | | | (57 | ) | | | 38 | | | | (21 | ) | Plan amendments | | | — | | | | — | | | | 9 | | | | — | | Medicare Part D reimbursement | | | — | | | | — | | | | 1 | | | | 1 | | Benefit obligation at end of year | | $ | 638 | | | $ | 563 | | | $ | 320 | | | $ | 269 | | Changes in fair value of plan assets: | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of year | | $ | 1,403 | | | $ | 1,254 | | | $ | 273 | | | $ | 242 | | Actual return on plan assets | | | 136 | | | | 176 | | | | 21 | | | | 38 | | Employer contributions | | | — | | | | — | | | | 10 | | | | 10 | | Benefits paid | | | (29 | ) | | | (27 | ) | | | (16 | ) | | | (17 | ) | Fair value of plan assets at end of year | | $ | 1,510 | | | $ | 1,403 | | | $ | 288 | | | $ | 273 | | Funded status at end of year | | $ | 872 | | | $ | 840 | | | $ | (32 | ) | | $ | 4 | | Amounts recognized in the Consolidated Balance Sheets at December 31: | | | | | | | | | | | | | | | | | Noncurrent pension and other postretirement benefit assets | | $ | 872 | | | $ | 840 | | | $ | — | | | $ | 19 | | Noncurrent pension and other postretirement benefit liabilities(4) | | | — | | | | — | | | | (32 | ) | | | (15 | ) | Net amount recognized | | $ | 872 | | | $ | 840 | | | $ | (32 | ) | | $ | 4 | | Significant assumptions used to determine benefit obligations as of December 31: | | | | | | | | | | | | | | | | | Discount rate | | | 4.40% | | | | 5.20% | | | | 4.40% | | | | 5.00% | | Weighted average rate of increase for compensation | | | 3.93% | | | | 3.93% | | | | 3.93% | | | | 3.93% | | Expected long-term rate of return on plan assets | | | 8.75% | | | | 8.50% | | | | 8.50% | | | | 7.75% | |
Combined Notes to Consolidated Financial Statements, Continued | (1) | 2013 other postretirement benefits amount relates to a plan amendment that changed medical coverage for certain Medicare-eligible retirees. |
| (2) | 2014 amounts relate primarily to a settlement charge for certain executives. 2013 amounts relate primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor. |
| (3) | Pension rates are2013 pension and other postretirement benefits discount rates: 5.20% and 5.00% for the gas union plans and 5.30% for the nonunion and other union plans. OPEB rates are 5.00% for the gas union plans and 5.10% for the nonunion and other union plans.plans, respectively. |
| (4) | Reflected in other deferred credits and other liabilities in Dominion Gas’ Consolidated Balance Sheets. |
The ABO for all of Dominion’s defined benefit pension plans was $5.1$6.0 billion and $5.5$5.1 billion at December 31, 2014 and 2013, respectively. The ABO for the defined benefit pension plans covering Dominion Gas employees represented by collective bargaining units was $604 million and 2012,$534 million at December 31, 2014 and 2013, respectively. Under its funding policies, Dominion evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion determines the amount of contributions for the current year, if any, at that time. During 2013,2014, Dominion and Dominion Gas made no contributions to itsthe qualified defined benefit pension plans and no contributions are currently expected in 2014.2015. In July 2012, the Moving Ahead for Progress in theMAP 21st Century Act was signed into law. This Act includes an increase in the interest rates used to determine plan sponsors’ pension contributions for required funding purposes. TheseIn 2014, the HATFA of 2014 was signed into law. Similar to the MAP 21 Act, the HATFA of 2014 adjusts the rules for calculating interest rates used in determining funding obligations. It is estimated that the new interest rates are expected towill reduce required pension contributions through 2015.2019. Dominion believes that required pension contributions will rise subsequent to 2015,2019, resulting in littlean estimated $200 million reduction in net impact to cumulative required contributions over a 10-year period. Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion’s subsidiaries, including Dominion Gas, fund other postretirement benefit costs through VEBAs. Dominion’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion’s contributions to VEBAs, all of which pertained to Dominion Gas employees, totaled $12 million for both 2014 and 2013, and Dominion expects to contribute approximately $12 million to the Dominion VEBAs in 2014.2015, all of which pertains to Dominion Gas employees. Dominion doesand Dominion Gas do not expect any pension or other postretirement plan assets to be returned to the Company during 2014.2015. The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets:assets for Dominion and Dominion Gas (for employees represented by collective bargaining units): | | | | Pension Benefits | | | Other Postretirement
Benefits | | | Pension Benefits | | | Other Postretirement
Benefits | | | As of December 31, | | 2013 | | | 2012 | | | 2013 | | | 2012 | | | 2014 | | | 2013 | | | 2014 | | | 2013 | | | (millions) | | | | | | | | | | | | | | | | | | | | | DOMINION | | | | | | | | | | Benefit obligation | | $ | 4,978 | | | $ | 5,462 | | | $ | 1,233 | | | $ | 1,591 | | | $ | 5,970 | | | $ | 4,978 | | | $ | 1,564 | | | $ | 1,233 | | Fair value of plan assets | | | 4,553 | | | | 4,189 | | | | 1,158 | | | | 1,027 | | | | 4,838 | | | | 4,553 | | | | 1,385 | | | | 1,158 | | DOMINION GAS | | | | | | | | | | Benefit obligation | | | $ | — | | | $ | — | | | $ | 320 | | | $ | 147 | | Fair value of plan assets | | | | — | | | | — | | | | 288 | | | | 132 | |
The following table provides information on the ABO and fair value of plan assets for Dominion’s pension plans with an ABO in excess of plan assets: | | | | | | | | | | As of December 31, | | 2013 | | | 2012 | | (millions) | | | | | | | | | Accumulated benefit obligation | | $ | 114 | | | $ | 4,850 | | Fair value of plan assets | | | — | | | | 4,189 | |
| | | | | | | | | | As of December 31, | | 2014 | | | 2013 | | | (millions) | | | | | | | Accumulated benefit obligation | | $ | 5,370 | | | $ | 114 | | Fair value of plan assets | | | 4,838 | | | | — | |
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:paid for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans: | | | | Estimated Future Benefit Payments | | | Estimated Future Benefit Payments | | | | | Pension Benefits | | | Other Postretirement
Benefits | | | Pension Benefits | | | Other Postretirement
Benefits | | | (millions) | | | | | | | | | | | | | 2014 | | $ | 264 | | | $ | 91 | | | DOMINION | | | | | | 2015 | | | 269 | | | | 93 | | | $ | 272 | | | $ | 91 | | 2016 | | | 283 | | | | 96 | | | | 284 | | | | 94 | | 2017 | | | 300 | | | | 98 | | | | 300 | | | | 98 | | 2018 | | | 319 | | | | 100 | | | | 320 | | | | 101 | | 2019-2023 | | | 1,868 | | | | 507 | | | 2019 | | | | 333 | | | | 102 | | | 2020-2024 | | | 1,925 | | | 523 | | DOMINON GAS | | | | | | 2015 | | | $ | 34 | | | $ | 18 | | 2016 | | | | 35 | | | | 19 | | 2017 | | | | 37 | | | | 20 | | 2018 | | | | 38 | | | | 21 | | 2019 | | | | 39 | | | | 22 | | 2020-2024 | | | | 204 | | | | 111 | |
Plan Assets Dominion’s overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. As a participating employer in various pension plans sponsored by Dominion, Dominion Gas is subject to Dominion’s investment policies for such plans. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for itsDominion’s pension funds are 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the United States.
Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the United States including both developed and emerging markets. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Common/collective trust funds are funds of grouped assets that follow various investment strategies. Real estate includes equity REITs and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies. Dominion also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies. Strategic investment policies are established for Dominion’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities. For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.
Combined Notes to Consolidated Financial Statements, Continued The fair values of Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) pension plan assets by asset category are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements | | | | | Pension Plans | | | At December 31, | | 2014 | | | 2013 | | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | DOMINION | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents | | $ | 13 | | | $ | 25 | | | $ | — | | | $ | 38 | | | $ | 53 | | | $ | 126 | | | $ | — | | | $ | 179 | | U.S. equity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Large Cap | | | 1,313 | | | | — | | | | — | | | | 1,313 | | | | 1,220 | | | | — | | | | — | | | | 1,220 | | Other | | | 530 | | | | — | | | | — | | | | 530 | | | | 514 | | | | — | | | | — | | | | 514 | | Non-U.S. equity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Large Cap | | | 234 | | | | — | | | | — | | | | 234 | | | | 308 | | | | — | | | | — | | | | 308 | | Other | | | 403 | | | | — | | | | — | | | | 403 | | | | 391 | | | | — | | | | — | | | | 391 | | Common/collective trust funds(1) | | | — | | | | 1,595 | | | | — | | | | 1,595 | | | | — | | | | 1,387 | | | | — | | | | 1,387 | | Fixed income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | 45 | | | | 666 | | | | — | | | | 711 | | | | 43 | | | | 451 | | | | — | | | | 494 | | U.S. Treasury securities and agency debentures | | | 74 | | | | 342 | | | | — | | | | 416 | | | | 2 | | | | 229 | | | | — | | | | 231 | | State and municipal | | | 10 | | | | 60 | | | | — | | | | 70 | | | | 69 | | | | 107 | | | | — | | | | 176 | | Other securities | | | 6 | | | | 80 | | | | — | | | | 86 | | | | 7 | | | | 50 | | | | — | | | | 57 | | Real estate: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | REITs | | | 40 | | | | — | | | | — | | | | 40 | | | | 32 | | | | — | | | | — | | | | 32 | | Partnerships | | | — | | | | — | | | | 209 | | | | 209 | | | | — | | | | — | | | | 227 | | | | 227 | | Other alternative investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Private equity | | | — | | | | — | | | | 518 | | | | 518 | | | | — | | | | — | | | | 530 | | | | 530 | | Debt | | | — | | | | — | | | | 144 | | | | 144 | | | | — | | | | — | | | | 180 | | | | 180 | | Hedge funds | | | — | | | | — | | | | 162 | | | | 162 | | | | — | | | | — | | | | 187 | | | | 187 | | Total(2) | | $ | 2,668 | | | $ | 2,768 | | | $ | 1,033 | | | $ | 6,469 | | | $ | 2,639 | | | $ | 2,350 | | | $ | 1,124 | | | $ | 6,113 | | DOMINION GAS | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents | | $ | 3 | | | $ | 6 | | | $ | — | | | $ | 9 | | | $ | 12 | | | $ | 29 | | | $ | — | | | $ | 41 | | U.S. equity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Large Cap | | | 306 | | | | — | | | | — | | | | 306 | | | | 280 | | | | — | | | | — | | | | 280 | | Other | | | 124 | | | | — | | | | — | | | | 124 | | | | 118 | | | | — | | | | — | | | | 118 | | Non-U.S. equity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Large Cap | | | 54 | | | | — | | | | — | | | | 54 | | | | 72 | | | | — | | | | — | | | | 72 | | Other | | | 94 | | | | — | | | | — | | | | 94 | | | | 90 | | | | — | | | | — | | | | 90 | | Common/collective trust funds(3) | | | — | | | | 372 | | | | — | | | | 372 | | | | — | | | | 318 | | | | — | | | | 318 | | Fixed income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | 11 | | | | 155 | | | | — | | | | 166 | | | | 10 | | | | 103 | | | | — | | | | 113 | | U.S. Treasury securities and agency debentures | | | 17 | | | | 80 | | | | — | | | | 97 | | | | 1 | | | | 52 | | | | — | | | | 53 | | State and municipal | | | 2 | | | | 14 | | | | — | | | | 16 | | | | 16 | | | | 24 | | | | — | | | | 40 | | Other securities | | | 1 | | | | 19 | | | | — | | | | 20 | | | | 2 | | | | 11 | | | | — | | | | 13 | | Real estate: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | REITs | | | 9 | | | | — | | | | — | | | | 9 | | | | 7 | | | | — | | | | — | | | | 7 | | Partnerships | | | — | | | | — | | | | 48 | | | | 48 | | | | — | | | | — | | | | 52 | | | | 52 | | Other alternative investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Private equity | | | — | | | | — | | | | 121 | | | | 121 | | | | — | | | | — | | | | 122 | | | | 122 | | Debt | | | — | | | | — | | | | 34 | | | | 34 | | | | — | | | | — | | | | 41 | | | | 41 | | Hedge funds | | | — | | | | — | | | | 38 | | | | 38 | | | | — | | | | — | | | | 43 | | | | 43 | | Total(4) | | $ | 621 | | | $ | 646 | | | $ | 241 | | | $ | 1,508 | | | $ | 608 | | | $ | 537 | | | $ | 258 | | | $ | 1,403 | |
| (1) | Common/Collective Trust Funds include $360 million and $560 million of John Hancock insurance contracts held at December 31, 2014 and 2013, respectively. See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund. |
| (2) | Includes net assets related to pending sales of securities of $31 million, net accrued income of $18 million, and excludes net assets related to pending purchases of securities of $38 million at December 31, 2014. |
| (3) | See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund. |
| (4) | Includes net assets related to pending sales of securities of $7 million, net accrued income of $4 million, and excludes net assets related to pending purchases of securities of $9 million at December 31, 2014. |
The fair values of Dominion’s pension plan assetsand Dominion Gas’ (for employees represented by asset category are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements | | | | | Pension Plans | | | At December 31, | | 2013 | | | 2012 | | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Cash equivalents | | $ | 53 | | | $ | 126 | | | | — | | | $ | 179 | | | $ | — | | | $ | 195 | | | $ | — | | | $ | 195 | | U.S. equity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Large Cap | | | 1,220 | | | | — | | | | — | | | | 1,220 | | | | 927 | | | | 104 | | | | — | | | | 1,031 | | Other | | | 514 | | | | — | | | | — | | | | 514 | | | | 425 | | | | 99 | | | | — | | | | 524 | | Non-U.S. equity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Large Cap | | | 308 | | | | — | | | | — | | | | 308 | | | | 313 | | | | 68 | | | | — | | | | 381 | | Other | | | 391 | | | | — | | | | — | | | | 391 | | | | 228 | | | | 167 | | | | — | | | | 395 | | Common/collective trust funds | | | — | | | | 1,387 | | | | — | | | | 1,387 | | | | — | | | | — | | | | — | | | | — | | Fixed income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | 43 | | | | 451 | | | | — | | | | 494 | | | | 27 | | | | 1,026 | | | | — | | | | 1,053 | | U.S. Treasury securities and agency debentures | | | 2 | | | | 229 | | | | — | | | | 231 | | | | 331 | | | | 304 | | | | — | | | | 635 | | State and municipal | | | 69 | | | | 107 | | | | — | | | | 176 | | | | 1 | | | | 71 | | | | — | | | | 72 | | Other securities | | | 7 | | | | 50 | | | | — | | | | 57 | | | | 5 | | | | 43 | | | | — | | | | 48 | | Real estate: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | REITs | | | 32 | | | | — | | | | — | | | | 32 | | | | 29 | | | | — | | | | — | | | | 29 | | Partnerships | | | — | | | | — | | | | 227 | | | | 227 | | | | — | | | | — | | | | 321 | | | | 321 | | Other alternative investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Private equity | | | — | | | | — | | | | 530 | | | | 530 | | | | — | | | | — | | | | 456 | | | | 456 | | Debt | | | — | | | | — | | | | 180 | | | | 180 | | | | — | | | | — | | | | 192 | | | | 192 | | Hedge funds | | | — | | | | — | | | | 187 | | | | 187 | | | | — | | | | — | | | | 221 | | | | 221 | | Total | | $ | 2,639 | | | $ | 2,350 | | | $ | 1,124 | | | $ | 6,113 | | | $ | 2,286 | | | $ | 2,077 | | | $ | 1,190 | | | $ | 5,553 | |
The fair values of Dominion’scollective bargaining units) other postretirement plan assets by asset category are as follows:
| | | | Fair Value Measurements | | | Fair Value Measurements | | | | | Other Postretirement Plans | | | Other Postretirement Plans | | | At December 31, | | 2013 | | | 2012 | | | 2014 | | | 2013 | | | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | DOMINION | | | | | | | | | | | | | | | | | | Cash equivalents | | $ | 3 | | | $ | 14 | | | $ | — | | | $ | 17 | | | $ | — | | | $ | 13 | | | $ | — | | | $ | 13 | | | $ | 1 | | | $ | 7 | | | $ | — | | | $ | 8 | | | $ | 3 | | | $ | 14 | | | $ | — | | | $ | 17 | | U.S. equity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Large Cap | | | 472 | | | | — | | | | — | | | | 472 | | | | 378 | | | | 5 | | | | — | | | | 383 | | | | 514 | | | | — | | | | — | | | | 514 | | | | 472 | | | | — | | | | — | | | | 472 | | Other | | | 26 | | | | — | | | | — | | | | 26 | | | | 21 | | | | 45 | | | | — | | | | 66 | | | | 28 | | | | — | | | | — | | | | 28 | | | | 26 | | | | — | | | | — | | | | 26 | | Non-U.S. equity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Large Cap | | | 111 | | | | — | | | | — | | | | 111 | | | | 93 | | | | 3 | | | | — | | | | 96 | | | | 102 | | | | — | | | | — | | | | 102 | | | | 111 | | | | — | | | | — | | | | 111 | | Other | | | 20 | | | | — | | | | — | | | | 20 | | | | 11 | | | | 8 | | | | — | | | | 19 | | | | 21 | | | | — | | | | — | | | | 21 | | | | 20 | | | | — | | | | — | | | | 20 | | Common/collective trust funds | | | — | | | | 502 | | | | — | | | | 502 | | | | — | | | | — | | | | — | | | | — | | | Common/collective trust funds(1) | | | | — | | | | 555 | | | | — | | | | 555 | | | | — | | | | 502 | | | | — | | | | 502 | | Fixed income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate debt instruments | | | 2 | | | | 23 | | | | — | | | | 25 | | | | 1 | | | | 160 | | | | — | | | | 161 | | | | 3 | | | | 35 | | | | — | | | | 38 | | | | 2 | | | | 23 | | | | — | | | | 25 | | U.S. Treasury securities and agency debentures | | | — | | | | 12 | | | | — | | | | 12 | | | | 16 | | | | 266 | | | | — | | | | 282 | | | | 4 | | | | 18 | | | | — | | | | 22 | | | | — | | | | 12 | | | | — | | | | 12 | | State and municipal | | | 4 | | | | 5 | | | | — | | | | 9 | | | | — | | | | 9 | | | | — | | | | 9 | | | | 1 | | | | 3 | | | | — | | | | 4 | | | | 4 | | | | 5 | | | | — | | | | 9 | | Other securities | | | — | | | | 3 | | | | — | | | | 3 | | | | — | | | | 2 | | | | — | | | | 2 | | | | — | | | | 4 | | | | — | | | | 4 | | | | — | | | | 3 | | | | — | | | | 3 | | Real estate: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | REITs | | | 2 | | | | — | | | | — | | | | 2 | | | | 1 | | | | — | | | | — | | | | 1 | | | | 2 | | | | — | | | | — | | | | 2 | | | | 2 | | | | — | | | | — | | | | 2 | | Partnerships | | | — | | | | — | | | | 19 | | | | 19 | | | | — | | | | — | | | | 24 | | | | 24 | | | | — | | | | — | | | | 19 | | | | 19 | | | | — | | | | — | | | | 19 | | | | 19 | | Other alternative investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Private equity | | | — | | | | — | | | | 60 | | | | 60 | | | | — | | | | — | | | | 58 | | | | 58 | | | | — | | | | — | | | | 58 | | | | 58 | | | | — | | | | — | | | | 60 | | | | 60 | | Debt | | | — | | | | — | | | | 27 | | | | 27 | | | | — | | | | — | | | | 31 | | | | 31 | | | | — | | | | — | | | | 18 | | | | 18 | | | | — | | | | — | | | | 27 | | | | 27 | | Hedge funds | | | — | | | | — | | | | 10 | | | | 10 | | | | — | | | | — | | | | 11 | | | | 11 | | | | — | | | | — | | | | 9 | | | | 9 | | | | — | | | | — | | | | 10 | | | | 10 | | Total | | $ | 640 | | | $ | 559 | | | $ | 116 | | | $ | 1,315 | | | $ | 521 | | | $ | 511 | | | $ | 124 | | | $ | 1,156 | | | $ | 676 | | | $ | 622 | | | $ | 104 | | | $ | 1,402 | | | $ | 640 | | | $ | 559 | | | $ | 116 | | | $ | 1,315 | | DOMINION GAS | | | | | | | | | | | | | | | | | | Cash equivalents | | | $ | — | | | $ | 2 | | | $ | — | | | $ | 2 | | | $ | — | | | $ | 3 | | | $ | — | | | $ | 3 | | U.S. equity-Large Cap | | | | 113 | | | | — | | | | — | | | | 113 | | | | 104 | | | | — | | | | — | | | | 104 | | Non-U.S. equity-Large Cap | | | | 26 | | | | — | | | | — | | | | 26 | | | | 26 | | | | — | | | | — | | | | 26 | | Common/collective trust funds(2) | | | | — | | | | 129 | | | | — | | | | 129 | | | | — | | | | 119 | | | | — | | | | 119 | | Real estate-partnerships | | | | — | | | | — | | | | 2 | | | | 2 | | | | — | | | | — | | | | 2 | | | | 2 | | Other alternative investments: | | | | | | | | | | | | | | | | | | Private equity | | | | — | | | | — | | | | 12 | | | | 12 | | | | — | | | | — | | | | 12 | | | | 12 | | Debt | | | | — | | | | — | | | | 4 | | | | 4 | | | | — | | | | — | | | | 7 | | | | 7 | | Total | | | $ | 139 | | | $ | 131 | | | $ | 18 | | | $ | 288 | | | $ | 130 | | | $ | 122 | | | $ | 21 | | | $ | 273 | |
| (1) | Common/Collective Trust Funds include $19 million and $29 million of John Hancock insurance contracts held at December 31, 2014 and 2013, respectively. See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund. |
| (2) | See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund. |
Combined Notes to Consolidated Financial Statements, Continued The following table presents the changes in Dominion’s pension and other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category:category for Dominion and Dominion Gas (for employees represented by collective bargaining units): | | | | Fair Value Measurements using Significant Unobservable Inputs (Level 3) | | | Fair Value Measurements using Significant Unobservable Inputs (Level 3) | | | | | Pension Plans | | Other Postretirement Plans | | | Pension Plans | | Other Postretirement Plans | | | | | Real
Estate | | Private
Equity | | Debt | | Hedge
Funds | | Total | | Real
Estate | | Private
Equity | | | Debt | | | Hedge
Funds | | | Total | | | Real
Estate | | Private
Equity | | Debt | | Hedge
Funds | | Total | | Real
Estate | | Private
Equity | | Debt | | | Hedge
Funds | | | Total | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2010 | | $ | 271 | | | $ | 400 | | | $ | 262 | | | $ | 345 | | | $ | 1,278 | | | $ | 22 | | | $ | 61 | | | $ | 40 | | | $ | 17 | | | $ | 140 | | | Actual return on plan assets: | | | | | | | | | | | | | | | | | | | | | | Relating to assets still held at the reporting date | | | 38 | | | | 70 | | | | 10 | | | | 10 | | | | 128 | | | | 3 | | | | 11 | | | | 1 | | | | — | | | | 15 | | | Relating to assets sold during the period | | | (8 | ) | | | (34 | ) | | | (10 | ) | | | (15 | ) | | | (67 | ) | | | — | | | | (4 | ) | | | (1 | ) | | | (1 | ) | | | (6 | ) | | Purchases | | | 57 | | | | 76 | | | | 34 | | | | 48 | | | | 215 | | | | 3 | | | | 8 | | | | 3 | | | | 2 | | | | 16 | | | Sales | | | (54 | ) | | | (64 | ) | | | (53 | ) | | | (98 | ) | | | (269 | ) | | | (4 | ) | | | (13 | ) | | | (7 | ) | | | (4 | ) | | | (28 | ) | | DOMINION | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2011 | | $ | 304 | | | $ | 448 | | | $ | 243 | | | $ | 290 | | | $ | 1,285 | | | $ | 24 | | | $ | 63 | | | $ | 36 | | | $ | 14 | | | $ | 137 | | | $ | 304 | | | $ | 448 | | | $ | 243 | | | $ | 290 | | | $ | 1,285 | | | $ | 24 | | | $ | 63 | | | $ | 36 | | | $ | 14 | | | $ | 137 | | Actual return on plan assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Relating to assets still held at the reporting date | | | 21 | | | | 46 | | | | 17 | | | | 21 | | | | 105 | | | | 1 | | | | 3 | | | | 4 | | | | 1 | | | | 9 | | | | 21 | | | | 46 | | | | 17 | | | | 21 | | | | 105 | | | | 1 | | | | 3 | | | | 4 | | | | 1 | | | | 9 | | Relating to assets sold during the period | | | (8 | ) | | | (41 | ) | | | (11 | ) | | | (2 | ) | | | (62 | ) | | | — | | | | (1 | ) | | | — | | | | — | | | | (1 | ) | | | (8 | ) | | | (41 | ) | | | (11 | ) | | | (2 | ) | | | (62 | ) | | | — | | | | (1 | ) | | | — | | | | — | | | | (1 | ) | Purchases | | | 35 | | | | 79 | | | | 15 | | | | — | | | | 129 | | | | 2 | | | | 6 | | | | 1 | | | | — | | | | 9 | | | | 35 | | | | 79 | | | | 15 | | | | — | | | | 129 | | | | 2 | | | | 6 | | | | 1 | | | | — | | | | 9 | | Sales | | | (31 | ) | | | (76 | ) | | | (72 | ) | | | (88 | ) | | | (267 | ) | | | (3 | ) | | | (13 | ) | | | (10 | ) | | | (4 | ) | | | (30 | ) | | | (31 | ) | | | (76 | ) | | | (72 | ) | | | (88 | ) | | | (267 | ) | | | (3 | ) | | | (13 | ) | | | (10 | ) | | | (4 | ) | | | (30 | ) | Balance at December 31, 2012 | | $ | 321 | | | $ | 456 | | | $ | 192 | | | $ | 221 | | | $ | 1,190 | | | $ | 24 | | | $ | 58 | | | $ | 31 | | | $ | 11 | | | $ | 124 | | | $ | 321 | | | $ | 456 | | | $ | 192 | | | $ | 221 | | | $ | 1,190 | | | $ | 24 | | | $ | 58 | | | $ | 31 | | | $ | 11 | | | $ | 124 | | Actual return on plan assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Relating to assets still held at the reporting date | | | 15 | | | | 98 | | | | 32 | | | | 21 | | | | 166 | | | | (2 | ) | | | 6 | | | | 3 | | | | 1 | | | | 8 | | | | 15 | | | | 98 | | | | 32 | | | | 21 | | | | 166 | | | | (2 | ) | | | 6 | | | | 3 | | | | 1 | | | | 8 | | Relating to assets sold during the period | | | (36 | ) | | | (48 | ) | | | (34 | ) | | | (4 | ) | | | (122 | ) | | | 1 | | | | 3 | | | | — | | | | 1 | | | | 5 | | | | (36 | ) | | | (48 | ) | | | (34 | ) | | | (4 | ) | | | (122 | ) | | | 1 | | | | 3 | | | | — | | | | 1 | | | | 5 | | Purchases | | | 6 | | | | 115 | | | | 32 | | | | — | | | | 153 | | | | 1 | | | | 7 | | | | 2 | | | | — | | | | 10 | | | | 6 | | | | 115 | | | | 32 | | | | — | | | | 153 | | | | 1 | | | | 7 | | | | 2 | | | | — | | | | 10 | | Sales | | | (79 | ) | | | (91 | ) | | | (42 | ) | | | (51 | ) | | | (263 | ) | | | (5 | ) | | | (14 | ) | | | (9 | ) | | | (3 | ) | | | (31 | ) | | | (79 | ) | | | (91 | ) | | | (42 | ) | | | (51 | ) | | | (263 | ) | | | (5 | ) | | | (14 | ) | | | (9 | ) | | | (3 | ) | | | (31 | ) | Balance at December 31, 2013 | | $ | 227 | | | $ | 530 | | | $ | 180 | | | $ | 187 | | | $ | 1,124 | | | $ | 19 | | | $ | 60 | | �� | $ | 27 | | | $ | 10 | | | $ | 116 | | | $ | 227 | | | $ | 530 | | | $ | 180 | | | $ | 187 | | | $ | 1,124 | | | $ | 19 | | | $ | 60 | | | $ | 27 | | | $ | 10 | | | $ | 116 | | Actual return on plan assets: | | | | | | | | | | | | | | | | | | | | | | Relating to assets still held at the reporting date | | | | 40 | | | | 70 | | | | 12 | | | | 4 | | | | 126 | | | | 4 | | | | 7 | | | | 2 | | | | — | | | | 13 | | Relating to assets sold during the period | | | | (18 | ) | | | (67 | ) | | | (26 | ) | | | (4 | ) | | | (115 | ) | | | (1 | ) | | | (7 | ) | | | (3 | ) | | | — | | | | (11 | ) | Purchases | | | | — | | | | 135 | | | | 10 | | | | — | | | | 145 | | | | — | | | | 13 | | | | 1 | | | | — | | | | 14 | | Sales | | | | (40 | ) | | | (150 | ) | | | (32 | ) | | | (25 | ) | | | (247 | ) | | | (3 | ) | | | (15 | ) | | | (9 | ) | | | (1 | ) | | | (28 | ) | Balance at December 31, 2014 | | | $ | 209 | | | $ | 518 | | | $ | 144 | | | $ | 162 | | | $ | 1,033 | | | $ | 19 | | | $ | 58 | | | $ | 18 | | | $ | 9 | | | $ | 104 | | DOMINION GAS | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2011 | | | $ | 68 | | | $ | 99 | | | $ | 54 | | | $ | 64 | | | $ | 285 | | | $ | 3 | | | $ | 15 | | | $ | 10 | | | $ | — | | | $ | 28 | | Actual return on plan assets: | | | | | | | | | | | | | | | | | | | | | | Relating to assets still held at the reporting date | | | | 6 | | | | 12 | | | | 4 | | | | 4 | | | | 26 | | | | — | | | | (1 | ) | | | (1 | ) | | | — | | | | (2 | ) | Relating to assets sold during the period | | | | (2 | ) | | | (9 | ) | | | (2 | ) | | | — | | | | (13 | ) | | | — | | | | 2 | | | | 1 | | | | — | | | | 3 | | Purchases | | | | 7 | | | | 17 | | | | 3 | | | | — | | | | 27 | | | | — | | | | 1 | | | | — | | | | — | | | | 1 | | Sales | | | | (7 | ) | | | (16 | ) | | | (16 | ) | | | (18 | ) | | | (57 | ) | | | — | | | | (4 | ) | | | (2 | ) | | | — | | | | (6 | ) | Balance at December 31, 2012 | | | $ | 72 | | | $ | 103 | | | $ | 43 | | | $ | 50 | | | $ | 268 | | | $ | 3 | | | $ | 13 | | | $ | 8 | | | $ | — | | | $ | 24 | | Actual return on plan assets: | | | | | | | | | | | | | | | | | | | | | | Relating to assets still held at the reporting date | | | | 4 | | | | 24 | | | | 7 | | | | 5 | | | | 40 | | | | (1 | ) | | | 2 | | | | 1 | | | | — | | | | 2 | | Relating to assets sold during the period | | | | (8 | ) | | | (10 | ) | | | (7 | ) | | | (1 | ) | | | (26 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | Purchases | | | | 1 | | | | 25 | | | | 7 | | | | — | | | | 33 | | | | — | | | | 1 | | | | — | | | | — | | | | 1 | | Sales | | | | (17 | ) | | | (20 | ) | | | (9 | ) | | | (11 | ) | | | (57 | ) | | | — | | | | (4 | ) | | | (2 | ) | | | — | | | | (6 | ) | Balance at December 31, 2013 | | | $ | 52 | | | $ | 122 | | | $ | 41 | | | $ | 43 | | | $ | 258 | | | $ | 2 | | | $ | 12 | | | $ | 7 | | | $ | — | | | $ | 21 | | Actual return on plan assets: | | | | | | | | | | | | | | | | | | | | | | Relating to assets still held at the reporting date | | | | 9 | | | | 17 | | | | 4 | | | | 1 | | | | 31 | | | | — | | | | 2 | | | | 1 | | | | — | | | | 3 | | Relating to assets sold during the period | | | | (4 | ) | | | (15 | ) | | | (6 | ) | | | (1 | ) | | | (26 | ) | | | — | | | | (1 | ) | | | (1 | ) | | | — | | | | (2 | ) | Purchases | | | | — | | | | 30 | | | | 2 | | | | — | | | | 32 | | | | — | | | | 2 | | | | — | | | | — | | | | 2 | | Sales | | | | (9 | ) | | | (33 | ) | | | (7 | ) | | | (5 | ) | | | (54 | ) | | | — | | | | (3 | ) | | | (3 | ) | | | — | | | | (6 | ) | Balance at December 31, 2014 | | | $ | 48 | | | $ | 121 | | | $ | 34 | | | $ | 38 | | | $ | 241 | | | $ | 2 | | | $ | 12 | | | $ | 4 | | | $ | — | | | $ | 18 | |
Investments in Common/Collective Trust Funds in Dominion’s pension and other postretirement plans, including those in which Dominion Gas participates, are stated at fair value as determined by the issuer of the Common/Collective Trust Funds based on the fair value of the underlying investments. The Common/Collective Trusts do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the Common/Collective Trust Funds have limited withdrawal or redemption rights during the term of the investment. Strategies of the Common/Collective Trust Funds are as follows: Ÿ | | Dominion and Dominion Gas Wells Fargo Closed End Bond Trust-The Fund invests in stocks, bonds or a combination of both. Shares of the Fund are traded on a stock exchange and are subject to market risk like stocks, bonds and mutual funds. The Fund may invest in a less liquid portfolio of stocks and bonds because the fund does not need to sell securities to meet shareholder redemptions as mutual funds in order to keep a percentage of its portfolio in cash to pay back investors who withdraw shares. JPMorgan Core Bond Trust-The Fund seeks to maximize total return by investing primarily in a diversified portfolio of intermediate- and long-term debt securities. The Fund invests primarily in investment-grade bonds; it generally maintains an average weighted maturity between four and 12 years. It may shorten its average weighted maturity if deemed appropriate for temporary defensive purposes. SSgA Russell 2000 Value Index Common Trust-The Fund measures the performance of the small-cap value segment of the U.S. equity universe. The Russell 2000 Value Index is constructed to provide a comprehensive and unbiased barometer for the small-cap value segment. The Index is completely reconstituted annually to ensure larger stocks do not distort the performance and characteristics of the true small-cap opportunity set and that the represented companies continue to reflect value characteristics. NT Common Short-Term Investment Fund-The Fund seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of approved money market instruments with short maturities. Liquidity is emphasized to provide for redemption of units at par on any business day. Principal preservation is a primary objective. Within quality, maturity, and sector diversification guidelines, investments are made in those securities with the most attractive yields. Dominion SSgA Daily MSCI Emerging Markets Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI Emerging Markets Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company). SSgA Daily MSCI ACWI Ex-USA Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI ACWI Ex-USA Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company). SSgA S&P 400 MidCap Index-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of its benchmark index (the Index) over the long term. The S&P MidCap 400 is comprised of approximately 400 U.S. mid-cap securities and accounts for approximately 7% coverage of the U.S. stock market capitalization. SSgA will typically attempt to invest in the equity securities comprising the Index, in approximately the same proportions as they are represented in the Index. JPMorgan Chase Bank U.S. Active Core Plus Equity Fund-The Fund seeks to outperform the S&P 500 Index (the Benchmark), gross of fees, over a market cycle. The Fund invests primarily in a portfolio of long and short positions in equity securities of large and mid capitalization U.S. companies with characteristics similar to those of the Benchmark. Mondrian International Small Cap Equity Fund-The Fund’s investment objective is long-term total return. The Fund primarily invests in equity securities of non-U.S. small capitalization companies that, in the investment manager’s opinion, are undervalued at the time of purchase based on fundamental value analysis employed by the investment manager. NT Collective Russell 2000 Growth Index-The Fund seeks an investment return that approximates the overall performance of the common stocks included in the Russell 2000 Growth Index. The Fund primarily invests in common stocks of one or more companies that are deemed to be representative of the industry diversification of the entire Russell 2000 Growth Index. NT Collective Short-Term Investment Fund-The Fund is composed of high-grade money market instruments with short-term maturities. The Fund’s objective is to provide an investment vehicle for cash reserves while offering a competitive rate of return. Liquidity is emphasized to provide for redemption of units on any business day. Principal preservation is also a prime objective. Admissions and withdrawals are made daily. Interest is accrued daily and distributed monthly. Investments in Group Insurance Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate debt instruments, and state and municipal debt securities.
Combined Notes to Consolidated Financial Statements, Continued Net Periodic Benefit (Credit) Cost Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in the Consolidated Statements of Income. The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | Other Postretirement Benefits | | | Year Ended December 31, | | 2014 | | | 2013 | | | 2012 | | | 2014 | | | 2013 | | | 2012 | | | (millions, except percentages) | | | | | | | | | | | | | | | | | | | DOMINION | | | | | | | | | | | | | | | | | | | | | | | | | Service cost | | $ | 114 | | | $ | 131 | | | $ | 116 | | | $ | 32 | | | $ | 43 | | | $ | 44 | | Interest cost | | | 290 | | | | 271 | | | | 268 | | | | 67 | | | | 73 | | | | 79 | | Expected return on plan assets | | | (499 | ) | | | (462 | ) | | | (430 | ) | | | (111 | ) | | | (92 | ) | | | (79 | ) | Amortization of prior service (credit) cost | | | 3 | | | | 3 | | | | 3 | | | | (28 | ) | | | (15 | ) | | | (13 | ) | Amortization of net actuarial loss | | | 111 | | | | 165 | | | | 132 | | | | 2 | | | | 7 | | | | 6 | | Settlements and curtailments(1) | | | 1 | | | | (2 | ) | | | — | | | | — | | | | (15 | ) | | | (4 | ) | Special termination benefits | | | — | | | | — | | | | — | | | | — | | | | 1 | | | | — | | Net periodic benefit (credit) cost | | $ | 20 | | | $ | 106 | | | $ | 89 | | | $ | (38 | ) | | $ | 2 | | | $ | 33 | | Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | Current year net actuarial (gain) loss | | $ | 784 | | | $ | (968 | ) | | $ | 786 | | | $ | 183 | | | $ | (255 | ) | | $ | 139 | | Prior service (credit) cost | | | — | | | | 1 | | | | — | | | | 9 | | | | (215 | ) | | | 1 | | Settlements and curtailments(1) | | | (1 | ) | | | (22 | ) | | | — | | | | — | | | | (7 | ) | | | (2 | ) | Less amounts included in net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | Amortization of net actuarial loss | | | (111 | ) | | | (165 | ) | | | (132 | ) | | | (2 | ) | | | (7 | ) | | | (6 | ) | Amortization of prior service credit (cost) | | | (3 | ) | | | (3 | ) | | | (3 | ) | | | 28 | | | | 15 | | | | 13 | | Total recognized in other comprehensive income and regulatory assets and liabilities | | $ | 669 | | | $ | (1,157 | ) | | $ | 651 | | | $ | 218 | | | $ | (469 | ) | | $ | 145 | | Significant assumptions used to determine periodic cost: | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | | 5.20%-5.30 | % | | | 4.40%-4.80 | % | | | 5.50 | % | | | 4.20%-5.10 | % | | | 4.40%-4.80 | % | | | 5.50 | % | Expected long-term rate of return on plan assets | | | 8.75 | % | | | 8.50 | % | | | 8.50 | % | | | 8.50 | % | | | 7.75 | % | | | 7.75 | % | Weighted average rate of increase for compensation | | | 4.21 | % | | | 4.21 | % | | | 4.21 | % | | | 4.22 | % | | | 4.22 | % | | | 4.22 | % | Healthcare cost trend rate(2) | | | | | | | | | | | | | | | 7.00 | % | | | 7.00 | % | | | 7.00 | % | Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(2) | | | | | | | | | | | | | | | 5.00 | % | | | 4.60 | % | | | 4.60 | % | Year that the rate reaches the ultimate trend rate(2)(3) | | | | | | | | | | | | | | | 2018 | | | | 2062 | | | | 2061 | | DOMINION GAS | | | | | | | | | | | | | | | | | | | | | | | | | Service cost | | $ | 12 | | | $ | 13 | | | $ | 11 | | | $ | 6 | | | $ | 7 | | | $ | 7 | | Interest cost | | | 28 | | | | 27 | | | | 28 | | | | 13 | | | | 12 | | | | 14 | | Expected return on plan assets | | | (115 | ) | | | (106 | ) | | | (96 | ) | | | (23 | ) | | | (19 | ) | | | (16 | ) | Amortization of prior service (credit) cost | | | 1 | | | | 1 | | | | 1 | | | | (1 | ) | | | (3 | ) | | | (4 | ) | Amortization of net actuarial loss | | | 19 | | | | 26 | | | | 26 | | | | — | | | | 2 | | | | 1 | | Net periodic benefit (credit) cost | | $ | (55 | ) | | $ | (39 | ) | | $ | (30 | ) | | $ | (5 | ) | | $ | (1 | ) | | $ | 2 | | Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | Current year net actuarial (gain) loss | | $ | 43 | | | $ | (127 | ) | | $ | 35 | | | $ | 40 | | | $ | (40 | ) | | $ | 12 | | Prior service cost | | | — | | | | — | | | | — | | | | 10 | | | | — | | | | — | | Less amounts included in net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | Amortization of net actuarial loss | | | (19 | ) | | | (26 | ) | | | (26 | ) | | | — | | | | (2 | ) | | | (1 | ) | Amortization of prior service credit (cost) | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | 1 | | | | 3 | | | | 4 | | Total recognized in other comprehensive income and regulatory assets and liabilities | | $ | 23 | | | $ | (154 | ) | | $ | 8 | | | $ | 51 | | | $ | (39 | ) | | $ | 15 | | Significant assumptions used to determine periodic cost: | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | | 5.20 | % | | | 4.40%-4.80 | % | | | 5.50 | % | | | 4.20%-5.00 | % | | | 4.40%-4.70 | % | | | 5.50 | % | Expected long-term rate of return on plan assets | | | 8.75 | % | | | 8.50 | % | | | 8.50 | % | | | 8.50 | % | | | 7.75 | % | | | 7.75 | % | Weighted average rate of increase for compensation | | | 3.93 | % | | | 3.93 | % | | | 3.93 | % | | | 3.93 | % | | | 3.93 | % | | | 3.93 | % | Healthcare cost trend rate(2) | | | | | | | | | | | | | | | 7.00 | % | | | 7.00 | % | | | 7.00 | % | Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(2) | | | | | | | | | | | | | | | 5.00 | % | | | 4.60 | % | | | 4.60 | % | Year that the rate reaches the ultimate trend rate(2)(3) | | | | | | | | | | | | | | | 2018 | | | | 2062 | | | | 2061 | |
| (1) | 2013 amounts relate primarily to the decommissioning of Kewaunee. |
Ÿ(2) | | JPMorgan Core Bond Trust-The Fund seeksAssumptions used to maximize total return by investing primarily in a diversified portfolio of intermediate- and long-term debt securities. The Fund invests primarily in investment-grade bonds; it generally maintains an average weighted maturity between four and 12 years. It may shorten its average weighted maturity if deemed appropriatedetermine net periodic cost for temporary defensive purposes.
the following year. |
Ÿ(3) | | SSgA Russell 2000 Value Index Common Trust-The Fund measuresThe Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the performance of the small-cap value segment of the U.S. equity universe. The Russell 2000 Value Index is constructed to provide a comprehensive and unbiased barometer for the small-cap value segment. The Index is completely reconstituted annually to ensure larger stocks do not
ultimate trend rate much more quickly than previous models. |
| | distort the performance and characteristics of the true small-cap opportunity set and that the represented companies continue to reflect value characteristics.
|
Ÿ | | SSgA Daily MSCI Emerging Markets Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI Emerging Markets Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company).
|
Ÿ | | SSgA Daily MSCI ACWI Ex-USA Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI ACWI Ex-USA Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company).
|
Ÿ | | SSgA S&P 400 MidCap Index-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of its benchmark index (the Index) over the long term. The S&P MidCap 400 is comprised of approximately 400 U.S. mid-cap securities and accounts for approximately 7% coverage of the U.S. stock market capitalization. SSgA will typically attempt to invest in the equity securities comprising the Index, in approximately the same proportions as they are represented in the Index.
|
Ÿ | | JPMorgan Chase Bank U.S. Active Core Plus Equity Fund-The Fund seeks to outperform the S&P 500 Index (the Benchmark), gross of fees, over a market cycle. The Fund invests primarily in a portfolio of long and short positions in
|
| | equity securities of large and mid capitalization U.S. companies with characteristics similar to those of the Benchmark.
|
Ÿ | | Mondrian International Small Cap Equity Fund-The Fund’s investment objective is long-term total return. The Fund
|
| | primarily invests in equity securities of non-U.S. small capitalization companies that, in the investment manager’s opinion, are undervalued at the time of purchase based on fundamental value analysis employed by the investment manager.
|
Net Periodic Benefit Cost
The components of the provision for net periodic benefit cost and amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Benefits | | | Other Postretirement Benefits | | | Year Ended December 31, | | 2013 | | | 2012 | | | 2011 | | | 2013 | | | 2012 | | | 2011 | | | (millions, except percentages) | | | | | | | | | | | | | | | | | | | Service cost | | $ | 131 | | | $ | 116 | | | $ | 108 | | | $ | 43 | | | $ | 44 | | | $ | 48 | | Interest cost | | | 271 | | | | 268 | | | | 258 | | | | 73 | | | | 79 | | | | 94 | | Expected return on plan assets | | | (462 | ) | | | (430 | ) | | | (440 | ) | | | (92 | ) | | | (79 | ) | | | (79 | ) | Amortization of prior service (credit) cost | | | 3 | | | | 3 | | | | 3 | | | | (15 | ) | | | (13 | ) | | | (13 | ) | Amortization of net actuarial loss | | | 165 | | | | 132 | | | | 96 | | | | 7 | | | | 6 | | | | 12 | | Settlements and curtailments(1) | | | (2 | ) | | | — | | | | — | | | | (15 | ) | | | (4 | ) | | | 1 | | Special termination benefits | | | — | | | | — | | | | — | | | | 1 | | | | — | | | | — | | Net periodic benefit cost | | $ | 106 | | | $ | 89 | | | $ | 25 | | | $ | 2 | | | $ | 33 | | | $ | 63 | | Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | Current year net actuarial (gain) loss | | $ | (968 | ) | | $ | 786 | | | $ | 534 | | | $ | (255 | ) | | $ | 139 | | | $ | (157 | ) | Prior service (credit) cost | | | 1 | | | | — | | | | — | | | | (215 | ) | | | 1 | | | | (70 | ) | Settlements and curtailments(1) | | | (22 | ) | | | — | | | | — | | | | (7 | ) | | | (2 | ) | | | (1 | ) | Less amounts included in net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | Amortization of net actuarial loss | | | (165 | ) | | | (132 | ) | | | (96 | ) | | | (7 | ) | | | (6 | ) | | | (12 | ) | Amortization of prior service credit (cost) | | | (3 | ) | | | (3 | ) | | | (3 | ) | | | 15 | | | | 13 | | | | 13 | | Total recognized in other comprehensive income and regulatory assets and liabilities | | $ | (1,157 | ) | | $ | 651 | | | $ | 435 | | | $ | (469 | ) | | $ | 145 | | | $ | (227 | ) | Significant assumptions used to determine periodic cost: | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | | 4.40%-4.80 | % | | | 5.50 | % | | | 5.90 | % | | | 4.40%-4.80 | % | | | 5.50 | % | | | 5.90 | % | Expected long-term rate of return on plan assets | | | 8.50 | % | | | 8.50 | % | | | 8.50 | % | | | 7.75 | % | | | 7.75 | % | | | 7.75 | % | Weighted average rate of increase for compensation | | | 4.21 | % | | | 4.21 | % | | | 4.61 | % | | | 4.22 | % | | | 4.22 | % | | | 4.62 | % | Healthcare cost trend rate(2) | | | | | | | | | | | | | | | 7.00 | % | | | 7.00 | % | | | 7.00 | % | Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(2) | | | | | | | | | | | | | | | 4.60 | % | | | 4.60 | % | | | 4.60 | % | Year that the rate reaches the ultimate trend rate(2) | | | | | | | | | | | | | | | 2062 | | | | 2061 | | | | 2060 | |
(1) | 2013 amount relates primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor. |
(2) | Assumptions used to determine periodic cost for the following year. |
The components of AOCI and regulatory assets and liabilities for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans that have not been recognized as components of net periodic benefit (credit) cost are as follows: | | | | Pension Benefits | | | Other
Postretirement
Benefits | | | Pension Benefits | | | Other
Postretirement
Benefits | | | At December 31, | | 2013 | | | 2012 | | | 2013 | | 2012 | | | 2014 | | | 2013 | | | 2014 | | 2013 | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | DOMINION | | | | | | | | | | Net actuarial (gain) loss | | $ | 1,709 | | | $ | 2,865 | | | $ | (40 | ) | | $ | 229 | | | $ | 2,382 | | | $ | 1,709 | | | $ | 139 | | | $ | (40 | ) | Prior service (credit) cost | | | 10 | | | | 11 | | | | (271 | ) | | | (71 | ) | | | 7 | | | | 10 | | | | (233 | ) | | | (271 | ) | Total(1) | | $ | 1,719 | | | $ | 2,876 | | | $ | (311 | ) | | $ | 158 | | | $ | 2,389 | | | $ | 1,719 | | | $ | (94 | ) | | $ | (311 | ) | DOMINION GAS | | | | | | | | | | Net actuarial loss | | | $ | 303 | | | $ | 279 | | | $ | 43 | | | $ | 3 | | Prior service (credit) cost | | | | 1 | | | | 2 | | | | 7 | | | | (4 | ) | Total(2) | | | $ | 304 | | | $ | 281 | | | $ | 50 | | | $ | (1 | ) |
| (1) | As of December 31, 2014, of the $2.4 billion and $(94) million related to pension benefits and other postretirement benefits, $1.4 billion and $(81) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2013, of the $1.7 billion and $(311) million related to pension benefits and other postretirement benefits, $1.0 billion and $(156) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. |
| (2) | As of December 31, 2012,2014, of the $2.9 billion and $158$304 million related to pension benefits, and other postretirement benefits, $1.8 billion and $69$112 million respectively, areis included in AOCI, with the remainder included in regulatory assets and liabilities; the $50 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2013, of the $281 million related to pension benefits, $104 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $(1) million related to other postretirement benefits is included entirely in regulatory assets and liabilities. |
The following table provides the components of AOCI and regulatory assets and liabilities for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans as of December 31, 20132014 that are expected to be amortized as components of net periodic benefit (credit) cost in 2014:2015: | | | | Pension
Benefits | | | Other
Postretirement
Benefits | | | Pension Benefits | | | Other Postretirement
Benefits | | | (millions) | | | | | | | | | | | | | DOMINION | | | | | | Net actuarial loss | | $ | 112 | | | $ | 2 | | | $ | 160 | | | $ | 6 | | Prior service (credit) cost | | | 3 | | | | (28 | ) | | | 2 | | | | (27 | ) | DOMINION GAS | | | | | | Net actuarial loss | | | $ | 20 | | | $ | 2 | | Prior service cost | | | | 1 | | | | — | |
The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion develops assumptions, which are then compared to the forecasts of an independent investment advisor (except for the expected long-term rates of return) to ensure reasonableness. An internal committee selects the final assumptions used for Dominion’s pension and other postretirement plans, including those in which Dominion Gas participates, including discount rates, expected long-term rates of return, healthcare cost trend rates and mortality rates. Dominion determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans, including those in which Dominion Gas participates, by using a combination of: Expected inflation and risk-free interest rate assumptions; Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes; Expected future risk premiums, asset volatilities and correlations;
Combined Notes to Consolidated Financial Statements, Continued
Forecasts of an independent investment advisor; Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; and Investment allocation of plan assets. Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans.plans, including those in which Dominion Gas participates. Dominion develops its mortality assumption using plan-specific studies and projects mortality improvement using scales developed by the Society of Actuaries for all its plans, including those in which Dominion Gas participates. Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion’s retiree healthcare plans.plans, including those in which Dominion Gas participates. A one percentage point change in assumed healthcare cost trend rates would have had the following effects:effects for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) other postretirement benefit plans: | | | | | | | | | | | | Other Postretirement Benefits | | | | | One
percentage
point
increase | | | One
percentage
point
decrease | | | (millions) | | | | | | | Effect on net periodic cost for 2014 | | $ | 16 | | | $ | (18 | ) | Effect on other postretirement benefit obligation at December 31, 2013 | | | 140 | | | | (118 | ) |
| | | | | | | | | | | | Other Postretirement Benefits | | | | | One percentage
point increase | | | One percentage
point decrease | | | (millions) | | | | | | | DOMINION | | | | | | | | | Effect on net periodic cost for 2015 | | $ | 26 | | | $ | (16 | ) | Effect on other postretirement benefit obligation at December 31, 2014 | | | 186 | | | | (152 | ) | DOMINION GAS | | | | | | | | | Effect on net periodic cost for 2015 | | $ | 5 | | | $ | (4 | ) | Effect on other postretirement benefit obligation at December 31, 2014 | | | 40 | | | | (30 | ) |
An internal committee selects the final assumptions used for Dominion’s pensionDominion Gas (Employees Not Represented by Collective Bargaining Units) and other postretirement plans, including discount rates, expected long-term rates of return and healthcare cost trend rates.
Virginia Power-Participation in Defined ContributionBenefit Plans In addition, Dominion sponsors defined contribution employee savings plans. During 2013, 2012 and 2011, Dominion recognized $40 million, $40 million and $38 million, respectively, as employer matching contributions to these plans.
VIRGINIA POWER
Virginia Power participates inemployees and Dominion Gas employees not represented by collective bargaining units are covered by the Dominion Pension Plan a defined benefit pension plan sponsored by Dominion that provides benefits to multiple Dominion subsidiaries. Retirement benefits payable under this plan are based primarily on years of service, age and the employee’s compensation.described above. As a participating employer,employers, Virginia Power isand Dominion Gas are subject to Dominion’s funding policy, which is to contribute annually an amount that is in accordance with the provisions of ERISA. During 20132014, Virginia Power and 2012, Virginia PowerDominion Gas made no contributions to the planDominion Pension Plan, and no contributions to this plan are currently expected in 2014.2015. Virginia Power’s net periodic pension cost related to this pension plan was $75 million, $96 million and $72 million in 2014, 2013 and $502012, respectively. Dominion Gas’ net periodic pension credit related to this plan was $(37) million, $(27) million and $(25) million in 2014, 2013 and 2012, respectively. Net periodic pension (credit) cost is reflected in other operations
Combined Notes to Consolidated Financial Statements, Continued and 2011, respectively. Employeemaintenance expense in their respective Consolidated Statements of Income. The funded status of various Dominion subsidiary groups and employee compensation isare the basis for determining Virginia Power’sthe share of total pension costs. costs for participating Dominion subsidiaries. See Note 24 for Virginia Power also participates inand Dominion Gas amounts due to/from Dominion related to this plan. Retiree healthcare and life insurance benefits, for Virginia Power employees and for Dominion Gas employees not represented by collective bargaining units, are covered by the Dominion Retiree Health and Welfare Plan a plan sponsored by Dominion that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Annual employee premiums are based on several factors such as age, retirement date and years of service.described above. Virginia Power’s net periodic benefit (credit) cost related to this plan was $(18) million, $5 million and $13 million in 2014, 2013 and $232012, respectively. Dominion Gas’ net periodic benefit (credit) cost related to this plan was $(5) million, less than $1 million and $3 million for 2014, 2013 and 2012, respectively. Net periodic benefit (credit) cost is reflected in 2013, 2012other operations and 2011, respectively.maintenance expenses in their respective Consolidated Statements of Income. Employee headcount is the basis for determining Virginia Power’sthe share of total other postretirement benefit costs.costs for participating Dominion subsidiaries. See Note 24 for Virginia Power and Dominion Gas amounts due to/from Dominion related to this plan. Dominion holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power and Dominion Gas’ employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power and Dominion Gas will provide to Dominion for their shares of employee benefit plan contributions. Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power fundsand Dominion Gas fund other postretirement benefit costs through a VEBA.VEBAs. During 20132014 and 2012,2013, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2014.2015. Dominion Gas’ contributions to VEBAs for employees not represented by collective bargaining units were $1 million and $2 million for 2014 and 2013, respectively. Defined Contribution Plans Dominion holds investments in trusts to fund employee benefit payments for its pension and other postretirement benefit plans, in which Virginia Power’s employees participate. Any investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power will provide to Dominion for its share of employee benefit plan contributions. Virginia Power also participates in Dominion-sponsoredsponsors defined contribution employee savings plans that cover substantially all employees. During 2014, 2013 and 2012, and 2011, Virginia PowerDominion recognized $16$41 million, $15$40 million and $14$40 million, respectively, as employer matching contributions to these plans. Dominion Gas participates in these employee savings plans, both specific to Dominion Gas and that cover multiple Dominion subsidiaries. During 2014, 2013 and 2012, Dominion Gas recognized $7 million, $7 million and $6 million, respectively, as employer matching contributions to these plans. Virginia Power also participates in these employee savings plans. During 2014, 2013 and 2012, Virginia Power recognized $17 million, $16 million and $15 million, respectively, as employer matching contributions to these plans.
NOTE 22. COMMITMENTSAND CONTINGENCIES As a result of issues generated in the ordinary course of business, Dominion and Virginia Powerthe Companies are involved in legal proceedings before various courts and are periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on Dominion’s or Virginia Power’sthe financial position, liquidity or results of operations.operations of the Companies.
Environmental Matters Dominion and Virginia PowerThe Companies are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
AIR The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of Dominion’s and Virginia Power’sthe Companies’ facilities are subject to the CAA’s permitting and other requirements. In December 2011, the EPA issued MATS for coal and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance will be required by April 16,
2015, with certain limited exceptions. In December 2011, Virginia Power recordedJune 2014, the VDEQ granted a $228 million ($139 million after-tax) charge reflecting plant balances that are not expectedone-year MATS compliance extension for two coal-fired units at Yorktown to be recovered in future periods due to the anticipated retirement of certain regulated coal units, primarily as a resultdefer planned retirements and allow for continued operation of the issuance of the final MATS.units to address reliability concerns while necessary electric transmission upgrades are being completed. During the fourth quarter of 2013, Virginia Power recorded charges totaling $26 million ($16 million after-tax) for certain exit activities associated with these coal units, including the cost of employee severance, vendor contract termination, and inventory not expected to be used or usable at other stations. The EPA established CAIR with the intent to require significant reductions in SO2 and NOXemissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO2 and NOxemissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO2 and NOx emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NOx emissions caps, NOx emissions caps during the ozone season (May 1 through September 30) and annual SO2 emission caps with differing requirements for two groups of affected states. Following numerous petitions by industry participants for review and motionsa successful motion for stay, in October 2014, the U.S. Court of Appeals for the D.C. Circuit issued a ruling in December 2011ordered that the EPA’s motion to lift the stay of CSAPR pending judicial review. In February and June 2012,be granted. Further, the EPA issued technical revisions to CSAPR that were not material to Dominion. In August 2012, the court vacated CSAPR in its entirety and ordered the EPA to implement CAIR until a valid replacement rule is issued. In October 2012, the EPA filed a peti- tion requesting a rehearing of the court’s decision, which was denied in January 2013. The mandate vacating CSAPR was issued in February 2013. In March 2013, the EPA and several environmental groups filed petitions with the U.S. Supreme Court requesting review of the decision to vacate and remand CSAPR. In June 2013, the U.S. Supreme Court granted the EPA’s petition seeking review ofrequest to shift the D.C. Circuit’s decisionCSAPR compliance deadlines by three years, so that vacatedPhase 1 emissions budgets (which would have gone into effect in 2012 and remanded CSAPR. With respect to Dominion’s generation fleet, the2013) will apply in 2015 and 2016, and Phase 2 emissions budgets will apply in 2017 and beyond. CSAPR will replace CAIR beginning in January 2015. The cost to comply with CAIR is not expected to be material.material to the Consolidated Financial Statements. Future outcomes of any additional litigation and/or any additional action to issue a revised rule could affect the assessment regarding cost of compliance.
In May 2012, the EPA issued final designations for the 75-ppb ozone air quality standard. Several Dominion electric generatingA number of the Companies’ facilities are located in areas impacted by this standard. As part of the standard, states will be required to develop and implement plans to address sources emitting pollutants which contribute to the formation of ozone. In November 2014, the EPA issued a new proposal to revise the ozone standard and expects to finalize the rule in October 2015. The EPA is not expected to complete attainment designations for a new standard until 2017 and states will have until 2020 to develop plans to address the new standard. Until the states have developed implementation plans, Dominion isthe Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significant expenditures are required to implement additional controls, it could adversely affect the Companies’ results of operations and cash flows. In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerned historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations fromAugust 2010, the EPA claiming violationsissued revised National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. The rule was amended in March 2011 and January 2013. The rule establishes emission standards for control of hazardous air pollutants for engines at smaller facilities, known as area sources. As a result of these regulations, Dominion Gas installed emissions controls on several compressor engines. Dominion Gas has spent approximately $2 million to date and is evaluating further expenditures. Dominion Gas is unable to estimate the CAA New Source Review requirements, NSPS, the Title V permit program and the stations’ respective State Implementation Plans. In May 2010, Dominion received a request for information pursuant to Section 114additional potential impacts on results of the CAA from the EPA. The request concerned historical operating changes and capital improvements undertaken at Brayton Point. Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. Dominion entered into settlement discussions with the U.S. government and reached an agreement to settle the allegations. In April 2013, the U.S. government lodged a consent decree and complaint with the U.S. District Court for the Central District of Illinois that resolves all alleged violations at State Line, Kincaid and Brayton Point. The settlement mandates the closure of State Line, installation of certain control technology at Kincaid and Brayton Point, the achievement of certain emissions limitations, payment of a civil penalty of $3 million and funding of $10 million in environmental mitigation projects. In July 2013, the court entered the consent decree, concluding the enforcement action. Dominion previously accrued a liability of $13 millionoperations, financial condition and/or cash flows related to this matter. State Line ceased operations in March 2012 and was sold in June 2012. The installation of pollution control technology was in progress at Kincaid and had been completed at Brayton Point.
In August 2013, Dominion sold Kincaid2012, the EPA issued the first NSPS impacting the natural gas production and Brayton Point. Undergathering sectors and made revisions to the termsNSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of volatile organic compound emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the sale transaction, Dominion retained the $13 million liability associatedupstream sector. Compliance with these rules is required for installations and wells constructed or reconstructed after August 23, 2011. The cost to comply with the settlement agreement.NSPS will depend on the number of new wells and new equipment installations subject to the rule; therefore, Dominion has paidGas is unable to estimate the civil penalty and is implementing the environmental mitigation projects.
Combined Notespotential impacts on results of operations, financial condition and/or cash flows related to Consolidated Financial Statements, Continuedthis matter.
WATER The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. Dominion and Virginia PowerThe Companies must comply with applicable aspects of the CWA programs at their operating facilities. In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two mgd, with a heightened entrainment analysis for those facilities over 125 mgd. Dominion and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. While the impacts of this rule could be material to Dominion’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power. In September 2010, Millstone’s NPDES permit was reissued under the CWA. The conditions of the permit require an evaluation of control technologies that could result in additional expenditures in the future. The report summarizing the results of
Combined Notes to Consolidated Financial Statements, Continued the evaluation was submitted in August 2012 and is under review by the Connecticut Department of Energy and Environmental Protection. Dominion cannot currently predict the outcome of this review. In October 2010, the permit issuance was appealed to the state court by a private plaintiff. The permit is expected to remain in effect during the appeal. Dominion is currently unable to make an estimate of the potential financial statement impacts related to this matter. SOLIDAND HAZARDOUS WASTE The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight. From time to time, Dominion, or Virginia Power, or Dominion Gas may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion, or Virginia Power, or Dominion Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. Except as noted below, the Companies do not believe this will have a material effect on results of operations, financial condition and/or cash flows. In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. In November 2011, Virginia Power and a number of other parties notified the EPA that they are declining to undertake the work set forth in the UAO. The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO. Virginia Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter. Dominion has determined that it is associated with 17 former manufactured gas plant sites, three of which pertain to Virginia Power.Power and 12 of which pertain to Dominion Gas. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which Dominion and Virginia Powerthe Companies are associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. DominionVirginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. A remedy has not been selected. Due to the uncertainty surrounding the other sites, Dominion isthe Companies are unable to make an estimate of the potential financial statement impacts. In December 2014, the EPA Administrator signed the final rule regulating the management of CCRs stored in impoundments (ash ponds) and landfills and designating those CCRs as nonhazardous wastes under Subtitle D of the RCRA. The final rule regulates CCR landfills, ash ponds that still receive and manage CCRs (existing ash ponds), and ash ponds that do not receive, but still store CCRs (inactive ash ponds). Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. Virginia Power is also evaluating other features at its facilities for potential applicability under the final CCR rule. It is likely that the final rule will cause Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time. After closure of these structures, Virginia Power will continue to perform required monitoring, corrective action, and post-closure care activities as necessary to comply with the final rule. While Virginia Power is still evaluating the cost of compliance, there could be a material impact to its financial position, results of operations or cash flows. CLIMATE CHANGE LEGISLATIONAND REGULATION Massachusetts, Rhode Island, Connecticut, and Maryland, among other states, have joined RGGI, a multi-state effort to reduce CO2 emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO2 emissions from power plants in participating states are required to be stabilized at current levels from 2009 to 2015. Further reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO2 emissions. During 2012, RGGI underwent a program review, and in February 2013, revisions to the RGGI model rule were issued that include a reduction of the regional CO2 emissions cap from 165 million tons to 91 million tons beginning in January 2014, with an additional 2.5% reduction per year through 2020. The revisions also include changes to compliance demonstration requirements for regulated entities, offset and cost containment mechanisms. Most of the RGGI states have completed the regulatory and/or legislative processes required to amend existing state regulations to implement the RGGI program changes. However, as a result of the recent sales of several power plants located in these states, Dominion does not expect that RGGI will have a material effect on operations, financial condition, and/or cash flows.
In December 2009, the EPA issued their Final Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act, finding that GHGs “endanger both the public health and the public welfare of current and future generations.” On April 1, 2010, the EPA and the Department of Transportation’s National Highway Safety Administration announced a joint final rule establishing a pro-
gram that will dramatically reduce GHG emissions and improve fuel economy for new cars and trucks sold in the United States. These rules took effect in January 2011 and established GHG emissions as regulated pollutants under the CAA.
In May 2010, the EPA issued the Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule that, combined with prior actions, require Dominion and Virginia Power to obtain permits for GHG emissions for new and modified facilities over certain size thresholds, and meet best available control technology for GHG emissions. The EPA has issued draft guidance for GHG permitting, including best available control technology.
In April 2012, the EPA published proposed NSPS for GHG emissions for new electric generating units. This proposed rule set national emission standards for new coal, oil, integrated gasification, and combined cycle units larger than 25MW. The proposed rule covered CO2 only and does not apply to existing sources. The proposed rule also does not apply to any new or existing biomass units. In June 2013, the President of the U.S. released a Climate Action Plan focusing on ways to meet the national GHG reduction goal of 17% from 2005 levels by 2020. Pursuant to the Presidential Memorandum issued in conjunction with the Climate Action Plan, the EPA withdrew the April 2012 proposal and re-proposed the NSPS standards for new sources on January 8, 2014 and is expected to finalize the rule in 2014 or early 2015. The Presidential Memorandum also directed the EPA to propose a rule for reconstructed, modified and existing sources of GHG emissions no later than June 2014, and issue a final rule no later than June 2015, to provide guidelines to the states to achieve the required GHG reductions. Dominion currently cannot predict with certainty the direct or indirect financial impact on operations from these rule revisions, but believes the expenditures to comply with any new requirements could be material.
In October 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the D.C. Circuit Court’s June 2012 decision upholding the EPA’s regulation of GHG emissions from stationary sources under the CAA. The court’s decision could potentially impact EPA’s continued implementation of current Prevention of Significant Deterioration regulations applicableCAA’s permitting programs. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources in relation to GHG. It is not anticipated, however, thatbased solely on GHG emissions. However, the court’s decision would affectCourt upheld the EPA’s development ofability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. On July 24, 2014, the GHG NSPS rulesEPA issued a memorandum specifying that it will no longer apply or enforce federal regulations or EPA-approved PSD state implementation plan provisions that require new and modified stationary sources to obtain a PSD permit when GHGs are the only pollutant that would be emitted at levels that exceed the permitting thresholds. In addition, the EPA stated that it will continue to use the existing thresholds to apply to sources that are otherwise subject to PSD for conventional pollutants until it completes a new sources,rulemaking either justifying and upholding those thresholds or setting new ones. Some states have issued interim guidance that follows
the EPA guidance. Due to uncertainty regarding what additional actions states may take to amend their existing sources, asregulations and what action the authority for those rules comes fromEPA ultimately takes to address the Court ruling under a different section ofnew rulemaking, the CAA than what is at issue inCompanies cannot predict the Supreme Court case. It is uncertainimpact to their financial statements at this time whether the court’s decision will have any material impact on Dominion’s operations.time. In July 2011, the EPA signed a final rule deferring the need for Prevention of Significant DeteriorationPSD and Title V permitting for CO2 emissions for biomass projects. This rule temporarily deferred for a period of up to 3three years the consideration of CO2 emissions from biomass projects when determining whether a stationary source meets the Prevention of Significant DeteriorationPSD and Title V applicability thresholds, including those for the application of best available control technology.BACT. The deferral policy expired in July 2014. In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however, a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the CO2 deferral period. It is unclear how the court’s decision or the EPA’s final policy regarding the treatment of specific feedstock will affect biomass sources that were permitted during the deferral period, period; however, the expenditures to comply with any new requirements could be material.material to Dominion’s and Virginia Power’s financial statements.
NatriumOther Legal Matters
The Companies are defendants in a number of lawsuits and Blue Racer In January 2011, Dominion announcedclaims involving unrelated incidents of property damage and personal injury. Due to the development of a natural gas processing and fractionation facility in Natrium, West Virginia, and in July 2011 it executed a contract foruncertainty surrounding these matters, the constructionCompanies are unable to make an estimate of the first phase of the facility. The first phase of the project is fully contracted and was placed into service in May 2013. In August 2013, the Natrium natural gas processing and fractionation facility was contributed to the Blue Racer joint venture. In September 2013, the Natrium facility was shut down followingpotential financial statement impacts; however, they could have a fire at the plant. It returned to service in January 2014. There was no material impact on Dominion’s financial condition, results of operations, financial condition and/or cash flows.
MF GlobalAppalachian Gateway
Prior to October 31, 2011, certain of Dominion’s subsidiaries executed certain commodity transactions on exchanges using MF Global, an FCM registered withFollowing the CFTC. In order to secure its potential exposure on these commodity transactions, Dominion posted certain required margin collateral with MF Global. The parent company of MF Global, MF Global Holdings Ltd., filed for bankruptcy relief under Chapter 11completion of the U.S. Bankruptcy Code on October 31, 2011. OnAppalachian Gateway Project in 2012, DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the same date, theproject. In July 2013, DTI filed a complaint in U.S. District Court, Eastern District of Virginia for breach of contract, accounting and declaratory relief. The contractor filed a motion to dismiss, or in the alternative, a motion to transfer venue to Pennsylvania and/or West Virginia, where the pipelines were constructed. DTI filed an opposition to the contractor’s motion in August 2013. In November 2013, the court granted the contractor’s motion on the basis that DTI must first comply with the dispute resolution process. Pursuant to the ruling, DTI intends to mediate the matter. This case is pending. DTI has accrued a liability of approximately $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.
Ash Pond Closure Costs In September 2014, Virginia Power received a notice from the SELC on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at the Possum Point Power Station. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point’s historical and active ash storage facilities. A similar notice from the SELC on behalf of Sierra Club was subsequently received related to Chesapeake. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum Point, Chesapeake and Bremo to the SELC as settlement of the potential litigation. In January 2015, the SELC declined the offer as presented, however the issue is open to potential further negotiations. As a result of the settlement offer, Virginia Power recognized a charge of $121 million in other operations and maintenance expense in its Consolidated Statements of Income. Cove Point Dominion is constructing the Liquefaction Project at the Cove Point facility, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. In April 2013, Cove Point filed with FERC for permission to build liquefaction and other facilities related to the export of natural gas. In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project. In October 2014, several parties filed a motion with FERC to stay the order and requested rehearing. The order remains in effect pending consideration of the motion by FERC. In April 2013, Cove Point filed an application with the Maryland Commission requesting authorization to construct a generating station in connection with the Liquefaction Project. In May 2014, the Maryland Commission granted the CPCN authorizing the construction of such generating station. The CPCN obligates Cove Point to make payments totaling approximately $48 million. These payments consist of $40 million to the Strategic Energy Investments Fund over a five-year period beginning in 2015 and $8 million to Maryland low income energy assistance programs over a twenty-year period expected to begin in 2018. In December 2014, upon receipt of applicable approvals to commence construction of the generating station, Dominion recorded the present value of the obligation as an increase to property, plant and equipment and a corresponding liability. In June 2014, a party filed a notice of petition for judicial review of the CPCN with the Circuit Court for Baltimore City in Maryland. In September 2014, the party filed with the Maryland Commission a motion to stay the CPCN pending judicial review of the CPCN. In December 2014, the Circuit Court issued an order affirming the Maryland Commission’s grant of the CPCN and dismissing the appeal, and the motion for stay was denied by the Maryland Commission. In January 2015, the same party filed a Notice of Appeal of the Baltimore Circuit Court’s Order affirming the Maryland Commission’s grant of the CPCN with the Court of Special Appeals for the Southern DistrictCircuit Court of New York appointed a trustee to oversee the liquidation of MF Global pursuant to the Securities Investor Protection Act.Baltimore City. This appeal is pending. In accordance with court-approved procedures, Dominion transferred to other FCMs all open positions executed using MF Global. The initial margin posted for these open positions at October 31, 2011 was approximately $73 million. Dominion had received approximately $17 million of this amount through the liquidation process as of December 31, 2012. In January 2013, Dominion sold the remaining claims of approximately $56 million to a third party at a small discount.
Nuclear Matters In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as INPO. Like other U.S. nuclear operators, Dominion has been gathering supporting data and participating in industry initiatives focused on the ability to respond to and mitigate the consequences of design-basis and beyond-design-basis events at its stations. In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident
Combined Notes to Consolidated Financial Statements, Continued and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3, with the Tier 1 recommendations consisting of actions which the staff determined should be started without unnecessary delay. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible. Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction
Combined Notes to Consolidated Financial Statements, Continued
permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion require implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation. The orders require prompt implementation of the safety enhancements and completion of implementation within two refueling outages or by December 31, 2016, whichever comes first. Implementation of these enhancements is currently in progress. The information requests issued by the NRC request each reactor to reevaluate the seismic and flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. Dominion and Virginia Power do not currently expect that compliance with the NRC’s March 2012 orders and information requests will materially impact their financial position, results of operations or cash flows during the approximately four-year implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion and Virginia Power are currently unable to estimate the potential financial impacts related to compliance with Tier 2 and Tier 3 recommendations. Nuclear Operations NUCLEAR DECOMMISSIONING—MINIMUM FINANCIAL ASSURANCE The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 20132014 calculation for the NRC minimum financial assurance amount, aggregated for Dominion’s and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.8$2.9 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 20132014 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 20132014 U.S. Bureau of Labor Statistics indices. Dominion believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion and Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial guarantees instruments recognized by the NRC. See Note 6 to the Consolidated Financial Statements for additional information on Kewaunee.Kewaunee, and Note 9 for additional information on nuclear decommissioning trust investments.
NUCLEAR INSURANCE The Price-Anderson Amendments Act of 1988 provides the public up to $13.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies 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. Effective June 7, 2013 for Kewaunee and July 1, 2013 for Millstone and Virginia Power’s nuclear units, theThe current levels of nuclear property insurance coverage were reduced to the following:for Dominion’s and Virginia Power’s nuclear units is as follows:
| | | | | | | | Coverage | | | (billions) | | | | Dominion | | | | | Millstone | | $ | 1.70 | | Kewaunee | | | 1.06 | | Virginia Power(1) | | | | | Surry | | $ | 1.70 | | North Anna | | | 1.70 | |
| (1) | Surry and North Anna share a blanket property limit of $450$200 million. |
The Companies’Dominion’s and Virginia Power’s nuclear property insurance coverage for Millstone, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. Kewaunee meets the NRC minimum requirement of $1.06 billion. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $71$72 million and $39$42 million, respectively. Based on the severity of the
incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination. Millstone and Virginia Power also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, the Companies are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $19$20 million and $9 million, respectively.
During 2013, Kewaunee ceased power production and commenced decommissioning activities. Effective February 1, 2013, Kewaunee’s accidental outage policy for replacement power costs was canceled.
ODEC, a part owner of North Anna, and Massachusetts Municipal and Green Mountain, part owners of Millstone’s Unit 3, are responsible to Dominion and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance. SPENT NUCLEAR FUEL Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Companies’Dominion’s and Virginia Power’s contracts with the DOE. The CompaniesDominion and Virginia Power have previously received damages award payments and settlement payments related to these contracts. In 2012, Dominion and Virginia Power resolved additional claims for damages incurred at Millstone, Kewaunee, Surry and North Anna with the Authorized Representative of the Attorney General. The CompaniesDominion and Virginia Power entered into settlement agreements that resolved claims for damages incurred through December 31, 2010, and also provideprovided for periodic payments after that date for damages incurred through December 31, 2013. Initial settlement payments in the amounts of $20 million for Millstone, $6 million for Kewaunee and $75 million for Surry and North Anna were received in the fourth quarter of 2012. In the fourth quarter of 2013, Dominion received payment of approximately $5 million for resolution of claims incurred at Millstone for the period January 1, 2011 through June 30, 2012. The government has formally accepted an offer of settlement for resolution of claims incurred at Kewaunee in the amount of approximately $2 million for the period January 1, 2011 through December 31, 2012, and payment is expected in the first quarter of 2014. By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone plants have been extended to provide for periodic payments for damages incurred through December 31, 2016. Possible extension of the Kewaunee settlement agreement is being evaluated. The CompaniesIn 2014, Virginia Power and Dominion received payments of $27 million for the resolution of claims incurred at North Anna and Surry for the period January 1, 2011 through December 31, 2012 and $17 million for the resolution of claims incurred at Millstone for the period of July 1, 2012 through June 30, 2013. In 2014, Dominion also received payments totaling $7 million for the resolution of claims incurred at Kewaunee for periods from January 1, 2011 through December 31, 2013. In 2013, Dominion received payment of $5 million for resolution of claims incurred at Millstone for the period January 1, 2011 through June 30, 2012.
Dominion and Virginia Power continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion’s receivables for spent nuclear fuel-related costs totaled $79$69 million and $36$79 million at December 31, 20132014 and 2012,2013, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $50$41 million and $26$50 million at December 31, 20132014 and 2012,2013, respectively. Pursuant to a November 2013 decision of the U.S Court of Appeals for the District of ColumbiaD.C. Circuit, in January 2014 the Secretary of the DOE sent a recommendation to the U.S. Congress to adjust to zero the current fee of $1 per MWh for electricity paid by civilian nuclear power generators for disposal of spent nuclear fuel. The government continues to pursue further judicial review of the November 2013 decision and until such time as the processes specified in the Nuclear Waste Policy Act for adjustment of the fee have been completed, and as of May 2014, Dominion and Virginia Power are completed, civilian nuclear power generators, including the Companies, areno longer required to pay the waste fee. In 2013,2014, Dominion and Virginia Power recognized fees of $44$16 million and $27$10 million, respectively. The CompaniesDominion and Virginia Power will continue to manage their spent fuel until it is accepted by the DOE.
Long-Term Purchase Agreements At December 31, 2013,2014, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services: | | | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | Thereafter | | Total | | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 | | Thereafter | | Total | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchased electric capacity(1) | | $ | 336 | | | $ | 316 | | | $ | 253 | | | $ | 159 | | | $ | 104 | | | $ | 163 | | | $ | 1,331 | | | $ | 313 | | | $ | 250 | | | $ | 158 | | | $ | 104 | | | $ | 65 | | | $ | 99 | | | $ | 989 | |
| (1) | Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2013,2014, the present value of Virginia Power’s total commitment for capacity payments is $1.1 billion.$833 million. Capacity payments totaled $330 million, $345 million, $337 million, and $338$337 million, and energy payments totaled $304 million, $236 million, and $214 million for the years ended 2014, 2013 and $275 million for 2013, 2012, and 2011, respectively. |
Lease Commitments Dominion and Virginia PowerThe Companies’ lease various facilities, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 20132014 are as follows:
| | | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | 2018 | | | Thereafter | | | Total | | | 2015 | | | 2016 | | | 2017 | | | 2018 | | | 2019 | | | Thereafter | | | Total | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dominion | | $ | 63 | | | $ | 60 | | | $ | 51 | | | $ | 43 | | | $ | 37 | | | $ | 87 | | | $ | 341 | | | $ | 63 | | | $ | 57 | | | $ | 49 | | | $ | 43 | | | $ | 36 | | | $ | 79 | | | $ | 327 | | Virginia Power | | $ | 27 | | | $ | 26 | | | $ | 21 | | | $ | 17 | | | $ | 14 | | | $ | 27 | | | $ | 132 | | | $ | 30 | | | $ | 26 | | | $ | 21 | | | $ | 18 | | | $ | 12 | | | $ | 26 | | | $ | 133 | | Dominion Gas | | | $ | 28 | | | $ | 25 | | | $ | 23 | | | $ | 21 | | | $ | 19 | | | $ | 25 | | | $ | 141 | |
Rental expense for Dominion totaled $92 million, $101 million, and $112 million for 2014, 2013 and $155 million for 2013, 2012, and 2011, respectively. Rental expense for Virginia Power totaled $43 million, $42 million, and $48 million for 2014, 2013, and $502012, respectively. Rental expense for Dominion Gas totaled $35 million forin 2014 and $15 million in each 2013 2012, and 2011, respectively.2012. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.
Combined Notes to Consolidated Financial Statements, Continued Guarantees, Surety Bonds and Letters of Credit DOMINIONDOMINION
At December 31, 2013,2014, Dominion had issued $69$74 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2013,2014, Dominion’s exposure under these guarantees was $39$49 million, primarily related to certain reserve requirements associated with non-recourse financing. In addition to the above guarantees, Dominion and its partners, Shell and BP, may be required to make additional periodic equity contributions to NedPower and Fowler Ridge in connection with certain funding requirements associated with their respective non-recourse financings. As of December 31, 2013, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $90 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million.
Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their com-
Combined Notes to Consolidated Financial Statements, Continued
mercialcommercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.
At December 31, 2013,2014, Dominion had issued the following subsidiary guarantees: | | | | Stated Limit | | | Value(1) | | | Stated Limit | | | Value(1) | | | (millions) | | | | | | | | | | | | | Subsidiary debt(2) | | $ | 27 | | | $ | 27 | | | $ | 27 | | | $ | 27 | | Commodity transactions(3) | | | 3,158 | | | | 403 | | | | 3,151 | | | | 919 | | Nuclear obligations(4) | | | 232 | | | | 68 | | | | 215 | | | | 76 | | Cove Point(5) | | | 335 | | | | — | | | | 1,910 | | | | — | | Other(6) | | | 669 | | | | 108 | | | Solar(6) | | | | 531 | | | | 396 | | Other(7) | | | | 532 | | | | 35 | | Total | | $ | 4,421 | | | $ | 606 | | | $ | 6,366 | | | $ | 1,453 | |
| (1) | Represents the estimated portion of the guarantee’s stated limit that is utilized as of December 31, 20132014 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount. |
| (2) | Guarantee of debt of a DEI subsidiary. In the event of default by the subsidiary, Dominion would be obligated to repay such amounts. |
| (3) | Guarantees related to energy trading and marketing activities and other commodity commitments of certain subsidiaries, including subsidiaries of Virginia Power, Dominion Gas and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion would be obligated to satisfy such obligation. Dominion and its subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits. |
| (4) | Guarantees related to certain DEI subsidiaries’ potential retrospective premiums that could be assessed if there is a nuclear incident under Dominion’s nuclear insurance programs and guarantees for a DEI subsidiary’s and Virginia Power’s commitment to buy nuclear fuel. Excludes Dominion’s agreement to provide up to $150 million and $60 million to two DEI subsidiaries to pay the operating expenses of Millstone and Kewaunee, respectively, in(in the event of a prolonged outage,outage) and Kewaunee, respectively, as part of satisfying certain NRC requirements concerned with ensuring adequate funding for the operations of nuclear power stations. The agreement for Kewaunee also provides for funds through the completion of decommissioning. |
| (5) | Guarantees related to Cove Point, in support of terminal services, transportation and construction. Two of the guarantees have no stated limit, one guarantee has a $150 million limit, and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million. |
| (6) | Includes guarantees to facilitate the development of solar projects including agreementsguarantees to support terminal service and transportation agreements as well as an engineering, procurement and construction contract for new liquefaction facilities.the issuance of full notice to proceed under EPC agreements. Includes certain guarantees that do not have stated limits. Also includes guarantees entered into by DEI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects. |
(6)(7) | Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $72 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits. |
Additionally, as ofat December 31, 20132014, Dominion had purchased $147$133 million of surety bonds, including $64 million at Virginia Power and $30 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $11$48 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Dominion isthe Companies are obligated to indemnify the respective surety bond company for any amounts paid. VIRGINIA POWER
As of December 31, 2013,2014, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. The related debt matures in 2031. In the event of default by a conduit, Virginia Power had also purchased $59 million of surety bonds for various purposes, including providing workers’ compensation coverage, and authorized the issuance of letters of credit by financial institutions of $1 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Virginia Power iswould be obligated to indemnifyrepay such amounts, which are limited to the respective surety bond company for any amounts paid.principal and interest then outstanding. Indemnifications As part of commercial contract negotiations in the normal course of business, Dominion and Virginia Powerthe Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. Dominion and Virginia PowerThe Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2013, Dominion and Virginia Power2014, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position. NOTE 23. CREDIT RISK Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction. Dominion and Virginia Power
The Companies maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 20132014 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance. GENERAL DOMINION As a diversified energy company, Dominion transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base,
Dominion is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations. Dominion’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include trading of energy-related commodities, marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of any collateral. At December 31, 2013,2014, Dominion’s credit exposure totaled $263$228 million. Of this amount, investment grade counterparties, including those internally rated, represented 63%. No86%, and no single counterparty, exposurewhether investment grade or non-investment grade, exceeded 6%$23 million of Dominion’s total exposure. VIRGINIA POWER Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2013,2014, Virginia Power’s exposure to potential concentrations of credit risk was not considered material. DOMINION GAS Dominion Gas transacts mainly with major companies in the energy industry and with residential and commercial energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion Gas does not believe that this geographic concentration contributes to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Gas is not exposed to a significant concentration of credit risk for receivables arising from gas utility operations. In 2014, DTI provided service to 260 customers with approximately 94% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 41% of the total storage and transportation revenue and the thirty largest provided approximately 74% of the total storage and transportation revenue of approximately $718 million. Approximately 99% of the transmission capacity under contract on DTI’s pipeline is subscribed with long-term contracts (three years or greater). The remaining 1% is contracted on a year-to-year basis. Less than 1% of firm transportation capacity is currently unsubscribed. All storage services are subscribed under long-term contracts. East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates established by the Ohio Commission. Approximately 98% of East Ohio revenues are derived from its regulated gas distribution services. While individual customers of East Ohio have had increased amounts of bad debt in recent years, management believes that this concentration and bad debt risk is mitigated by the regulatory framework established by the Ohio Commission. See Note 13 for further information about Ohio’s PIPP and UEX Riders that mitigate East Ohio’s overall credit risk. CREDIT-RELATED CONTINGENT PROVISIONS The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 20132014 and 2012,2013, Dominion would have been required to post an additional $146$20 million and $110$146 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion had posted $1 million in collateral at December 31, 2014 and $76 million in collateral at December 31, 2013, and $4 million in collateral at December 31, 2012, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of
Combined Notes to Consolidated Financial Statements, Continued December 31, 2014 and 2013 and 2012 was $169$49 million and $163$169 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and Dominion Gas were not material as of December 31, 20132014 and 2012.2013. See Note 7 for further information about derivative instruments. NOTE 24. RELATED-PARTY TRANSACTIONS Virginia Power engagesand Dominion Gas engage in related-partyrelated party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s and Dominion Gas’ receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power isand Dominion Gas are included in Dominion’s consolidated federal income tax return and participates in certain Dominion benefit plans.return. A discussion of significant related-partyrelated party transactions follows. VIRGINIA POWER Transactions with Affiliates Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 19 for more information. As of December 31, 20132014 and 2012,2013, Virginia Power’s derivative assets and liabilities with affiliates were not material. Virginia Power participates in certain Dominion benefit plans as described in Note 21. At December 31, 2014 and 2013, Virginia Power’s amounts due to Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets, were $219 million and $144 million, respectively. At December 31, 2014, Virginia Power’s amounts due from Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred charges and other assets in the Consolidated Balance Sheets were $37 million and at December 31, 2013, amounts due to Dominion and reflected in noncurrent pension and other postretirement benefit liabilities were $3 million. DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage. Presented below are significant transactions with DRS and other affiliates: | | Year Ended December 31, | | 2013 | | | 2012 | | | 2011 | | | 2014 | | | 2013 | | | 2012 | | | (millions) | | | | | | | | | | | | | | | | | | | Commodity purchases from affiliates | | $ | 417 | | | $ | 368 | | | $ | 376 | | | $ | 543 | | | $ | 417 | | | $ | 368 | | Services provided by affiliates | | | 415 | | | | 399 | | | | 393 | | | | 432 | | | | 415 | | | | 399 | | Services provided to affiliates | | | 21 | | | | 19 | | | | 21 | | | | 22 | | | | 21 | | | | 19 | |
In the fourth quarter of 2011, a subsidiary of Virginia Power purchased nuclear fuel-related inventory from an affiliate for $39 million for future use at its nuclear generation stations.
| (1) | Includes capitalized expenditures. |
Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were $97$427 million and $243$97 million in short-term demand note borrowings from Dominion as of December 31, 20132014 and 2012,2013, respectively. Virginia Power’sPower had no outstanding borrowings, net of repayments under the Dominion money pool for its nonregulated subsidiaries totaled $192 million as of December 31, 2012. There were no borrowings as of December 31,2014 and 2013. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the years ended December 31, 2014, 2013 2012 and 2011.2012. There were no issuances of Virginia Power’s common stock to Dominion in 2014, 2013 2012 or 2011.2012. DOMINION GAS Transactions with Affiliates Dominion Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Gas provides transportation and storage services to affiliates. Dominion Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of December 31, 2014 and 2013, all of Dominion Gas’ commodity derivatives were with affiliates. See Notes 7 and 19 for more information. See Note 9 for information regarding sales of assets to an affiliate. Dominion Gas participates in certain Dominion benefit plans as described in Note 21. At December 31, 2014 and 2013, Dominion Gas’ amounts due from Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets, were $614 million and $577 million, respectively. At December 31, 2014 and 2013, Dominion Gas’ liabilities to Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred credits and other liabilities in the Consolidated Balance Sheets were $7 million and $14 million, respectively. | | | | | | | | | | | | | | Year Ended December 31, | | 2014 | | | 2013 | | | 2012 | | | (millions) | | | | | | | | | | Purchases of natural gas and transportation and storage services from affiliates | | $ | 34 | | | $ | 31 | | | $ | 14 | | Sales of natural gas and transportation and storage services to affiliates | | | 84 | | | | 109 | | | | 64 | |
DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Gas. Dominion Gas provides certain services to affiliates, including technical services. The costs of these services follow: | | | | | | | | | | | | | | Year Ended December 31, | | 2014 | | | 2013 | | | 2012 | | | (millions) | | | | | | | | | | Services provided by affiliates(1) | | $ | 106 | | | $ | 116 | | | $ | 107 | | Services provided to affiliates | | | 17 | | | | 4 | | | | 3 | |
| (1) | Includes capitalized expenditures. |
Combined Notes to Consolidated Financial Statements, Continued
The following table presents affiliated and related party activity reflected in Dominion Gas’ Consolidated Balance Sheets: | | | | | | | | | | At December 31, | | 2014 | | | 2013 | | | (millions) | | | | | | | Customer receivables from related parties(1) | | $ | 22 | | | $ | 3 | | Imbalances receivable from affiliates(2) | | | 3 | | | | 6 | | Imbalances payable to affiliates(3) | | | — | | | | 1 | | Affiliated notes receivable(4) | | | 9 | | | | 5 | |
| (1) | Includes $17 million due from Atlantic Coast Pipeline, an affiliated VIE. |
| (2) | Amounts are presented in other current assets in Dominion Gas’ Consolidated Balance Sheets. |
| (3) | Amounts are presented in other current liabilities in Dominion Gas’ Consolidated Balance Sheets. |
| (4) | Amounts are presented in other deferred charges and other assets in Dominion Gas’ Consolidated Balance Sheets. |
Dominion Gas’ borrowings under the IRCA with Dominion totaled $384 million and $1.3 billion as of December 31, 2014 and 2013, respectively. Interest charges related to Dominion Gas’ total borrowings from Dominion were $4 million, $35 million and $61 million for the years ended December 31, 2014, 2013 and 2012, respectively. NOTE 25. OPERATING SEGMENTS Dominion and Virginia PowerThe Companies are organized primarily on the basis of products and services sold in the U.S. A description of the operations included in the Companies’ primary operating segments is as follows:
| | | | | | | | | Primary Operating Segment | | Description of Operations | | Dominion | | Virginia Power | | Dominion Gas | DVP | | Regulated electric distribution | | X | | X | | | | | | Regulated electric transmission | | X | | X | | | Dominion Generation | | Regulated electric fleet | | X | | X | | | | | Merchant electric fleet | | X | | | | | | | | Nonregulated retail energy marketing (electric and gas)(1) | | X | | | | | Dominion Energy | | Gas transmission and storage(1) | | X | | | | X | | | Gas distribution and storage | | X | | | | X | | | LNG servicesGas gathering and processing
| | X | | | | X | | | | Producer servicesLNG import and storage
| | X | | | | |
| (1) | As a result of Dominion’s decision to realign its business units effective for 2013 year-end reporting, nonregulated retail energy marketing operations were moved from DVP to the Dominion Generation segment.Includes remaining producer services activities. |
In addition to the operating segments above, the Companies also report a Corporate and Other segment. The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.DOMINION
The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued which are discussed in Note 3.or sold. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. In January 2014, Dominion announced it would exit the electric retail energy marketing business. Dominion completed the sale in March 2014. As a result, the earnings impact from the electric retail energy marketing business has been included in the Corporate and Other Segment of Dominion for 2014 first quarter results of operations. In the second quarter of 2013, Dominion commenced a restructuring of its producer services business, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates. The restructuring, which was completed in the first quarter of 2014, resulted in the termination of natural gas trading and certain energy marketing activities. As a result, the earnings impact from natural gas trading and certain energy marketing activities has been included in the Corporate and Other Segment of Dominion.Dominion for 2014. DOMINIONIn 2014, Dominion reported after-tax net expense of $970 million in the Corporate and Other segment, with $544 million of these net expenses attributable to specific items related to its operating segments.
The net expenses for specific items in 2014 primarily related to the impact of the following items: | Ÿ | | $374 million ($248 million after-tax) in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, attributable to Dominion Generation; |
| Ÿ | | A $319 million ($193 million after-tax) net loss related to the producer services business discussed above, attributable to Dominion Energy; and |
| Ÿ | | A $121 million ($74 million after-tax) charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities, attributable to Dominion Generation. |
In 2013, Dominion reported after-tax net expense of $452 million in the Corporate and Other segment, with $184 million of these net expenses attributable to specific items related to its operating segments. The net expenses for specific items in 2013 primarily related to the impact of the following items: | Ÿ | | A $135 million ($92 million after-tax) net loss from discontinued operations of Brayton Point and Kincaid, including debt extinguishment of $64 million ($38 million after-tax) related to the sale, impairment charges of $48 million ($28 |
| | million after-tax), a $17 million ($18 million after-tax) loss on the sale which includes a $16 million write-off of goodwill, and a $6 million ($8 million after-tax) loss from operations, attributable to Dominion Generation; and |
| Ÿ | | A $182 million ($109 million after-tax) net loss, including a $55 million ($33 million after-tax) impairment charge related to certain natural gas infrastructure assets and a $127 million ($76 million after-tax) loss related to the producer services business discussed above, attributable to Dominion Energy; partially offset by |
| Ÿ | | An $81 million ($49 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation. |
Combined Notes to Consolidated Financial Statements, Continued In 2012, Dominion reported after-tax net expense of $1.7 billion in the Corporate and Other segment, with $1.5 billion of these net expenses attributable to specific items related to its operating segments. The net expenses for specific items in 2012 primarily related to the impact of the following items: | Ÿ | | A $1.7 billion ($1.1 billion after-tax) net loss from discontinued operations, including impairment charges, of Brayton Point and Kincaid, which were sold in 2013, attributable to Dominion Generation; |
| Ÿ | | A $467 million ($303 million after-tax) net loss, including impairment charges, primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013, attributable to Dominion Generation; |
| Ÿ | | An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP; and |
| Ÿ | | A $49 million ($22 million after-tax) loss from discontinued operations of State Line and Salem Harbor which were sold in 2012, attributable to Dominion Generation. |
In 2011, Dominion reported after-tax net expense of $607 million for specific items in the Corporate and Other segment, with $364 million of these net expenses attributable to specific items related to its operating segments.
The net expensesfollowing table presents segment information pertaining to Dominion’s operations: | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | DVP | | | Dominion Generation | | | Dominion Energy | | | Corporate and Other | | | Adjustments & Eliminations | | | Consolidated Total | | | (millions) | | | | | | | | | | | | | | | | | | | 2014 | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | $ | 1,918 | | | $ | 7,665 | | | $ | 1,718 | | | $ | (12 | ) | | $ | 1,147 | | | $ | 12,436 | | Intersegment revenue | | | 18 | | | | 70 | | | | 1,174 | | | | 572 | | | | (1,834 | ) | | | — | | Total operating revenue | | | 1,936 | | | | 7,735 | | | | 2,892 | | | | 560 | | | | (687 | ) | | | 12,436 | | Depreciation, depletion and amortization | | | 462 | | | | 516 | | | | 241 | | | | 73 | | | | — | | | | 1,292 | | Equity in earnings of equity method investees | | | — | | | | (18 | ) | | | 54 | | | | 10 | | | | — | | | | 46 | | Interest income | | | — | | | | 67 | | | | 14 | | | | 20 | | | | (33 | ) | | | 68 | | Interest and related charges | | | 205 | | | | 240 | | | | 11 | | | | 770 | | | | (33 | ) | | | 1,193 | | Income taxes | | | 317 | | | | 392 | | | | 436 | | | | (693 | ) | | | — | | | | 452 | | Net income (loss) attributable to Dominion | | | 502 | | | | 1,101 | | | | 677 | | | | (970 | ) | | | — | | | | 1,310 | | Investment in equity method investees | | | — | | | | 262 | | | | 796 | | | | 23 | | | | — | | | | 1,081 | | Capital expenditures | | | 1,652 | | | | 2,466 | | | | 1,329 | | | | 104 | | | | — | | | | 5,551 | | Total assets (billions) | | | 13.0 | | | | 24.2 | | | | 12.7 | | | | 8.7 | | | | (4.3 | ) | | | 54.3 | | 2013 | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | $ | 1,825 | | | $ | 8,445 | | | $ | 1,783 | | | $ | 3 | | | $ | 1,064 | | | $ | 13,120 | | Intersegment revenue | | | 9 | | | | 68 | | | | 1,063 | | | | 609 | | | | (1,749 | ) | | | — | | Total operating revenue | | | 1,834 | | | | 8,513 | | | | 2,846 | | | | 612 | | | | (685 | ) | | | 13,120 | | Depreciation, depletion and amortization | | | 427 | | | | 518 | | | | 228 | | | | 35 | | | | — | | | | 1,208 | | Equity in earnings of equity method investees | | | — | | | | (14 | ) | | | 21 | | | | 7 | | | | — | | | | 14 | | Interest income | | | — | | | | 66 | | | | 12 | | | | 42 | | | | (66 | ) | | | 54 | | Interest and related charges | | | 175 | | | | 220 | | | | 26 | | | | 522 | | | | (66 | ) | | | 877 | | Income taxes | | | 287 | | | | 483 | | | | 409 | | | | (287 | ) | | | — | | | | 892 | | Loss from discontinued operations, net of tax | | | — | | | | — | | | | — | | | | (92 | ) | | | — | | | | (92 | ) | Net income (loss) attributable to Dominion | | | 475 | | | | 1,031 | | | | 643 | | | | (452 | ) | | | — | | | | 1,697 | | Investment in equity method investees | | | — | | | | 280 | | | | 615 | | | | 21 | | | | — | | | | 916 | | Capital expenditures | | | 1,361 | | | | 1,605 | | | | 1,043 | | | | 95 | | | | — | | | | 4,104 | | Total assets (billions) | | | 11.9 | | | | 22.0 | | | | 12.1 | | | | 8.5 | | | | (4.4 | ) | | | 50.1 | | 2012 | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | $ | 1,846 | | | $ | 8,170 | | | $ | 1,813 | | | $ | 155 | | | $ | 851 | | | $ | 12,835 | | Intersegment revenue | | | 9 | | | | 104 | | | | 930 | | | | 608 | | | | (1,651 | ) | | | — | | Total operating revenue | | | 1,855 | | | | 8,274 | | | | 2,743 | | | | 763 | | | | (800 | ) | | | 12,835 | | Depreciation, depletion and amortization | | | 392 | | | | 483 | | | | 216 | | | | 36 | | | | — | | | | 1,127 | | Equity in earnings of equity method investees | | | — | | | | 3 | | | | 23 | | | | (1 | ) | | | — | | | | 25 | | Interest income | | | 1 | | | | 65 | | | | 30 | | | | 71 | | | | (106 | ) | | | 61 | | Interest and related charges | | | 187 | | | | 177 | | | | 47 | | | | 511 | | | | (106 | ) | | | 816 | | Income taxes | | | 278 | | | | 576 | | | | 352 | | | | (395 | ) | | | — | | | | 811 | | Loss from discontinued operations, net of tax | | | — | | | | — | | | | — | | | | (1,125 | ) | | | — | | | | (1,125 | ) | Net income (loss) attributable to Dominion | | | 439 | | | | 1,021 | | | | 551 | | | | (1,709 | ) | | | — | | | | 302 | | Capital expenditures | | | 1,158 | | | | 1,615 | | | | 1,350 | | | | 22 | | | | — | | | | 4,145 | |
Intersegment sales and transfers for specific itemsDominion are based on contractual arrangements and may result in 2011 primarily related to the impact of the following items:intersegment profit or loss that is eliminated in consolidation. Ÿ | | A $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units, attributable to Dominion Generation;
|
Ÿ | | A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP;
|
Ÿ | | A $66 million ($39 million after-tax) loss from the operations of Kewaunee, attributable to Dominion Generation;
|
Ÿ | | A $57 million ($33 million after-tax) net loss from discontinued operations of Brayton Point and Kincaid, which were sold in 2013, attributable to Dominion Generation;
|
Ÿ | | A $43 million ($26 million after-tax) charge related to the impairment of SO2 emissions allowances not expected to be consumed due to CSAPR, attributable to Dominion Generation; and
|
Ÿ | | A $34 million ($25 million after-tax) loss from discontinued operations of State Line and Salem Harbor which were sold in 2012, attributable to Dominion Generation.
|
The following table presents segment information pertaining to Dominion’s operations:
| | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | DVP(1) | | | Dominion Generation(1)(2) | | | Dominion Energy | | | Corporate and Other(2) | | | Adjustments &
Eliminations(1) | | | Consolidated Total | | | (millions) | | | | | | | | | | | | | | | | | | | 2013 | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | $ | 1,825 | | | $ | 8,445 | | | $ | 1,783 | | | $ | 3 | | | $ | 1,064 | | | $ | 13,120 | | Intersegment revenue | | | 9 | | | | 68 | | | | 1,063 | | | | 609 | | | | (1,749 | ) | | | — | | Total operating revenue | | | 1,834 | | | | 8,513 | | | | 2,846 | | | | 612 | | | | (685 | ) | | | 13,120 | | Depreciation, depletion and amortization | | | 427 | | | | 518 | | | | 228 | | | | 35 | | | | — | | | | 1,208 | | Equity in earnings of equity method investees | | | — | | | | (14 | ) | | | 21 | | | | 7 | | | | — | | | | 14 | | Interest income | | | — | | | | 66 | | | | 12 | | | | 42 | | | | (66 | ) | | | 54 | | Interest and related charges | | | 175 | | | | 220 | | | | 26 | | | | 522 | | | | (66 | ) | | | 877 | | Income taxes | | | 287 | | | | 483 | | | | 409 | | | | (287 | ) | | | — | | | | 892 | | Loss from discontinued operations, net of tax | | | — | | | | — | | | | — | | | | (92 | ) | | | — | | | | (92 | ) | Net income (loss) attributable to Dominion | | | 475 | | | | 1,031 | | | | 643 | | | | (452 | ) | | | — | | | | 1,697 | | Investment in equity method investees | | | — | | | | 280 | | | | 615 | | | | 21 | | | | — | | | | 916 | | Capital expenditures | | | 1,361 | | | | 1,605 | | | | 1,043 | | | | 95 | | | | — | | | | 4,104 | | Total assets (billions) | | | 11.9 | | | | 22.0 | | | | 12.1 | | | | 8.5 | | | | (4.4 | ) | | | 50.1 | | 2012 | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | $ | 1,846 | | | $ | 8,170 | | | $ | 1,813 | | | $ | 155 | | | $ | 851 | | | $ | 12,835 | | Intersegment revenue | | | 9 | | | | 104 | | | | 930 | | | | 608 | | | | (1,651 | ) | | | — | | Total operating revenue | | | 1,855 | | | | 8,274 | | | | 2,743 | | | | 763 | | | | (800 | ) | | | 12,835 | | Depreciation, depletion and amortization | | | 392 | | | | 483 | | | | 216 | | | | 36 | | | | — | | | | 1,127 | | Equity in earnings of equity method investees | | | — | | | | 3 | | | | 23 | | | | (1 | ) | | | — | | | | 25 | | Interest income | | | 1 | | | | 65 | | | | 30 | | | | 71 | | | | (106 | ) | | | 61 | | Interest and related charges | | | 187 | | | | 177 | | | | 47 | | | | 511 | | | | (106 | ) | | | 816 | | Income taxes | | | 278 | | | | 576 | | | | 352 | | | | (395 | ) | | | — | | | | 811 | | Loss from discontinued operations, net of tax | | | — | | | | — | | | | — | | | | (1,125 | ) | | | — | | | | (1,125 | ) | Net income (loss) attributable to Dominion | | | 439 | | | | 1,021 | | | | 551 | | | | (1,709 | ) | | | — | | | | 302 | | Investment in equity method investees | | | — | | | | 414 | | | | 141 | | | | 3 | | | | — | | | | 558 | | Capital expenditures | | | 1,158 | | | | 1,615 | | | | 1,350 | | | | 22 | | | | — | | | | 4,145 | | Total assets (billions) | | | 11.5 | | | | 21.8 | | | | 11.2 | | | | 12.6 | | | | (10.3 | ) | | | 46.8 | | 2011 | | | | | | | | | | | | | | | | | | | | | | | | | Total revenue from external customers | | $ | 1,791 | | | $ | 8,759 | | | $ | 2,044 | | | $ | 56 | | | $ | 1,115 | | | $ | 13,765 | | Intersegment revenue | | | 63 | | | | 123 | | | | 1,077 | | | | 595 | | | | (1,858 | ) | | | — | | Total operating revenue | | | 1,854 | | | | 8,882 | | | | 3,121 | | | | 651 | | | | (743 | ) | | | 13,765 | | Depreciation, depletion and amortization | | | 369 | | | | 413 | | | | 207 | | | | 29 | | | | — | | | | 1,018 | | Equity in earnings of equity method investees | | | — | | | | 3 | | | | 23 | | | | 9 | | | | — | | | | 35 | | Interest income | | | 10 | | | | 65 | | | | 27 | | | | 71 | | | | (106 | ) | | | 67 | | Interest and related charges | | | 183 | | | | 148 | | | | 57 | | | | 514 | | | | (106 | ) | | | 796 | | Income taxes | | | 264 | | | | 655 | | | | 323 | | | | (464 | ) | | | — | | | | 778 | | Loss from discontinued operations, net of tax | | | — | | | | — | | | | — | | | | (58 | ) | | | — | | | | (58 | ) | Net income (loss) attributable to Dominion | | | 416 | | | | 1,078 | | | | 521 | | | | (607 | ) | | | — | | | | 1,408 | | Capital expenditures | | | 1,091 | | | | 1,593 | | | | 907 | | | | 61 | | | | — | | | | 3,652 | |
(1) | Amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment. |
(2) | Segment information for 2012 and 2011 has been recast to reflect Brayton Point and Kincaid as discontinued operations, as discussed in Note 3. |
At December 31, 2013, 2012, and 2011, none of Dominion’s long-lived assets and no significant percentage of its operating revenues were associated with international operations.
VIRGINIA POWER The majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s DVP and Dominion Generation segments. The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. In 2014, Virginia Power reported after-tax net expenses of $342 million for specific items attributable to its operating segments in the Corporate and Other segment. The net expenses for specific items in 2014 primarily related to the impact of the following: | Ÿ | | $374 million ($248 million after-tax) in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, attributable to Dominion Generation; and |
| Ÿ | | A $121 million ($74 million after-tax) charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities, attributable to Dominion Generation. |
In 2013, Virginia Power reported after-tax net expenses of $47 million for specific items attributable to its operating segments in the Corporate and Other segment. The net expenses for specific items in 2013 primarily related to the impact of the following: | Ÿ | | A $40 million ($28 million after-tax) charge in connection with the 2013 Biennial Review Order, attributable to Dominion Generation. |
In 2012, Virginia Power reported after-tax net expenses of $51 million for specific items attributable to its operating segments in the Corporate and Other segment.
Combined Notes to Consolidated Financial Statements, Continued
The net expenses for specific items in 2012 primarily related to the impact of the following: | Ÿ | | An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP. |
In 2011, Virginia Power reported after-tax net expenses of $268 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2011 primarily related to the impact of the following:
Ÿ | | A $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired generating units, attributable to Dominion Generation;
|
Ÿ | | A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP; and
|
Ÿ | | A $43 million ($26 million after-tax) charge related to the impairment of SO2 emissions allowances not expected to be consumed due to CSAPR, attributable to Dominion Generation.
|
The following table presents segment information pertaining to Virginia Power’s operations: | | Year Ended December 31, | | DVP | | | Dominion
Generation | | | Corporate and
Other | | Adjustments &
Eliminations | | Consolidated
Total | | | DVP | | | Dominion Generation | | | Corporate and Other | | Adjustments & Eliminations | | Consolidated Total | | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | 2014 | | | | | | | | | | | | Operating revenue | | | $ | 1,928 | | | $ | 5,651 | | | $ | — | | | $ | — | | | $ | 7,579 | | Depreciation and amortization | | | | 462 | | | | 416 | | | | 37 | | | | — | | | | 915 | | Interest income | | | | — | | | | 8 | | | | — | | | | — | | | | 8 | | Interest and related charges | | | | 205 | | | | 203 | | | | 3 | | | | — | | | | 411 | | Income taxes | | | | 317 | | | | 416 | | | | (185 | ) | | | — | | | | 548 | | Net income (loss) | | | | 509 | | | | 691 | | | | (342 | ) | | | — | | | | 858 | | Capital expenditures | | | | 1,651 | | | | 1,456 | | | | — | | | | — | | | | 3,107 | | Total assets (billions) | | | | 13.2 | | | | 16.4 | | | | — | | | | (0.1 | ) | | | 29.5 | | 2013 | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 1,826 | | | $ | 5,475 | | | $ | (6 | ) | | $ | — | | | $ | 7,295 | | | $ | 1,826 | | | $ | 5,475 | | | $ | (6 | ) | | $ | — | | | $ | 7,295 | | Depreciation and amortization | | | 427 | | | | 425 | | | | 1 | | | | — | | | | 853 | | | | 427 | | | | 425 | | | | 1 | | | | — | | | | 853 | | Interest income | | | — | | | | 6 | | | | — | | | | — | | | | 6 | | | | — | | | | 6 | | | | — | | | | — | | | | 6 | | Interest and related charges | | | 175 | | | | 192 | | | | 2 | | | | — | | | | 369 | | | | 175 | | | | 192 | | | | 2 | | | | — | | | | 369 | | Income taxes | | | 286 | | | | 399 | | | | (26 | ) | | | — | | | | 659 | | | | 286 | | | | 399 | | | | (26 | ) | | | — | | | | 659 | | Net income (loss) | | | 483 | | | | 702 | | | | (47 | ) | | | — | | | | 1,138 | | | | 483 | | | | 702 | | | | (47 | ) | | | — | | | | 1,138 | | Capital expenditures | | | 1,360 | | | | 1,173 | | | | — | | | | — | | | | 2,533 | | | | 1,360 | | | | 1,173 | | | | — | | | | — | | | | 2,533 | | Total assets (billions) | | | 12.0 | | | | 15.1 | | | | — | | | | (0.1 | ) | | | 27.0 | | | | 12.0 | | | | 15.1 | | | | — | | | | (0.1 | ) | | | 27.0 | | 2012 | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 1,847 | | | $ | 5,379 | | | $ | — | | | $ | — | | | $ | 7,226 | | | $ | 1,847 | | | $ | 5,379 | | | $ | — | | | $ | — | | | $ | 7,226 | | Depreciation and amortization | | | 392 | | | | 390 | | | | — | | | | — | | | | 782 | | | | 392 | | | | 390 | | | | — | | | | — | | | | 782 | | Interest income | | | 1 | | | | 7 | | | | — | | | | — | | | | 8 | | | | 1 | | | | 7 | | | | — | | | | — | | | | 8 | | Interest and related charges | | | 186 | | | | 199 | | | | — | | | | — | | | | 385 | | | | 186 | | | | 199 | | | | — | | | | — | | | | 385 | | Income taxes | | | 277 | | | | 403 | | | | (27 | ) | | | — | | | | 653 | | | | 277 | | | | 403 | | | | (27 | ) | | | — | | | | 653 | | Net income (loss) | | | 448 | | | | 653 | | | | (51 | ) | | | — | | | | 1,050 | | | | 448 | | | | 653 | | | | (51 | ) | | | — | | | | 1,050 | | Capital expenditures | | | 1,142 | | | | 1,146 | | | | — | | | | — | | | | 2,288 | | | | 1,142 | | | | 1,146 | | | | — | | | | — | | | | 2,288 | | Total assets (billions) | | | 11.4 | | | | 14.8 | | | | — | | | | (1.4 | ) | | | 24.8 | | | 2011 | | | | | | | | | | | | Operating revenue | | $ | 1,793 | | | $ | 5,546 | | | $ | (93 | ) | | $ | — | | | $ | 7,246 | | | Depreciation and amortization | | | 368 | | | | 350 | | | | — | | | | — | | | | 718 | | | Interest income | | | 10 | | | | 8 | | | | — | | | | — | | | | 18 | | | Interest and related charges | | | 182 | | | | 199 | | | | (50 | ) | | | — | | | | 331 | | | Income taxes | | | 265 | | | | 447 | | | | (172 | ) | | | — | | | | 540 | | | Net income (loss) | | | 426 | | | | 664 | | | | (268 | ) | | | — | | | | 822 | | | Capital expenditures | | | 1,081 | | | | 1,009 | | | | — | | | | — | | | | 2,090 | | |
DOMINION GAS The Corporate and Other Segment of Dominion Gas primarily includes specific items attributable to Dominion Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance and the effect of certain items recorded at Dominion Gas as a result of Dominion’s basis in the net assets contributed. In 2014, Dominion Gas reported after-tax net expenses of $9 million in its Corporate and Other segment, with none of these net expenses attributable to specific items related to its operating segment. In 2013, Dominion Gas reported after-tax net expenses of $49 million in the Corporate and Other segment, with $41 million of these net expenses attributable to specific items related to its operating segment.
Combined Notes to Consolidated Financial Statements, Continued The net expenses for specific items in 2013 primarily related to the impact of the following: | Ÿ | | $55 million ($33 million after-tax) of impairment charges related to certain natural gas infrastructure assets; and |
| Ÿ | | A $14 million ($8 million after-tax) charge primarily reflecting severance pay and other benefits related to workforce reductions. |
In 2012, Dominion Gas reported after-tax net expenses of $10 million in its Corporate and Other segment, with none of these net expenses attributable to specific items related to its operating segment. The following table presents segment information pertaining to Dominion Gas’ operations: | | | | | | | | | | | | | | Year Ended December 31, | | Dominion
Energy | | | Corporate and Other | | | Consolidated Total | | | (millions) | | | | | | | | | | 2014 | | | | | | | | | | | | | Operating revenue | | $ | 1,898 | | | $ | — | | | $ | 1,898 | | Depreciation and amortization | | | 197 | | | | — | | | | 197 | | Equity in earnings of equity method investees | | | 21 | | | | — | | | | 21 | | Interest income | | | 1 | | | | — | | | | 1 | | Interest and related charges | | | 27 | | | | — | | | | 27 | | Income taxes | | | 340 | | | | (6 | ) | | | 334 | | Net income (loss) | | | 521 | | | | (9 | ) | | | 512 | | Investment in equity method investees | | | 107 | | | | — | | | | 107 | | Capital expenditures | | | 719 | | | | — | | | | 719 | | Total assets (billions) | | | 9.2 | | | | 0.6 | | | | 9.8 | | 2013 | | | | | | | | | | | | | Operating revenue | | $ | 1,937 | | | $ | — | | | $ | 1,937 | | Depreciation and amortization | | | 188 | | | | — | | | | 188 | | Equity in earnings of equity method investees | | | 22 | | | | — | | | | 22 | | Interest income | | | 2 | | | | — | | | | 2 | | Interest and related charges | | | 28 | | | | — | | | | 28 | | Income taxes | | | 333 | | | | (32 | ) | | | 301 | | Net income (loss) | | | 510 | | | | (49 | ) | | | 461 | | Investment in equity method investees | | | 105 | | | | — | | | | 105 | | Capital expenditures | | | 650 | | | | — | | | | 650 | | Total assets (billions) | | | 8.5 | | | | 0.6 | | | | 9.1 | | 2012 | | | | | | | | | | | | | Operating revenue | | $ | 1,677 | | | $ | — | | | $ | 1,677 | | Depreciation and amortization | | | 176 | | | | — | | | | 176 | | Equity in earnings of equity method investees | | | 23 | | | | — | | | | 23 | | Interest income | | | 2 | | | | — | | | | 2 | | Interest and related charges | | | 40 | | | | — | | | | 40 | | Income taxes | | | 293 | | | | (5 | ) | | | 288 | | Net income (loss) | | | 469 | | | | (10 | ) | | | 459 | | Capital expenditures | | | 928 | | | | — | | | | 928 | |
NOTE 26. QUARTERLY FINANCIALAND COMMON STOCK DATA ((UUNAUDITEDNAUDITED) A summary of Dominion’s and Virginia Power’sthe Companies’ quarterly results of operations for the years ended December 31, 20132014 and 20122013 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors. DOMINION | | | | First Quarter | | Second Quarter | | Third
Quarter | | Fourth Quarter | | Full Year | | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Year | | (millions, except per
share amounts) | | | | | | | | | | | | | | | | | | | | | | | | 2013 | | | | | | | | | | | | | | 2014 | | | | | | | | | | | | | Operating revenue | | $ | 3,523 | | | $ | 2,980 | | | $ | 3,432 | | | $ | 3,185 | | | $ | 13,120 | | | $ | 3,630 | | | $ | 2,813 | | | $ | 3,050 | | | $ | 2,943 | | | $ | 12,436 | | Income from operations | | | 930 | | | | 548 | | | | 1,034 | | | | 804 | | | | 3,316 | | | | 768 | | | | 394 | | | | 921 | | | | 638 | | | | 2,721 | | Net income including noncontrolling interests | | | 502 | | | | 208 | | | | 575 | | | | 435 | | | | 1,720 | | | | 385 | | | | 161 | | | | 531 | | | | 249 | | | | 1,326 | | Income from continuing operations(1) | | | 494 | | | | 272 | | | | 592 | | | | 431 | | | | 1,789 | | | | 379 | | | | 159 | | | | 529 | | | | 243 | | | | 1,310 | | Income (loss) from discontinued operations(1) | | | 1 | | | | (70 | ) | | | (23 | ) | | | — | | | | (92 | ) | | Net income attributable to Dominion | | | 495 | | | | 202 | | | | 569 | | | | 431 | | | | 1,697 | | | | 379 | | | | 159 | | | | 529 | | | | 243 | | | | 1,310 | | Basic EPS: | | | | | | | | | | | | | | | | | | | | | Income from continuing operations(1) | | | 0.86 | | | | 0.47 | | | | 1.02 | | | | 0.74 | | | | 3.09 | | | | 0.65 | | | | 0.27 | | | | 0.91 | | | | 0.42 | | | | 2.25 | | Income (loss) from discontinued operations(1) | | | — | | | | (0.12 | ) | | | (0.04 | ) | | | — | | | | (0.16 | ) | | Net income attributable to Dominion | | | 0.86 | | | | 0.35 | | | | 0.98 | | | | 0.74 | | | | 2.93 | | | | 0.65 | | | | 0.27 | | | | 0.91 | | | | 0.42 | | | | 2.25 | | Diluted EPS: | | | | | | | | | | | | | | | | | | | | | Income from continuing operations(1) | | | 0.86 | | | | 0.47 | | | | 1.02 | | | | 0.74 | | | | 3.09 | | | | 0.65 | | | | 0.27 | | | | 0.90 | | | | 0.42 | | | | 2.24 | | Income (loss) from discontinued operations(1) | | | — | | | | (0.12 | ) | | | (0.04 | ) | | | — | | | | (0.16 | ) | | Net income attributable to Dominion | | | 0.86 | | | | 0.35 | | | | 0.98 | | | | 0.74 | | | | 2.93 | | | | 0.65 | | | | 0.27 | | | | 0.90 | | | �� | 0.42 | | | | 2.24 | | Dividends declared per share | | | 0.5625 | | | | 0.5625 | | | | 0.5625 | | | | 0.5625 | | | | 2.25 | | | | 0.60 | | | | 0.60 | | | | 0.60 | | | | 0.60 | | | | 2.40 | | Common stock prices (intraday high-low) | | $
| 58.25 -
51.92 |
| | $
| 61.85 -
53.79 |
| | $
| 64.04 -
55.51 |
| | $
| 67.97 -
61.36 |
| | $
| 67.97 -
51.92 |
| | $
| 72.22 -
63.14 |
| | $
| 73.75 -
67.06 |
| | $
| 71.62 -
64.71 |
| | $
| 80.89 -
65.53 |
| | $
| 80.89 -
63.14 |
|
| | | | First Quarter | | Second Quarter | | Third
Quarter | | Fourth Quarter(2) | | Full Year | | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Year | | 2012 | | | | | | | | | | | | (millions, except per
share amounts) | | | | | | | | | | | | | 2013 | | | | | | | | | | | | Operating revenue | | $ | 3,397 | | | $ | 3,005 | | | $ | 3,332 | | | $ | 3,101 | | | $ | 12,835 | | | $ | 3,523 | | | $ | 2,980 | | | $ | 3,432 | | | $ | 3,185 | | | $ | 13,120 | | Income from operations | | | 918 | | | | 628 | | | | 551 | | | | 761 | | | | 2,858 | | | | 930 | | | | 548 | | | | 1,034 | | | | 804 | | | | 3,316 | | Net income (loss) including noncontrolling interests | | | 501 | | | | 265 | | | | 215 | | | | (652 | ) | | | 329 | | | Net income including noncontrolling interests | | | | 502 | | | | 208 | | | | 575 | | | | 435 | | | | 1,720 | | Income from continuing operations(1) | | | 504 | | | | 290 | | | | 261 | | | | 372 | | | | 1,427 | | | | 494 | | | | 272 | | | | 592 | | | | 431 | | | | 1,789 | | Income (loss) from discontinued operations(1) | | | (10 | ) | | | (32 | ) | | | (52 | ) | | | (1,031 | ) | | | (1,125 | ) | | | 1 | | | | (70 | ) | | | (23 | ) | | | — | | | | (92 | ) | Net income attributable to Dominion | | | 494 | | | | 258 | | | | 209 | | | | (659 | ) | | | 302 | | | | 495 | | | | 202 | | | | 569 | | | | 431 | | | | 1,697 | | Basic EPS: | | | | | | | | | | | | | | | | | | | | | Income from continuing operations(1) | | | 0.88 | | | | 0.51 | | | | 0.45 | | | | 0.65 | | | | 2.49 | | | | 0.86 | | | | 0.47 | | | | 1.02 | | | | 0.74 | | | | 3.09 | | Loss from discontinued operations(1) | | | (0.02 | ) | | | (0.06 | ) | | | (0.09 | ) | | | (1.80 | ) | | | (1.96 | ) | | Net income (loss) attributable to Dominion | | | 0.86 | | | | 0.45 | | | | 0.36 | | | | (1.15 | ) | | | 0.53 | | | Income (loss) from discontinued operations(1) | | | | — | | | | (0.12 | ) | | | (0.04 | ) | | | — | | | | (0.16 | ) | Net income attributable to Dominion | | | | 0.86 | | | | 0.35 | | | | 0.98 | | | | 0.74 | | | | 2.93 | | Diluted EPS: | | | | | | | | | | | | | | | | | | | | | Income from continuing operations(1) | | | 0.88 | | | | 0.51 | | | | 0.45 | | | | 0.64 | | | | 2.49 | | | | 0.86 | | | | 0.47 | | | | 1.02 | | | | 0.74 | | | | 3.09 | | Loss from discontinued operations(1) | | | (0.02 | ) | | | (0.06 | ) | | | (0.09 | ) | | | (1.79 | ) | | | (1.96 | ) | | Net income (loss) attributable to Dominion | | | 0.86 | | | | 0.45 | | | | 0.36 | | | | (1.15 | ) | | | 0.53 | | | Income (loss) from discontinued operations(1) | | | | — | | | | (0.12 | ) | | | (0.04 | ) | | | — | | | | (0.16 | ) | Net income attributable to Dominion | | | | 0.86 | | | | 0.35 | | | | 0.98 | | | | 0.74 | | | | 2.93 | | Dividends declared per share | | | 0.5275 | | | | 0.5275 | | | | 0.5275 | | | | 0.5275 | | | | 2.11 | | | | 0.5625 | | | | 0.5625 | | | | 0.5625 | | | | 0.5625 | | | | 2.25 | | Common stock prices (intraday high-low) | | $
| 53.68 -
48.87 |
| | $
| 54.69 -
49.87 |
| | $
| 55.62 -
52.15 |
| | $
| 53.89 -
48.94 |
| | $
| 55.62 -
48.87 |
| | $
| 58.25 -
51.92 |
| | $
| 61.85 -
53.79 |
| | $
| 64.04 -
55.51 |
| | $
| 67.97 -
61.36 |
| | $
| 67.97 -
51.92 |
|
| (1) | Amounts attributable to Dominion’s common shareholders. |
Dominion’s 2014 results include the impact of the following significant items: (2)Ÿ | Recast | Fourth quarter results include $172 million in after-tax charges associated with the Liability Management Exercise in 2014 and $74 million in after-tax costs related to reflect Brayton PointVirginia Power’s settlement offer to incur future ash pond closure costs at certain utility generation facilities. |
| Ÿ | | Second quarter results include $191 million in after-tax charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and Kincaid as discontinued operations as describedoffshore wind facilities. |
| Ÿ | | First quarter results include a $193 million after-tax reduction in Note 3.revenues associated with the repositioning of Dominion’s producer services business which was completed in the first quarter of 2014. |
Combined Notes to Consolidated Financial Statements, Continued Dominion’s 2013 results include the impact of the following significant items: | Ÿ | | Second quarter results include a $70 million after-tax net loss from discontinued operations of Brayton Point and Kincaid; and a $57 million after-tax net loss, including a $33 million after-tax impairment charge related to certain natural gas infrastructure assets and a $24 million after-tax loss related to the producer services business. |
Dominion’s 2012VIRGINIA POWER
Virginia Power’s quarterly results of operations were as follows: | | | | | | | | | | | | | | | | | | | | | | | | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | | Year | | | (millions) | | | | | | | | | | | | | | | | 2014 | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 1,983 | | | $ | 1,729 | | | $ | 2,053 | | | $ | 1,814 | | | $ | 7,579 | | Income from operations | | | 613 | | | | 205 | | | | 594 | | | | 312 | | | | 1,724 | | Net income | | | 324 | | | | 69 | | | | 314 | | | | 151 | | | | 858 | | Balance available for common stock | | | 318 | | | | 67 | | | | 312 | | | | 148 | | | | 845 | | 2013 | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 1,781 | | | $ | 1,710 | | | $ | 2,059 | | | $ | 1,745 | | | $ | 7,295 | | Income from operations | | | 530 | | | | 463 | | | | 679 | | | | 408 | | | | 2,080 | | Net income | | | 287 | | | | 265 | | | | 387 | | | | 199 | | | | 1,138 | | Balance available for common stock | | | 283 | | | | 261 | | | | 383 | | | | 194 | | | | 1,121 | |
Virginia Power’s 2014 results include the impact of the following significant items: | Ÿ | | Fourth quarter results include a $1.0 billion$74 million in after-tax impairment chargecosts related to write down Brayton Point’s and Kincaid’s long-lived assetsVirginia Power’s settlement offer to their estimated fair value.incur future ash pond closure costs at certain utility generation facilities. |
| Ÿ | | ThirdSecond quarter results include a $281$191 million after-tax net loss, including impairment charges, primarily resulting from management’s decisioncharge associated with Virginia legislation enacted in April 2014 relating to cease operationsthe development of a third nuclear unit located at North Anna and begin decommissioning Kewaunee in 2013.offshore wind facilities.
|
Combined Notes to Consolidated Financial Statements, Continued
VIRGINIA POWER
Virginia Power’s quarterly results of operations were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | First
Quarter | | | Second
Quarter | | | Third
Quarter | | | Fourth
Quarter | | | Year | | | (millions) | | | | | | | | | | | | | | | | 2013 | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 1,781 | | | $ | 1,710 | | | $ | 2,059 | | | $ | 1,745 | | | $ | 7,295 | | Income from operations | | | 530 | | | | 463 | | | | 679 | | | | 408 | | | | 2,080 | | Net income | | | 287 | | | | 265 | | | | 387 | | | | 199 | | | | 1,138 | | Balance available for common stock | | | 283 | | | | 261 | | | | 383 | | | | 194 | | | | 1,121 | | 2012 | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 1,754 | | | $ | 1,756 | | | $ | 2,086 | | | $ | 1,630 | | | $ | 7,226 | | Income from operations | | | 468 | | | | 361 | | | | 746 | | | | 417 | | | | 1,992 | | Net income | | | 243 | | | | 172 | | | | 415 | | | | 220 | | | | 1,050 | | Balance available for common stock | | | 239 | | | | 168 | | | | 411 | | | | 216 | | | | 1,034 | |
Virginia Power’s 2013 results include the impact of the following significant item: | Ÿ | | Fourth quarter results include a $28 million after-tax charge resulting from impacts of the 2013 Biennial Review Order. |
Virginia Power’s 2012DOMINION GAS
Dominion Gas’ quarterly results of operations were as follows: | | | | | | | | | | | | | | | | | | | | | | | | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | | Year | | | (millions) | | | | | | | | | | | | | | | | 2014 | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 569 | | | $ | 428 | | | $ | 391 | | | $ | 510 | | | $ | 1,898 | | Income from operations | | | 265 | | | | 154 | | | | 177 | | | | 255 | | | | 851 | | | Net income | | 164 | | | 93 | | | 107 | | | 148 | | | 512 | | 2013 | | | | | | | | | | | | | | | | | | | | | Operating revenue | | $ | 586 | | | $ | 430 | | | $ | 388 | | | $ | 533 | | | $ | 1,937 | | Income from operations | | | 224 | | | | 88 | | | | 217 | | | | 233 | | | | 762 | | Net income | | | 138 | | | | 53 | | | | 130 | | | | 140 | | | | 461 | |
Dominion Gas’ 2014 results include the impact of the following significant item: | Ÿ | | Fourth quarter results include a $36 million after-tax gain from agreements to convey Marcellus Shale development rights underneath several natural gas storage fields. |
Dominion Gas’ 2013 results include the impact of the following significant item: | Ÿ | | Second quarter results include a $42$33 million after-tax charge reflecting restoration costs associated with damage caused by late June summer storms.resulting from the impairment of certain natural gas infrastructure assets. |
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures DOMINION Senior management, including Dominion’s CEO and CFO, evaluated the effectiveness of Dominion’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion’s CEO and CFO have concluded that Dominion’s disclosure controls and procedures are effective. There were no changes in Dominion’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion’s internal control over financial reporting. MANAGEMENT’S ANNUAL REPORTON INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Dominion Resources, Inc. (Dominion) understands and accepts responsibility for Dominion’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion does throughout all aspects of its business. Dominion maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. The Audit Committee of the Board of Directors of Dominion, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time. SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion’s 20132014 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2013,2014, Dominion makes the following assertions: Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion. There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time. Management evaluated Dominion’s internal control over financial reporting as of December 31, 2013.2014. This assessment was based on criteria for effective internal control over financial reporting described inInternal Control—Integrated Framework (1992)(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion maintained effective internal control over financial reporting as of December 31, 2013.2014. Dominion’s independent registered public accounting firm is engaged to express an opinion on Dominion’s internal control over financial reporting, as stated in their report which is included herein. February 27, 20142015
REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Dominion Resources, Inc. Richmond, Virginia We have audited the internal control over financial reporting of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2013,2014, based on criteria established inInternal Control—Integrated Framework (2013) (1992)issued by the Committee of Sponsoring Organizations of the Treadway Commission. Dominion’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, Dominion maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013,2014, based on the criteria established inInternal Control—Integrated Framework (1992)(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 20132014 of Dominion and our report dated February 27, 20142015 expressed an unqualified opinion on those financial statements. /s/ Deloitte & Touche LLP Richmond, Virginia February 27, 20142015
VIRGINIA POWER Senior management, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes in Virginia Power’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Power’s internal control over financial reporting. MANAGEMENT’S ANNUAL REPORTON INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Virginia Electric and Power Company (Virginia Power) understands and accepts responsibility for Virginia Power’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Virginia Power continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business. Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities. SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s 20132014 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2013,2014, Virginia Power makes the following assertions: Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power. There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time. Management evaluated Virginia Power’s internal control over financial reporting as of December 31, 2013.2014. This assessment was based on criteria for effective internal control over financial reporting described inInternal Control—Integrated Framework (1992)(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2013.2014. This annual report does not include an attestation report of Virginia Power’s registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act. February 27, 2015 DOMINION GAS DISCLOSURE CONTROLS AND PROCEDURES An evaluation of the effectiveness of the design and operation of Dominion Gas’ disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended) was carried out under the supervision and with the participation of management, including the CEO and CFO of Dominion Gas. Based upon that evaluation, the CEO and CFO of Dominion Gas concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2014, the end of the period covered by this report. INTERNAL CONTROL OVER FINANCIAL REPORTING The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules that generally require every company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. In addition, an independent registered public accounting firm must attest to a company’s internal control over financial reporting. This first Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of Dominion Gas’ independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. Management will be required to provide an assessment of the effectiveness of Dominion Gas’ internal control over financial reporting as of December 31, 2015. Management’s report will not be subject to attestation by Dominion Gas’ independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act. CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING There have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, Dominion Gas’ internal control over financial reporting during the quarter ended December 31, 2014.
Item 9B. Other Information None. Part III Item 10. Directors, Executive Officers and Corporate Governance DOMINION The following information for Dominion is incorporated by reference from the Dominion 20142015 Proxy Statement, which will be filed on or around March 21, 2014:23, 2015: | Ÿ | | Information regarding the directors required by this item is found under the headingElection of Directors. |
| Ÿ | | Information regarding compliance with Section 16 of the Securities Exchange Act of 1934, as amended, required by this item is found under the headingSection 16(a) Beneficial Ownership Reporting Compliance. |
| Ÿ | | Information regarding the Dominion Audit Committee Financial expert(s) required by this item is found under the headingsDirector Independence andCommittees and Meeting Attendance. |
| Ÿ | | Information regarding the Dominion Audit Committee required by this item is found under the headingsThe Audit Committee Report andCommittees and Meeting Attendance. |
| Ÿ | | Information regarding Dominion’s Code of Ethics required by this item is found under the headingCorporate Governance and Board Matters. |
The information concerning the executive officers of Dominion required by this item is included in Part I of this Form 10-K under the captionExecutive Officers of Dominion. Each executive officer of Dominion is elected annually. VIRGINIA POWER
Information concerning directors of Virginia Power, each of whom is elected annually, is as follows:
| | | | | | | Name and Age | | Principal Occupation and
Directorships in Public Corporations for Last Five Years(1)
| | Year First
Elected as
Director
| | Thomas F. Farrell II (59)
| | Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date. Mr. Farrell has served as a director of Altria Group, Inc. since 2008.
Mr. Farrell’s qualifications to serve as a director include his 18 years of industry experience as well as his legal expertise, having served as General Counsel for Dominion and Virginia Power and as a practicing attorney with a private firm. He is chairman of the Institute of Nuclear Power Operations and a member of the Board of Directors of the Edison Electric Institute through which he actively represents the interests of Dominion, Virginia Power and the energy sector. Mr. Farrell also has extensive community and public interest involvement and serves or has served on many non-profit and university foundations.
| | | 1999 | | Mark F. McGettrick (56)
| | Executive Vice President and CFO of Virginia Power and Dominion from June 2009 to date; President and COO-Generation of Virginia Power from February 2006 to May 2009; Executive Vice President of Dominion from April 2006 to May 2009.
Mr. McGettrick’s qualifications to serve as a director include his more than 30 years of power generation management and industry experience. He currently serves on the George Mason University board of visitors and business council and is on the Board of Directors of the Dominion Foundation. Mr. McGettrick also has community and public interest involvement and serves or has served on many non-profit foundations and boards.
| | | 2009 | | Mark O. Webb (49)
| | Vice President, General Counsel and Chief Risk Officer of Virginia Power and Dominion from January 2014 to date; Vice President and General Counsel of Virginia Power and Dominion from January 2013 to December 2013; Deputy General Counsel of DRS from July 2011 to December 2012; Director – Policy & Business Evaluation AES of DRS from May 2009 to June 2011 and Deputy General Counsel of DRS from April 2004 to April 2009.
Mr. Webb’s qualifications to serve as a director include his more than 20 years of legal expertise as a practicing attorney with private firms and having served as General Counsel and Deputy General Counsel for Dominion advising on a wide range of matters including securities and corporate finance, mergers and acquisitions, electric and gas regulation, alternative energy policy and litigation. He also has community service and public interest involvement, including serving on non-profit foundations and boards.
| | | 2014 | |
(1) | Any service listed for Dominion and DRS reflects service at a parent, subsidiary or affiliate. Virginia Power is a wholly-owned subsidiary of Dominion. DRS is an affiliate of Virginia Power and is also a subsidiary of Dominion. |
Executive Officers of Virginia Power
Information concerning the executive officers of Virginia Power, each of whom is elected annually, is as follows:
| | | Name and Age | | Business Experience Past Five Years(1) | Thomas F. Farrell II (59)
| | Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date. | Mark F. McGettrick (56)
| | Executive Vice President and CFO of Virginia Power and Dominion from June 2009 to date; President and COO-Generation of Virginia Power from February 2006 to May 2009; Executive Vice President of Dominion from April 2006 to May 2009. | Paul D. Koonce (54)
| | President and COO of Virginia Power from June 2009 to date; Executive Vice President and Chief Executive Officer-Energy Infrastructure Group of Dominion from February 2013 to date; Executive Vice President of Dominion from April 2006 to February 2013. | David A. Christian (59)
| | President and COO of Virginia Power from June 2009 to date; Executive Vice President and Chief Executive Officer-Dominion Generation Group of Dominion from February 2013 to date; Executive Vice President of Dominion from May 2011 to February 2013; President and CNO of Virginia Power from October 2007 to May 2009. | David A. Heacock (56)
| | President and CNO of Virginia Power from June 2009 to date; President and COO-DVP of Virginia Power and Senior Vice President of Dominion from June 2008 to May 2009. | Robert M. Blue (46)
| | President of Virginia Power from January 2014 to date; Senior Vice President-Law, Public Policy and Environment of Virginia Power and Dominion from January 2011 to December 2013; Senior Vice President-Public Policy and Environment of Dominion from February 2010 to December 2010; Senior Vice President-Public Policy and Corporate Communications of Dominion from May 2008 to January 2010. | Ashwini Sawhney (64)
| | Vice President, Controller and CAO of Virginia Power and Dominion from January 2014 to date; Vice President-Accounting of Virginia Power from April 2006 to December 2013; Vice President-Accounting and Controller (CAO) of Dominion from May 2010 to December 2013; Vice President and Controller (CAO) of Dominion from July 2009 to May 2010; Vice President and Controller of Dominion from April 2007 to June 2009. | Mark O. Webb (49)
| | Vice President, General Counsel and Chief Risk Officer of Virginia Power and Dominion from January 2014 to date; Vice President and General Counsel of Virginia Power and Dominion from January 2013 to December 2013; Deputy General Counsel of DRS from July 2011 to December 2012; Director—Policy & Business Evaluation AES of DRS from May 2009 to June 2011 and Deputy General Counsel of DRS from April 2004 to April 2009. |
(1) | Any service listed for Dominion and DRS reflects services at a parent, subsidiary or affiliate. |
Section 16(a) Beneficial Ownership Reporting Compliance
To Virginia Power’s knowledge, for the fiscal year ended December 31, 2013, all Section 16(a) filing requirements applicable to its executive officers and directors were satisfied.
Audit Committee Financial Experts
Virginia Power is a wholly-owned subsidiary of Dominion. As permitted by SEC rules, its Board of Directors serves as Virginia Power’s Audit Committee and is comprised entirely of executive officers of Virginia Power or Dominion. Virginia Power’s Board of Directors has determined that Thomas F. Farrell II, Mark F. McGettrick and Mark O. Webb are “audit committee financial experts” as defined by the SEC. As executive officers of Virginia Power and Dominion, Thomas F. Farrell II, Mark F. McGettrick and Mark O. Webb were not deemed independent.
Code of Ethics
Virginia Power has adopted a Code of Ethics that applies to its principal executive, financial and accounting officers, as well as its employees. This Code of Ethics is the same as Dominion adopted and is available on the corporate governance section of Dominion’s website (http://www.dom.com). You may also request a copy of the Code of Ethics, free of charge, by writing or telephoning to: Corporate Secretary, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (800) 552-4034. Any waivers or changes to Virginia Power’s Code of Ethics will be posted on the Dominion website.
Item 11. Executive Compensation DominionDOMINION
The following information about Dominion is contained in the 20142015 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the headingsCompensation Discussion and Analysis andExecutive CompensationCompensation;; the information regarding Compensation Committee interlocks contained under the headingCompensation Committee Interlocks and Insider ParticipationParticipation;; theCompensation, Governance and Nominating Committee Report; and the information regarding director compensation contained under the headingNon-Employee Director Compensation. Virginia Power
COMPENSATION COMMITTEE REPORT
In preparation for the filing of Virginia Power’s Annual Report on Form 10-K, Dominion’s CGN Committee reviewed and discussed the following CD&A with management and has recommended to the Board of Directors of Virginia Power that the CD&A be included in Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013.
Robert S. Jepson, Jr.,Chairman
William P. Barr
John W. Harris
Mark J. Kington
David A. Wollard
INTRODUCTION
Virginia Power is a wholly-owned subsidiary of Dominion. Virginia Power’s Board is comprised of Messrs. Farrell, McGettrick and Webb. As executive officers of Virginia Power and Dominion, Messrs. Farrell, McGettrick and Webb are not independent. Because Virginia Power’s Board is not independent, there is not a separate compensation committee at the Virginia Power level. Instead, Virginia Power’s Board depends on the advice and recommendations of Dominion’s CGN Committee which is comprised of independent directors. Virginia Power’s Board approves all compensation paid to Virginia Power’s executive officers based on the CGN Committee’s recommendations.
None of Virginia Power’s directors receive any compensation for services they provide as directors of Virginia Power. No executive officer of Dominion or Virginia Power serves as a member of another compensation committee or on the Board of Directors of any company of which a member of Dominion’s CGN Committee, Dominion’s Board of Directors or Virginia Power’s Board of Directors serves as an executive officer.
Because the CGN Committee effectively administers one compensation program for all of Dominion, the following discussion and analysis is based on Dominion’s overall compensation program.
COMPENSATION DISCUSSION AND ANALYSIS
This CD&A explains the objectives and principles of Dominion’s executive compensation program, its elements and the way performance is measured, evaluated and rewarded. It also describes Dominion’s compensation decision-making process. Dominion’s executive compensation program is designed to pay for performance and plays an important role in Dominion’s success by linking a significant amount of compensation to the achievement of performance goals.
The program and processes generally apply to all of Dominion’s officers, but this discussion and analysis focuses primarily on compensation for the NEOs of Virginia Power. During 2013, Virginia Power’s NEOs were:
Ÿ | | Thomas F. Farrell II, Chairman and CEO;
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Ÿ | | Mark F. McGettrick, Executive Vice President and CFO;
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Ÿ | | David A. Christian, President and COO (Dominion Generation);
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Ÿ | | Paul D. Koonce, President and COO (DVP); and
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Ÿ | | David A. Heacock, President and CNO.
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The CGN Committee determines the compensation payable to officers of Dominion and its wholly-owned subsidiaries on an aggregate basis, taking into account all services performed by the officers, whether for Dominion or one or more of its subsidiaries. All of Virginia Power’s NEOs are NEOs of Dominion. For the NEOs included in Dominion’s annual proxy statement, these aggregate amounts are reported in the Summary Compensation Table and related executive compensation tables. For purposes of reporting each NEO’s compensation from Virginia Power in the Summary Compensation Table (and related tables that follow) in this Item 11, the aggregate compensation for each NEO is pro-rated based on the ratio of services performed by the NEO for Virginia Power to the NEO’s total services performed for all of Dominion. The amounts reported in the tables below are part of, and not in addition to the aggregate compensation amounts that are reported for these NEOs in Dominion’s 2014 Proxy Statement.
The CD&A below discusses the CGN Committee’s decisions with respect to each NEO’s aggregate compensation for all services performed for all of Dominion, not just the pro-rated portion attributable to the NEO’s services for Virginia Power.
Objectives of Dominion’s Executive Compensation Program And The Compensation Decision-making Process
Objectives
Dominion’s executive compensation philosophy is to provide a competitive total compensation program tied to performance and aligned with the interests of Dominion’s shareholders, employees and customers.
The major objectives of Dominion’s compensation program are to:
Ÿ | | Attract, develop and retain an experienced and highly qualified management team;
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Ÿ | | Motivate and reward superior performance that supports Dominion’s business and strategic plans and contributes to the long-term success of the company;
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Ÿ | | Align the interests of management with those of Dominion’s shareholders and customers by placing a substantial portion of pay at risk through performance goals that, if achieved, are expected to increase TSR and enhance customer service;
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Ÿ | | Promote internal pay equity; and
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Ÿ | | Reinforce Dominion’s four core values of safety, ethics, excellence and One Dominion – Dominion’s term for teamwork.
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These objectives provide the framework for compensation decisions. To determine if Dominion is meeting the objectives of its compensation program, the CGN Committee reviews and compares Dominion’s actual performance to its short-term and long-term goals, strategies, and Dominion’s peer companies’ performance.
Dominion’s 2013 performance indicates that the design of Dominion’s compensation program is meeting these objectives. The NEOs have service with Dominion ranging from 15 to 37 years. Dominion has attracted, motivated and maintained a superior leadership team with skills, industry knowledge and institutional experience that strengthen their ability to act as sound stewards of Dominion’s shareholder dollars.
Dominion’s shareholders voted on an advisory basis on its executive compensation program (also known as Say on Pay) and approved it with a 96% vote at the 2013 Annual Meeting, which followed an approval by a 95% vote in 2012. The CGN Committee considered the very strong shareholder endorsement of Dominion’s executive compensation program in continuing the pay-for-performance program that is currently in place without any specific changes based on the vote. Unless Dominion’s Board of Directors modifies its policy on the frequency of future Say on Pay advisory votes, shareholders will have an opportunity annually to cast an advisory vote to approve Dominion’s executive compensation program. Dominion will ask shareholders, on an advisory basis, to vote on the frequency of the Say on Pay vote at least once every six years, with the next advisory vote on frequency to be held no later than the 2017 Annual Meeting of Shareholders.
The Process for Setting Compensation
The CGN Committee is responsible for reviewing and approving NEO compensation and the overall executive compensation program. Each year, the CGN Committee reviews and considers a comprehensive assessment and analysis of the executive compensation program, including the elements of each NEO’s compensation, with input from management and the CGN Committee’s independent compensation consultants. As part of its assessment, the CGN Committee reviews the performance of the CEO and other executive officers, meets at least annually with the CEO to discuss succession planning for his position and the positions of Dominion’s senior officers, reviews executive officer share ownership guidelines and compliance, and establishes compensation programs designed to achieve Dominion’s objectives.
THE ROLEOF THE INDEPENDENT COMPENSATION CONSULTANT
In June 2013, the CGN Committee retained Cook & Co. as its independent compensation consultant to advise the Committee on executive and director compensation matters. The CGN Committee’s consultant:
Ÿ | | Attends meetings as requested by the CGN Committee, either in person or by teleconference;
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Ÿ | | Communicates directly with the chairman of the CGN Committee outside of the CGN Committee meetings as needed;
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Ÿ | | Participates in CGN Committee executive sessions without the CEO present to discuss CEO compensation and any other relevant matters, including the appropriate relationship between pay and performance and emerging trends;
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Ÿ | | Reviews and comments on proposals and materials prepared by management and answers technical questions, as requested; and
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Ÿ | | Generally reviews and offers advice as requested by or on behalf of the CGN Committee regarding other aspects of Dominion’s executive compensation program, including best practices and other matters.
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Prior to the engagement of Cook & Co., PM&P served as the independent compensation consultant to the CGN Committee. During 2013, the CGN Committee reviewed and assessed the independence of both PM&P and Cook & Co. and concluded that neither PM&P’s nor Cook & Co.’s work raised any conflicts of interest. Cook & Co. did not provide any additional services to Dominion during 2013, and for the period in 2013 for which PM&P served as the CGN Committee’s independent consultant, PM&P also did not provide any additional services to Dominion.
MANAGEMENT’S ROLEIN DOMINION’S PROCESS
Although the CGN Committee has the responsibility to approve and monitor all compensation for the NEOs, management plays an important role in determining executive compensation. Under the direction of Dominion’s management, internal compensation specialists provide the CGN Committee with data, analysis and counsel regarding the executive compensation program, including an ongoing assessment of the effectiveness of the program, peer practices, and executive compensation trends and best practices. Dominion’s management, along with the internal compensation and financial specialists, assist in the design of the incentive com-
pensation plans, including performance target recommendations consistent with the strategic goals of the company, and recommendations for establishing the peer group. Dominion’s management also works with the chairman of the CGN Committee to establish the agenda and prepare meeting information for each CGN Committee meeting.
As discussed previously, the CEO is responsible for reviewing senior officer succession plans with the CGN Committee on an annual basis. He is also responsible for reviewing the performance of the other senior officers, including the other NEOs, with the CGN Committee at least annually. He makes recommendations on the compensation and benefits for the NEOs (other than himself) to the CGN Committee and provides other information and advice as appropriate or as requested by the CGN Committee, but all decisions are ultimately made by the CGN Committee.
THE COMPENSATION PEER GROUP
The CGN Committee uses two peer groups for executive compensation purposes. The Compensation Peer Group is used to assess the competitiveness of the compensation of the NEOs. A separate Performance Grant Peer Group is used to evaluate the relative performance of Dominion for purposes of the LTIP. (See2013 Performance Grants andPerformance Grant Peer Groupfor additional information.)
In the fall of each year, the CGN Committee reviews and approves the Compensation Peer Group of companies. In selecting the Compensation Peer Group, Dominion uses a methodology that identifies companies in its industry that compete for customers, executive talent and investment capital. Dominion screens this group based on size and usually eliminates companies that are much smaller or larger than Dominion’s size in revenues, assets or market capitalization. Dominion also considers the geographic locations and the regulatory environment in which potential peer companies operate.
Dominion’s Compensation Peer Group is generally consistent from year to year, with merger and acquisition activity being the primary reason for any changes. No changes were made to the Compensation Peer Group for 2013. Dominion’s Compensation Peer Group for 2013 was comprised of the following companies:
| | | Ameren Corporation
American Electric Power Company, Inc.
CMS Energy Corporation
DTE Energy Company
Duke Energy Corporation
Entergy Corporation
Exelon Corporation
| | FirstEnergy Corp.
NextEra Energy, Inc.
NiSource Inc.
PPL Corporation
Public Service Enterprise Group Incorporated
The Southern Company
Xcel Energy Inc.
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The CGN Committee and management use the Compensation Peer Group to: (i) compare Dominion’s stock and financial performance against these peers using a number of different metrics and time periods to evaluate how Dominion is performing as compared to its peers; (ii) analyze compensation practices within the industry; (iii) evaluate peer company practices and determine peer median and 75th percentile ranges for base pay, annual incentive pay, long-term incentive pay and total direct compensation, both generally and for specific positions; and (iv) compare
benefits and perquisites. In setting the levels for base pay, annual incentive pay, long-term incentive pay and total direct compensation, the CGN Committee also takes into consideration Dominion’s size compared with the median of the Compensation Peer Group and the complexity of its business.
SURVEYAND OTHER DATA
Dominion does not benchmark or otherwise use broad-based market data as the basis for compensation decisions for the NEOs. Survey compensation data and information on local companies with whom Dominion competes for talent and other companies with comparable market capitalization to Dominion are used only to provide a general understanding of compensation practices and trends. The CGN Committee takes into account individual and company-specific factors, including internal pay equity, along with data from the Compensation Peer Group, in establishing compensation opportunities. The CGN Committee believes this reflects Dominion’s specific needs in its distinct competitive market and with respect to its size and complexity versus its peers.
COMPENSATION DESIGNAND RISK
Dominion’s management, including Dominion’s Chief Risk Officer and other executives, annually reviews the overall structure of Dominion’s executive compensation program and policies to ensure they are consistent with effective management of enterprise key risks and that they do not encourage executives to take unnecessary or excessive risks that could threaten the value of the enterprise. With respect to the programs and policies that apply to the NEOs, this review includes:
Ÿ | | Analysis of how different elements of the compensation programs may increase or mitigate risk-taking;
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Ÿ | | Analysis of performance metrics used for short-term and long-term incentive programs and the relation of such incentives to the objectives of the company;
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Ÿ | | Analysis of whether the performance measurement periods for short-term and long-term incentive compensation are appropriate; and
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Ÿ | | Analysis of the overall structure of compensation programs as related to business risks.
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Among the factors considered in management’s assessment are: (i) the balance of the overall program design, including the mix of cash and equity compensation; (ii) the mix of fixed and
variable compensation; (iii) the balance of short-term and long-term objectives of incentive compensation; (iv) the performance metrics, performance targets, threshold performance requirements and capped payouts related to incentive compensation; (v) the clawback provision on incentive compensation; (vi) Dominion’s share ownership guidelines, including share ownership levels and retention practices and prohibitions on hedging, pledging, and other derivative transactions related to Dominion stock; (vii) the CGN Committee’s ability to exercise negative discretion to reduce the amount of the annual incentive award; and (viii) internal controls and oversight structures in place at Dominion.
Management reviewed and provided the results of this assessment to the CGN Committee. Based on this review, the CGN Committee believes that Dominion’s well-balanced mix of salary and short-term and long-term incentives, as well as the performance metrics that are included in the incentive programs, are appropriate and consistent with Dominion’s risk management practices and overall strategies.
OTHER TOOLS
The CGN Committee uses a number of tools in its annual review of the compensation of Dominion’s CEO and other NEOs, including charts illustrating the total range of payouts for each performance-based compensation element under a number of different scenarios; spreadsheets showing the cumulative dollar impact on total direct compensation that could result from implementing proposals on any single element of compensation; graphs demonstrating the relationship between the CEO’s pay and that of the next highest-paid officer and Dominion’s NEOs as a group; and other information the CGN Committee may request in its discretion. Management’s internal compensation specialists provide the CGN Committee with detailed comparisons of the design and features of Dominion’s long-term incentive and other executive benefit programs with available information regarding similar programs at the companies in the Compensation Peer Group. These tools are used as part of the overall process to ensure that the compensation program results in appropriate pay relationships as compared to Dominion’s peer companies and internally among the NEOs, and that an appropriate balance of at-risk, performance-based compensation is maintained to support the program’s core objectives. No material adjustments were made to Dominion’s NEO’s compensation as a result of using these tools.
ELEMENTSOF DOMINION’S COMPENSATION PROGRAM
The executive compensation program consists of four basic elements:
| | | | | Pay Element | | Primary Objectives | | Key Features & Behavioral Focus | Base Salary
| | Ÿ Provide competitive level of fixed cash compensation for performing day-to-day responsibilities
Ÿ Attract and retain talent
| | Ÿ Generally targeted at or slightly above peer median, with individual and company-wide considerations
Ÿ Rewards individual performance and level of experience
| Annual Incentive Plan
| | Ÿ Provide competitive level of at-risk cash compensation for achievement of short-term financial and operational goals
Ÿ Align short-term compensation with annual budget, earnings goals, business plans and core values
| | Ÿ Cash payments based on achievement of annual financial and individual operating and stewardship goals
Ÿ Rewards achievement of annual financial goals for Dominion as well as business unit and individual goals selected to support longer-term strategies
| Long-Term Incentive Program
| | Ÿ Provide competitive level of at-risk compensation for achievement of long-term performance goals
Ÿ Create long-term shareholder value
Ÿ Retain talent and support the succession planning process
| | Ÿ A 50/50 combination of performance-based cash and restricted stock awards
Ÿ Encourages and rewards officers for making decisions and investments that create long-term shareholder value as reflected in superior relative total shareholder returns, as well as achieving desired returns on invested capital
| Employee and Executive Benefits
| | Ÿ Provide competitive retirement and other benefit programs that attract and retain highly qualified individuals
Ÿ Provide competitive terms to encourage officers to remain with Dominion during any potential change in control to ensure an orderly transition of management
| | Ÿ Includes company-wide benefit programs, executive retirement plans, limited perquisites, and change in control and other agreements, supplemented with non-compete provisions in the non-qualified retirement plans
Ÿ Encourages officers to remain with Dominion long-term and to act in the best interests of shareholders, even during any potential change in control
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Factors in Setting Compensation
As part of the process of setting compensation targets, approving payouts and designing future programs, the CGN Committee evaluates Dominion’s overall performance versus its business plans and strategies, its short-term and long-term goals and the performance of its peer companies. In addition to considering Dominion’s overall performance for the year, the CGN Committee takes into consideration several individual factors for each NEO that are not given any specific weighting in setting each element of compensation, including:
Ÿ | | An officer’s experience and job performance;
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Ÿ | | The scope, complexity and significance of responsibility for a position, including any differences from peer company positions;
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Ÿ | | Internal pay equity considerations, such as the relative importance of a particular position or individual officer to Dominion’s strategy and success, and comparability to other officer positions at Dominion;
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Ÿ | | Retention and market competitive concerns; and
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Ÿ | | The officer’s role in any succession plan for other key positions.
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The CGN Committee evaluates each NEO’s base salary, total cash compensation (base salary plus target AIP award) and total direct compensation (base salary plus target AIP award plus target
long-term incentive award) against data from the Compensation Peer Group to ensure the compensation levels are appropriately competitive. It does not, however, target these compensation levels at a particular percentile or range of the peer group data. For Mr. Heacock, the same evaluation process is performed using the Towers Watson Energy Services data instead of peer group data, due to insufficient peer group data reported at the time in order to evaluate the competitiveness of his compensation levels. See Exhibit 99.1 for a listing of the companies included in the survey. As part of this analysis, the CGN Committee also takes into account Dominion’s size, including market capitalization and price to earnings ratio, and complexity compared to the companies in the Compensation Peer Group, as well as the tenure of the NEO as compared to executives in a similar position in a Compensation Peer Group Company.
CEO Compensation Relative to Other NEOs
Mr. Farrell participates in the same compensation programs and receives compensation based on the same philosophy and factors as the other NEOs. Application of the same philosophy and factors to Mr. Farrell’s position results in overall CEO compensation that is significantly higher than the compensation of the other NEOs. His compensation is commensurate with his greater responsibilities and decision-making authority, broader scope of duties encompassing the entirety of the company (as compared to the other NEOs who are responsible for significant but distinct areas within Dominion) and his overall responsibility for corpo-
rate strategy. His compensation also reflects his role as the principal corporate representative to investors, customers, regulators, analysts, legislators, industry and the media.
Dominion considers CEO compensation trends as compared to the next highest-paid officer, as well as to other executive officers as a group, over a multi-year period to monitor the ratio of Mr. Farrell’s pay relative to the pay of other executive officers based on (i) salary only and (ii) total direct compensation. Dominion also compares its ratios to that of its peers, in addition to the other factors listed above, for CGN Committee consideration of year-to-year trends and comparisons with peers. The CGN Committee did not make any adjustments to the compensation of any NEOs based on this review for 2013.
Allocation of Total Direct Compensation in 2013
Consistent with Dominion’s objective to reward strong performance based on the achievement of short-term and long-term goals, a significant portion of total cash and total direct compensation is at risk. Approximately 88% of Mr. Farrell’s targeted 2013 total direct compensation is performance-based, tied to pre-approved performance metrics, including relative TSR and ROIC, or tied to the performance of Dominion stock. For the other NEOs, performance-based and stock-based compensation ranges from 67% to 81% of targeted 2013 total direct compensation. This compares to an average of approximately 55% of targeted compensation at risk for most of officers at the vice president level and an average of approximately 12% of total pay at risk for non-officer employees.
The charts below illustrate the elements of targeted total direct compensation opportunities in 2013 for Mr. Farrell and the average of the other NEOs as a group and the allocation of such compensation among base salary, targeted 2013 AIP award and targeted 2013 long-term incentive compensation.
Base Salary
Base salary compensates officers, along with the rest of the workforce, for committing significant time to working on Dominion’s behalf. Base salary may be adjusted, as appropriate, to keep salaries in line and competitive with the Compensation Peer Group and to reflect changes in responsibility, including promotions. Base salary adjustments are also a motivational tool to acknowledge and reward excellent individual performance, special skills, experience, the strategic impact of a position relative to other Dominion executives and other relevant considerations.
The primary goal is to compensate officers at a level that best achieves Dominion’s objectives and reflects the considerations discussed above. Dominion believes that an overall goal of targeting base salary at or slightly above the Compensation Peer Group median is a conservative but appropriate target for base pay. However, an individual’s compensation may be below or above Dominion’s target range based on a number of factors such as performance, tenure, and other factors explained above inFactors inSetting Compensation. In addition to being ranked above the Compensation Peer Group median in 2013 in terms of market capitalization and at median for revenues and assets, the scope of Dominion’s business operations is complex and unique in its industry. Successfully managing such a broad and complex business requires a skilled and experienced management team. Dominion believes it would not be able to successfully recruit and retain such a team if the base pay for officers was generally below the Compensation Peer Group median.
The CGN Committee approved a modest base salary increase for most officers, including a 3.0% base salary increase for Messrs. Farrell, Christian, Koonce and Heacock and a 5.0% base salary increase for Mr. McGettrick effective March 1, 2013. In determining the base salary increase for Mr. McGettrick, the CGN Committee took into consideration Mr. McGettrick’s overall performance, the broader scope of his responsibilities in comparison to the business unit CEOs and his role in developing financing strategies to support Dominion’s long-term growth plan. Effective January 1, 2013, the CGN Committee increased Mr. Koonce’s base salary 10% to recognize his increased responsibility as CEO of the Energy Infrastructure Group, with the Dominion Energy business unit reporting to him in addition to the DVP business unit.
Annual Incentive Plan
OVERVIEW
The AIP plays an important role in meeting Dominion’s overall objective of rewarding strong performance. The AIP is a cash-based program focused on short-term goal accomplishments and is designed to:
Ÿ | | Tie interests of shareholders, customers and employees closely together;
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Ÿ | | Focus the workforce on company, operating group, team and individual goals that ultimately influence operational and financial results;
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Ÿ | | Reward corporate and operating unit earnings performance;
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Ÿ | | Reward safety, diversity and other operating and stewardship goal successes;
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Ÿ | | Emphasize teamwork by focusing on common goals;
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Ÿ | | Appropriately balance risk and reward; and
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Ÿ | | Provide a competitive total compensation opportunity.
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TARGET AWARDS
An NEO’s compensation opportunity under the AIP is based on a target award. Target awards are determined as a percentage of a participant’s base salary (for example, 85% of base salary). The target award is the amount of cash that will be paid if the plan is funded at the full funding target set for the year and a participant achieves a score of 100% for the payout goals. Participants who retire during the plan year are eligible to receive a prorated payment of their AIP award after the end of the plan year based on final funding and goal achievement. Participants who voluntarily terminate employment during the plan year and who are not eligible to retire (before attainment of age 55) generally forfeit their AIP award.
AIP target award levels are established based on a number of factors, including historical practice, individual and company performance and internal pay equity considerations, and are compared against Compensation Peer Group data to ensure the appropriate competitiveness of an NEO’s total cash compensation opportunity. However, as discussed above, AIP target award levels are not targeted at a specific percentile or range of the peer group data, nor was market survey data used in setting AIP target award levels for 2013. AIP target award levels are also consistent with the intent to have a significant portion of NEO compensation at risk. There were no changes to the AIP targets from 2012 as a percentage of salary for any NEO for 2013.
| | | | | Name | | 2013 AIP
Target Award* | | Thomas F. Farrell II
| | | 125% | | Mark F. McGettrick
| | | 100% | | David A. Christian
| | | 90% | | Paul D. Koonce
| | | 90% | | David A. Heacock
| | | 70% | |
*As a % of base salary
FUNDINGOF THE 2013 AIP
Funding of the 2013 AIP was based solely on consolidated operating earnings per share, with potential funding ranging from 0% to 200% of the target funding. Consolidated operating earnings are Dominion’s reported earnings determined in accordance with GAAP, adjusted for certain items. Dominion believes that by placing a focus on pre-established consolidated operating earnings per share targets, it increases employee awareness of the company’s financial objectives and encourages behavior and performance that will help achieve these objectives.
For the 2013 AIP, the CGN Committee established a full funding target at 100% for the NEOs of operating earnings per share between $3.05 and $3.35, inclusive of funding for all plan participants. The maximum funding target of 200% was set at $3.50 operating earnings per share, and no funding if operating earnings were less than $3.00 per share (threshold), with the CGN Committee retaining negative discretion to determine the final funding level for the NEOs. Full funding means that the AIP is 100% funded and participants can receive their full targeted AIP payout if they achieve a score of 100% for their particular goal package, as described below inHow AIP Payouts Are Determined. At the maximum plan funding level of 200%, the NEOs can earn up to two times their targeted AIP payout, subject to achievement of their individual goal packages.
Dominion’s consolidated operating earnings for the year ended December 31, 2013 were $1.88 billion or $3.25 per share which met the target goal for 100% funding.* Consolidated reported earnings in accordance with GAAP for the year ended December 31, 2013, were $1.70 billion or $2.93 per share.
*Reconciliation of 2013 Consolidated Operating Earnings to Reported Earnings. The following items, which are net of tax, are included in Dominion’s 2013 reported earnings, but are excluded from consolidated operating earnings: $92 million net loss from discontinued operations of two merchant power stations (Brayton Point & Kincaid) which were sold in third quarter 2013; $109 million net charge related to an impairment of certain natural gas infrastructure assets and the repositioning of Producer Services; $28 million charge in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2011-2012 test years; $17 million charge associated with Dominion’s operating expense reduction initiative, primarily severance pay and other employee-related costs; $49 million net gain related to Dominion’s investments in nuclear decommissioning trust funds; $30 million benefit due to a downward revision in the nuclear decommissioning AROs for certain merchant nuclear units that are no longer in service; and $17 million net expense related to other items.
HOW AIP PAYOUTSARE DETERMINED
For the NEOs, payout of funded AIP awards is contingent solely on the achievement of the consolidated operating financial funding goal with the CGN Committee retaining negative discretion to lower the earned payout as it deems appropriate, taking into consideration the accomplishment of the discretionary consolidated financial, business unit financial and operating and stewardship goals, including safety and diversity goals. The percentage allocated to each category of discretionary goals represents the percentage of the funded award subject to the performance of that goal. Officer goals are weighted according to their responsibilities. The overall score cannot exceed 100%.
The consolidated operating financial goal is the same as the funding goal and, as noted, was fully achieved for the 2013 AIP. Business unit financial goals provide a line-of-sight performance target for officers within a business unit and, on a combined basis, support the consolidated operating earnings target for Dominion. Operating and stewardship goals provide line-of-sight performance targets that may not be financial and that can be customized for each individual or by segments of each business unit. Operating and stewardship goals promote the core values of safety, ethics, excellence and teamwork, which in turn contribute to Dominion’s financial success.
The discretionary payout goals adopted by each of the NEOs which may be considered by the CGN Committee to reduce the NEOs’ final payout are described under2013 AIP Payouts and the weightings applied to those goals are shown in the table below.
| | | | | | | | | | | | | | | | | | | | | | | | Consolidated Financial Goal | | | Business Unit Financial Goals | | | Operating and Stewardship Goals* | | | | | | | Safety | | | Diversity | | | Other | | Thomas F. Farrell II | | | 90% | | | | — | | | | 5% | | | | 5% | | | | — | | Mark F. McGettrick | | | 90% | | | | — | | | | 5% | | | | 5% | | | | — | | David A. Christian | | | 45% | | | | 45% | | | | 5% | | | | 5% | | | | — | | Paul D. Koonce | | | 45% | | | | 45% | | | | 5% | | | | 5% | | | | — | | David A. Heacock | | | 20% | | | | 45% | | | | 5% | | | | 5% | | | | 25% | |
*5% goal weighting for safety and diversity goals. Mr. Heacock had other non-safety/non-diversity operating & stewardship goals as described below.
2013 AIP PAYOUTS
The formula for calculating an award is:
Dominion’s operating earnings per share for the year ended December 31, 2013 was $3.25, which met the target AIP payout goal for NEOs of achievement of consolidated operating earnings between $3.05 and $3.35 per share for the year ended December 31, 2013. The CGN Committee approved a payout score of 100% for Messrs. Farrell, McGettrick, Christian and Heacock and exercised negative discretion to reduce Mr. Koonce’s payout score to 99.97% for a missed safety goal at DVP which is discussed below. As noted above, the payouts for the NEOs are based solely on the accomplishment of the consolidated operating financial funding goal. The achievement of these discretionary goals are applied only to the extent the CGN Committee deems it appropriate to take these goals in consideration in its exercise of negative discretion to reduce the final payout of the NEOs.
The CGN Committee assessed the business challenges that Dominion faced during 2013 and recognized that all of the business units remained focused on safe and excellent operations and that many of these challenges were nearly overcome. Although all of the business units did not reach their financial targets, the consolidated financial funding and payout goal was achieved and, as such, payouts for the applicable NEOs were not reduced for the business unit financial accomplishments, which are shown below:
| | | | | | | | | | | | | | Business Unit | | Goal
Threshold
(Net Income) | | | Goal
100% Payout
(Net Income) | | | Actual
2013
Net Income | | | (Millions/$) | | | | | | | | | | DVP | | $ | 480 | | | $ | 600 | | | $ | 543 | | Dominion Generation | | | 794 | | | | 993 | | | | 963 | |
With respect to Messrs. Farrell and McGettrick, the DRS business unit met its safety goal of four or fewer OSHA recordable incidents with an incidence rate of 0.15 or less. The Dominion Generation business unit, of which Mr. Christian is a part, met its target safety goal of an OSHA incidence rate ranging from 0.27 to 1.23 for certain operating units and recordable incidents of one or fewer for another operating unit within Dominion Generation. Mr. Koonce is part of the DVP and Dominion Energy business units. DVP fell short of the target OSHA incidence rate of 1.21 with an actual rate of 1.22, but the OSHA incidence rate of 1.59 for the Dominion Energy business unit was met. DVP and Dominion Energy met the lost time/restricted duty rates of 0.30 and 0.58, respectively. Mr. Heacock carried a safety goal for the nuclear fleet of 14 or fewer total fleet wide OSHA recordable incidents, which was met.
Each of the NEOs met his discretionary diversity goal relating to one or more of the following areas: talent review, internship program improvements, recruitment and retention process improvements, and workforce training. In addition to safety and diversity goals, Mr. Heacock met his additional discretionary operating and stewardship goals in the following four categories: nuclear safety (based on fleet wide total number of station event-free day clock resets); total online radiation exposure for the fleet; fleet capacity factor percentage and environmental compliance (based on the number of environmental performance points assessed at the nuclear stations).
Amounts earned under the 2013 AIP for each NEO are shown below and are reflected in theNon-Equity Incentive Plan Compensation column of theSummary Compensation Table.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Name | | Base Salary | | | | | | Target
Award* | | | | | | Funding % | | | | | | Total Payout
Score % | | | | | | 2013 AIP
Payout | | Thomas F. Farrell II | | $ | 435,721 | | | | X | | | | 125% | | | | X | | | | 100% | | | | X | | | | 100% | | | | = | | | $ | 544,651 | | Mark F. McGettrick | | | 352,623 | | | | X | | | | 100% | | | | X | | | | 100% | | | | X | | | | 100% | | | | = | | | | 352,623 | | David A. Christian | | | 376,964 | | | | X | | | | 90% | | | | X | | | | 100% | | | | X | | | | 100% | | | | = | | | | 339,268 | | Paul D. Koonce | | | 238,903 | | | | X | | | | 90% | | | | X | | | | 100% | | | | X | | | | 99.97% | | | | = | | | | 214,948 | | David A. Heacock | | | 236,918 | | | | X | | | | 70% | | | | X | | | | 100% | | | | X | | | | 100% | | | | = | | | | 165,843 | |
*As a % of base salary.
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
Mr. Koonce’s payout score was calculated as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Name | | Consolidated
Financial Goal
Accomplishment | | | | | | Goal
Weighting | | | | | | Business Unit
Financial Goal
Accomplishment | | | | | | Goal
Weighting | | | | | Operating/
Stewardship Goal
Accomplishment | | | | | | Goal
Weighting | | | | | | Total Payout
Score | | Paul D. Koonce | | | 100% | | | | X | | | | 45% | | | | + | | | | 100% | | | | X | | | | 45% | | | + | | | 99.7% | | | | X | | | | 10% | | | | = | | | | 99.97% | |
Long-Term Incentive Program
OVERVIEW
Dominion’s LTIP is designed to focus on Dominion’s longer-term strategic goals and the retention of its executives. Each long-term incentive award consists of two components: 50% of the award is a full value equity award in the form of restricted stock with time-based vesting and the other 50% is a performance-based cash award. Dominion believes restricted stock serves as a strong retention tool and also creates a focus on Dominion’s stock price to further align the interests of officers with the interests of its shareholders and customers. The performance-based award encourages and rewards officers for making decisions and investments that create and maintain long-term shareholder value and benefit Dominion’s customers. For those officers who have made substantial progress toward their share ownership guidelines, the performance-based award is in the form of a cash performance grant. Officers who have not achieved 50% of their targeted share ownership guideline receive goal-based stock performance grants instead of a cash performance grant. Dividend equivalents are not paid on any performance-based grants. Because officers are expected to retain ownership of shares upon vesting of restricted stock awards, as explained inShare Ownership Guidelines,the long-term cash performance grant balances the program and allows a portion of the long-term incentive award to be accessible to the NEOs during the course of their employment. As all of the NEOs have satisfied their full targeted share ownership, all of the NEOs received the performance-based component of their 2013 long-term incentive award in the form of a cash performance grant.
The CGN Committee approves long-term incentive awards in January each year with a grant date in early February. This process ensures incentive-based awards are made at the beginning of the performance period and shortly after the public disclosure of Dominion’s earnings for the prior year. Like the AIP target award levels discussed above, long-term incentive target award levels are established based on a number of factors, including historical practice, individual and company performance, and internal pay equity considerations, and are compared against Compensation Peer Group data to ensure the appropriate competitiveness of an NEO’s total direct compensation opportunity. However, as discussed above, long-term incentive target award levels were not targeted at a specific percentile or range of the Compensation Peer Group data, nor was market survey data a factor in setting long-term incentive target award levels for 2013.
As part of the CGN Committee’s review of Dominion’s LTIP, the target 2013 long-term incentive award was increased for generally all officers, including each of the NEOs. This was the first general increase in target awards since the LTIP began in 2006. The increased target award levels reflected the CGN
Committee’s continued desire to place a significant portion of the NEO’s pay at risk, provide total direct compensation that is competitive, and place ongoing focus on achieving Dominion’s long-term growth plan as discussed further below.
The CGN Committee strongly believes in pay for performance and recognizes that Dominion’s continued strong absolute and relative TSR is due substantially in part to the contributions of senior management under the leadership of Dominion’s CEO, Mr. Farrell. In determining the target long-term incentive awards for each of the NEOs, the CGN Committee took into consideration, among many factors, the continued superior performance by each of the NEOs, industry competitiveness for personnel (especially personnel with nuclear expertise), the NEO’s tenure with the company and in his current position and the scope of the NEO’s responsibilities.
The CGN Committee also considered the need for continued focus by the NEOs on Dominion’s long-term growth plan which involves all of the business units of the company and is expected to include approximately $14 billion in investment from 2014 to 2018 to grow its energy infrastructure. In addition, in determining Mr. Farrell’s target long-term incentive award, the CGN Committee also considered Mr. Farrell’s experience as CEO, Dominion’s strong performance under his leadership, the successful advancement of Dominion’s long-term initiatives, the complexity of Dominion’s business, and other factors.
As a result of these considerations, the CGN Committee approved the following target long-term incentive awards for the NEOs for 2013:
| | | | | | | | | | | | | | | | | | Name | | 2013
Performance Grant | | | 2013
Restricted
Stock Grant | | | 2013
Total Target
Long-Term
Incentive Award | | | 2012
Total Target
Long-Term
Incentive Award | | Thomas F.
Farrell II | | $ | 1,350,300 | | | $ | 1,350,300 | | | $ | 2,700,600 | | | $ | 2,250,500 | | Mark F. McGettrick | | | 573,973 | | | | 573,973 | | | | 1,147,946 | | | | 1,043,588 | | David A. Christian | | | 439,218 | | | | 439,218 | | | | 878,435 | | | | 798,578 | | Paul D. Koonce | | | 293,759 | | | | 293,759 | | | | 587,518 | | | | 513,953 | | David A. Heacock | | | 156,300 | | | | 156,300 | | | | 312,600 | | | | 260,500 | |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
Information regarding the fair value of the 2013 restricted stock grants and target cash performance grants for the NEOs is provided in theGrants of Plan-Based Awardstable.
2013 RESTRICTED STOCK GRANTS
All officers received a restricted stock grant on February 1, 2013 based on the stated dollar value above. The number of shares awarded was determined by dividing the stated dollar value by the closing price of Dominion’s common stock on February 1, 2013. The grants have a three-year vesting term, with cliff vesting at the end of the restricted period on February 1, 2016. Dividends are paid to officers during the restricted period. The grant date fair value and vesting terms of the 2013 restricted stock grant awards made to the NEOs are disclosed in theGrants of Plan-Based Awards table and related footnotes.
2013 PERFORMANCE GRANTS
In January 2013, the CGN Committee approved cash performance grants for the NEOs, effective February 1, 2013. The performance period commenced on January 1, 2013 and will end on December 31, 2014. The 2013 performance grants are denominated as a target award, with potential payouts ranging from 0% to 200% of the target based on Dominion’s TSR relative to the Philadelphia Utility Index and ROIC, weighted equally. (SeePerformance Grant Peer Group for additional information on the Philadelphia Utility Index.)
The TSR metric was selected to focus officers on long-term shareholder value when developing and implementing their strategic plans and in turn, reward management based on the achievement of TSR levels as measured relative to the Performance Grant Peer Group. The ROIC metric was selected to reward officers for the achievement of expected levels of return on Dominion’s investments. Dominion believes an ROIC measure encourages management to choose the right investments, and with those investments, to achieve the highest returns possible through prudent decisions, management and control of costs. The target awards and vesting terms of the 2013 performance grants made to the NEOs are disclosed in theGrants of Plan-Based Awards table and related footnotes.
PERFORMANCE GRANT PEER GROUP
The CGN Committee approved measuring TSR performance for the 2013 performance grants against the TSR of the companies listed as members of the Philadelphia Utility Index at the end of the performance period (the Performance Grant Peer Group). In selecting the Philadelphia Utility Index, the CGN Committee took into consideration that the companies represented in the Philadelphia Utility Index are similar to those companies currently included in Dominion’s Compensation Peer Group and the index itself is a recognized published index whose members are determined externally and independently from Dominion. The companies in the Philadelphia Utility Index at the grant date of the 2013 performance grants were as follows:
| | | The AES Corporation
Ameren Corporation
American Electric Power Company, Inc.
CenterPoint Energy, Inc.
Consolidated Edison, Inc.
Covanta Holding Corporation
| | El Paso Electric Company
Entergy Corporation
Exelon Corporation
FirstEnergy Corp.
NextEra Energy, Inc.
Northeast Utilities
PG&E Corporation
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| | | DTE Energy Company
Duke Energy Corporation
Edison International
| | Public Service Enterprise Group Incorporated
The Southern Company
Xcel Energy Inc.
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PAYOUT UNDER 2012 PERFORMANCE GRANTS
In February 2014, final payouts were made to officers who received cash performance grants in February 2012, including the NEOs. The 2012 performance grants were based on two goals: TSR for the two-year period ended December 31, 2013 relative to the companies in the Philadelphia Utility Index as of the end of the performance period (weighted 50%) and ROIC for the same two-year period (weighted 50%).
Ÿ | | Relative TSR (50% weighting). TSR is the difference between the value of a share of common stock at the beginning and end of the two-year performance period, plus dividends paid as if reinvested in stock. For this metric, Dominion’s TSR is compared to TSR levels of the companies in the Philadelphia Utility Index as of the end of the same two-year period. The relative TSR targets and corresponding payout scores for the 2012 performance grant were as follows:
|
| | | | | Relative TSR Performance
Percentile Ranking
| | Percentage Payout of
TSR Percentage* | | 85th or above
| | | 200% | | 50th
| | | 100% | | 25th
| | | 50% | | Below 25th
| | | 0% | |
| * | TSR weighting is interpolated between the top and bottom of the percentages within a quartile. A minimum payment of 25% of the TSR percentage will be made if the TSR performance is at least 10% on a compounded annual basis for the performance period, regardless of relative performance. |
Actual relative TSR performance for the 2012-2013 period was in the 84th percentile which produced a payout of 197.7%. Dominion’s TSR for the two-year period ended December 31, 2013 was 32.0%.
Ÿ | | ROIC (50% weighting). ROIC reflects Dominion’s total return divided by average invested capital for the performance period. The ROIC goal at target is consistent with the strategic plan/annual business plan as approved by Dominion’s Board of Directors. For this purpose, total return is Dominion’s consolidated operating earnings plus its after-tax interest and related charges, plus preferred dividends. Dominion designed its 2012 ROIC goals to provide 100% payout if it achieved an ROIC between 7.44% and 7.62% over the two-year performance period. The ROIC performance targets and corresponding payout scores for the 2012 performance grant were as follows:
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| | | | | | ROIC Performance | | Percentage Payout of
ROIC Component* | | 7.80% and above | | | 200% | | 7.44% – 7.62% | | | 100% | | 7.26% | | | 50% | | Below 7.26% | | | 0% | |
| * | ROIC percentage payout is interpolated between the top and bottom of the percentages for any range. |
Actual ROIC performance for the 2012-2013 period was 7.25%, which was below the threshold and resulted in no payout for the ROIC component of the award.
Based on the achievement of the TSR and ROIC performance goals, the CGN Committee approved a 98.9% payout for the 2012 performance grants. The following table summarizes the achievement of the 2012 performance goals:
| | | | | | | | | | | | | | | | | | | | | | Measure | | Goal
Weight% | | | | | | Goal
Achievement% | | | | | | Payout% | | Relative TSR | | | 50% | | | | X | | | | 197.7% | | | | = | | | | 98.9% | | ROIC | | | 50% | | | | X | | | | 0.0% | | | | = | | | | 0.0% | | | | | | | | | | | | | | | | | | | | | | | Combined Overall Performance Score | | | | | | | | 98.9% | |
The resulting payout amounts for the NEOs for the 2012 performance grants are shown below and are also reflected in theNon-Equity Incentive Plan Compensation column of theSummary Compensation Table.
| | | | | | | | | | | | | | | | | | | | | | Name | | 2012
Performance
Grant Award | | | | | | Overall
Performance
Score | | | | | | Calculated
Performance
Grant Payout | | Thomas F. Farrell II | | $ | 1,125,250 | | | | X | | | | 98.9% | | | | = | | | $ | 1,112,872 | | Mark F. McGettrick | | | 521,794 | | | | X | | | | 98.9% | | | | = | | | | 516,054 | | David A. Christian | | | 399,289 | | | | X | | | | 98.9% | | | | = | | | | 394,897 | | Paul D. Koonce | | | 256,976 | | | | X | | | | 98.9% | | | | = | | | | 254,150 | | David A. Heacock | | | 130,250 | | | | X | | | | 98.9% | | | | = | | | | 128,817 | |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
Employee and Executive Benefits
Benefit plans and limited perquisites compose the fourth element of Dominion’s compensation program. These benefits serve as a retention tool and reward long-term employment.
RETIREMENT PLANS
Dominion sponsors two types of tax-qualified retirement plans for eligible non-union employees, including the NEOs: a defined benefit pension plan (the Dominion Pension Plan) and a defined contribution 401(k) savings plan. The NEOs, as employees hired before 2008, are eligible for a pension benefit upon attainment of retirement age based on a formula that takes into account final compensation and years of service. They also receive a cash retirement benefit under which the company contributes 2% of each participant’s compensation to a special retirement account, which may be paid in a lump sum or added to the annuity benefit upon retirement. The company began funding the special retirement account for eligible employees in January 2001. The formula for the Dominion Pension Plan is explained in the narrative following thePension Benefits table. The change in Dominion Pension Plan value for 2013 for the NEOs is included in theSummary Compensation Table.
All participating employees in the 401(k) Plan (including the NEOs) are eligible to receive a matching contribution. Officers whose matching contributions under the 401(k) Plan are limited by the IRC receive a cash payment to make them whole for the company match lost as a result of these limits. These cash payments are
currently taxable. The company matching contributions to the 401(k) Plan and the cash payments of company matching contributions above the IRC limits for the NEOs are included in theAll Other Compensation column of theSummary Compensation Table and detailed in the footnote for that column.
Dominion also maintains two nonqualified retirement plans for its executives, the BRP and the ESRP. Unlike the Dominion Pension Plan and 401(k) Plan, these plans are unfunded, unsecured obligations of the company. These plans keep Dominion competitive in attracting and retaining officers. Due to the IRC limits on pension plan benefits and because a more substantial portion of total compensation for officers is paid as incentive compensation than for other employees, the Dominion Pension Plan and 401(k) Plan alone will produce a lower percentage of replacement income in retirement for officers than these plans will provide for other employees. The BRP restores benefits that will not be paid under the Dominion Pension Plan due to IRC limits. The ESRP provides a benefit that covers a portion (25%) of final base salary and target annual incentive compensation to partially make up for this gap in retirement income. The Dominion Pension Plan, 401(k) Plan, BRP and ESRP do not include long-term incentive compensation in benefit calculations and, therefore, a significant portion of the potential compensation for officers is excluded from calculation in any retirement plan benefit. As consideration for the benefits earned under the BRP and ESRP, all officers agree to comply with confidentiality and one-year non-competition requirements set forth in the plan documents following their retirement or other termination of employment. The present value of accumulated benefits under these retirement plans is disclosed in thePension Benefits table and the terms of the plans are fully explained in the narrative following that table. Effective July 1, 2013, the ESRP is closed to any new participants.
In individual situations and primarily for mid-career changes or retention purposes, the CGN Committee has granted certain officers additional years of credited age and service for purposes of calculating benefits under the BRP. Age and service credits granted to the NEOs are described inDominion Retirement Benefit Restoration PlanunderPension Benefits.Additional age and service may also be earned under the terms of an officer’s Employee Continuity Agreement in the event of a change in control, as described inChange in Control underPotential Payments Upon Termination or Change in Control.No additional years of age or service credit were granted to the NEOs during 2013.
OTHER BENEFIT PROGRAMS
Dominion’s officers participate in all of the benefit programs available to other Dominion employees. The core benefit programs generally include medical, dental and vision benefit plans, a health savings account, health and dependent care flexible spending accounts, group-term life insurance, travel accident coverage, long-term disability coverage and a paid time off program.
Dominion also maintains an executive life insurance program for officers to replace a former company-wide retiree life insurance program that was discontinued in 2003. The plan is fully insured by individual policies that provide death benefits at a fixed amount depending on an officer’s salary tier. This life insurance coverage is in addition to the group-term insurance that
is provided to all employees. The officer is the owner of the policy and Dominion makes premium payments until the later of 10 years from enrollment date or the date the officer attains age 64. Officers are taxed on the premiums paid by Dominion. The premiums for these policies are included in theAll Other Compensation column of theSummary Compensation Table.
PERQUISITES
Dominion provides a limited number of perquisites for its officers to enable them to perform their duties and responsibilities as efficiently as possible and to minimize distractions. The CGN Committee annually reviews the perquisites to ensure they are an effective and efficient use of corporate resources. Dominion believes the benefits it receives from offering these perquisites outweigh the costs of providing them. In addition to incidental perquisites associated with maintaining an office, Dominion offers the following perquisites to all officers:
Ÿ | | An allowance of up to $9,500 a year to be used for health club memberships and wellness programs, comprehensive executive physical exams and financial and estate planning. Dominion wants officers to be proactive with preventive healthcare and also wants executives to use professional, independent financial and estate planning consultants to ensure proper tax reporting of company-provided compensation and to help officers optimize their use of Dominion’s retirement and other employee benefit programs.
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Ÿ | | A vehicle leased by Dominion, up to an established lease-payment limit (if the lease payment exceeds the allowance, the officer pays for the excess amount on the vehicle). The costs of insurance, fuel and maintenance for company-leased vehicles are paid by Dominion.
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Ÿ | | In limited circumstances, use of company aircraft for personal travel by executive officers. For security and other reasons, Dominion’s Board of Directors has directed Mr. Farrell to use the aircraft for all travel, including personal travel, whenever it is feasible to do so. Mr. Farrell’s family and guests may accompany him on any personal trips. The use of company aircraft for personal travel by other executive officers is limited and usually related to (i) travel with the CEO or (ii) personal travel to accommodate business demands on an executive’s schedule. With the exception of Mr. Farrell, personal use of aircraft is not available when there is a company need for the aircraft. Use of company aircraft saves substantial time and allows Dominion to have better access to its executives for business purposes. During 2013, 94% of the use of Dominion’s aircraft was for business purposes. None of the NEOs’ compensation for use of the company aircraft is attributable to their service for Virginia Power.
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Other than costs associated with comprehensive executive physical exams (which are exempt from taxation under the IRC), these perquisites are fully taxable to officers. There is no tax gross-up for imputed income on any perquisites.
EMPLOYMENT CONTINUITY AGREEMENTS
Dominion has entered into Employment Continuity Agreements with all officers to ensure continuity in the event of a change in control at Dominion. In addition to these agreements being consistent with the practices of Dominion’s peer companies for competitive purposes, the most important reason for these agree-
ments is to protect the company in the event of an anticipated or actual change in control of Dominion. In a time of transition, it is critical to protect shareholder value by retaining and continuing to motivate the company’s core management team. In a change in control situation, workloads typically increase dramatically, outside competitors are more likely to attempt to recruit top performers away from the company, and officers and other key employees may consider other opportunities when faced with uncertainties at their own company. Therefore, the Employment Continuity Agreements provide security and protection to officers in such circumstances for the long-term benefit of Dominion and its shareholders.
In determining the appropriate multiples of compensation and benefits payable upon a change in control, Dominion evaluated peer group and general practices and considered the levels of protection necessary to retain officers in such situations. The Employment Continuity Agreements are double-trigger agreements that require both a change in control and a qualifying termination of employment to trigger most benefits. The specific terms of the Employment Continuity Agreements are discussed inPotential Payments Upon Termination or Change in Control.
In January 2013, the CGN Committee approved the elimination of the excise tax gross up provision included in the Employment Continuity Agreement for any new officer elected after February 1, 2013.
OTHER AGREEMENTS
Dominion does not have comprehensive employment agreements or severance agreements with its NEOs. Although the CGN Committee believes the compensation and benefit programs described in this CD&A are appropriate, Dominion, as one of the nation’s largest producers and transporters of energy, is part of a constantly changing and increasingly competitive environment. In recognition of their valuable knowledge and experience and to secure and retain their services, Dominion has entered into letter agreements with certain of its NEOs to provide certain benefit enhancements or other protections, as described inDominion Retirement Benefit Restoration Plan, Dominion Executive Supplemental Retirement Planand Potential Payments Upon Termination or Change in Control. No new letter agreements were entered into in 2013.
OTHER RELEVANT COMPENSATION PRACTICES
Share Ownership Guidelines
Dominion requires officers to own and retain significant amounts of Dominion stock during their careers to align their interests with those of Dominion’s shareholders by promoting a long-term focus through long-term share ownership. The guidelines ensure that management maintains a personal stake in the company through significant equity investment in the company. Targeted ownership levels are the lesser of the following value or number of shares:
| | | | | Position | | Value/# of Shares | | Chairman, President & Chief Executive Officer
| | | 8 x salary/145,000 | | Executive Vice President—Dominion
| | | 5 x salary/35,000 | | Senior Vice President—Dominion & Subsidiaries/President—Dominion Subsidiaries
| | | 4 x salary/20,000 | | Vice President—Dominion & Subsidiaries
| | | 3 x salary/10,000 | |
The levels of ownership reflect the increasing level of responsibility for that officer’s position. Shares owned by an officer and his or her immediate family members as well as shares held under Dominion benefit plans count toward the ownership targets. Restricted stock, goal-based stock and shares underlying stock options do not count toward the ownership targets until the shares vest or the options are exercised. Dominion prohibits certain types of transactions related to Dominion stock, including owning derivative securities, hedging transactions, using margin accounts and pledging shares as collateral.
Until an officer meets his or her ownership target, an officer must retain all after-tax shares from the vesting of restricted stock and goal-based stock awards. Dominion refers to shares held by an officer that are more than 15% above his or her ownership target as qualifying excess shares. An officer may sell, gift or transfer qualifying excess shares at any time, subject to insider trading rules and other policy provisions as long as the sale, gift or transfer does not cause an executive to fall below his or her ownership target.
At least annually, the CGN Committee reviews the share ownership guidelines and monitors compliance by executive officers, both individually and by the officer group as a whole. As of January 1, 2014, each NEO exceeded his share ownership target as shown below:
| | | | | | | | | | | | Shares Owned and Counted Toward Target(1) | | | Share Ownership
Target(2) | | Thomas F. Farrell II | | | 625,665 | | | | 145,000 | | Mark F. McGettrick | | | 176,423 | | | | 35,000 | | David A. Christian | | | 56,270 | | | | 35,000 | | Paul D. Koonce | | | 84,028 | | | | 35,000 | | David A. Heacock | | | 24,561 | | | | 20,000 | |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Amounts shown are actual and not reduced by their Virginia Power allocation factor.
(1) | Amounts in this column do not include shares of unvested restricted stock which are not counted toward ownership targets |
(2) | Share ownership target is the lesser of salary multiple or number of shares |
Recovery of Incentive Compensation
Dominion’s Corporate Governance Guidelines authorize the Board of Directors to seek recovery of performance-based compensation paid to officers who are found to be personally responsible for fraud or intentional misconduct that causes a restatement of financial results filed with the SEC. Dominion’s AIP and long-term incentive performance grant documents
include a broader clawback provision that authorizes the CGN Committee, in its discretion and based on facts and circumstances, to recoup AIP and performance grant payouts from any employee whose fraudulent or intentional misconduct (i) directly causes or partially causes the need for a restatement of a financial statement or (ii) relates to or materially affects Dominion’s operations or the employee’s duties at the company. Dominion reserves the right to recover a payout by seeking repayment from the employee, by reducing the amount that would otherwise be payable to the employee under another company benefit plan or compensation program to the extent permitted by applicable law, by withholding future incentive compensation, or any combination of these actions. The clawback provision is in addition to, and not in lieu of, other actions Dominion may take to remedy or discipline misconduct, including termination of employment or a legal action for breach of fiduciary duty, and any actions imposed by law enforcement agencies.
Tax Deductibility of Compensation
Section 162(m) of the IRC generally disallows a deduction by publicly held corporations for compensation in excess of $1 million paid to the CEO and the next three most highly compensated officers other than the CFO. If certain requirements are met, performance-based compensation qualifies for an exemption from the IRC Section 162(m) deduction limit. Dominion generally seeks to provide competitive executive compensation while maximizing Dominion’s tax deduction. While the CGN Committee considers IRC Section 162(m) tax implications when designing annual and long-term incentive compensation programs and approving payouts under such programs, it reserves the right to approve, and in some cases has approved, non-deductible compensation when it feels that corporate objectives justify the cost of being unable to deduct such compensation. Dominion’s tax department has advised the CGN Committee that the cost of any such lost tax deductions has not been material to the company.
Accounting for Stock-Based Compensation
Dominion measures and recognizes compensation expense in accordance with the FASB guidance for share-based payments, which requires that compensation expense relating to share-based payment transactions be recognized in the financial statements based on the fair value of the equity or liability instruments issued. The CGN Committee considers the accounting treatment of equity and performance-based compensation when approving awards.
Executive Compensation
SUMMARY COMPENSATION TABLE – AN OVERVIEW
The Summary Compensation Table provides information in accordance with SEC requirements regarding compensation earned by the NEOs, stock awards made to the NEOs, as well as amounts accrued or accumulated during years reported with respect to retirement plans and other items. The NEOs include the CEO, the CFO, and the three most highly compensated executive officers other than the CEO and CFO.
The amounts reported in the Summary Compensation Table and the other tables below represent the prorated compensation amounts attributable to each NEO’s services performed for Virginia Power. The percentage of each NEO’s overall Dominion services performed for Virginia Power during 2013 was as follows: Mr. Farrell, 32%; Mr. McGettrick, 49%; Mr. Christian, 60%; Mr. Koonce 40%; and Mr. Heacock, 52%.
The following highlights some of the disclosures contained in this table for the NEOs. Detailed explanations regarding certain types of compensation paid to an NEO are included in the footnotes to the table.
Salary. The amounts in this column are the base salaries earned by the NEOs for the years indicated.
Stock Awards. The amounts in this column reflect the grant date fair value of the stock awards for accounting purposes for the respective year. Stock awards are reported in the year in which the awards are granted regardless of when or if the awards vest or are exercised.
Non-Equity Incentive Plan Compensation. This column includes amounts earned under two performance-based programs: the AIP and cash-based performance grant awards under Dominion’s LTIP. These performance programs are based on performance criteria established by the CGN Committee at the beginning of the performance period, with actual performance scored against the pre-set criteria by the CGN Committee at the end of the performance period.
Change in Pension Value and Nonqualified Deferred Compensation Earnings. This column shows any year-over-year increases in the annual accrual of pension and supplemental retirement benefits for the NEOs. These are accruals for future benefits under the terms of the retirement plans, and are not actual payments made during the year to the NEOs. The
amounts disclosed reflect the annual change in the actuarial present value of benefits under defined benefit plans sponsored by Dominion, which include the tax-qualified Dominion Pension Plan and the nonqualified plans described in the narrative following thePension Benefits table. The annual change equals the difference in the accumulated amount for the current fiscal year and the accumulated amount for the prior fiscal year, generally using the same actuarial assumptions used for Dominion’s audited financial statements for the applicable fiscal year. Accrued benefit calculations are based on assumptions that the NEOs would retire at the earliest age at which they are projected to become eligible for full, unreduced pension benefits (including the effect of future service for eligibility purposes), instead of their unreduced retirement age based on current years of service. The application of these assumptions results in a greater increase in the accumulated amount of pension benefits for certain NEOs than would result without the application of these assumptions. This method of calculation does not increase actual benefits payable at retirement but only how much of that benefit is allocated to the increase during the years presented in the Summary Compensation Table. Please refer to the footnotes to thePension Benefits table and the narrative following that table for additional information related to actuarial assumptions used to calculate pension benefits.
All Other Compensation. The amounts in this column disclose compensation that is not classified as compensation reportable in another column, including perquisites and benefits with an aggregate value of at least $10,000, the value of company-paid life insurance premiums, company matching contributions to an NEO’s 401(k) Plan account, and company matching contributions paid directly to the NEO that would be credited to the 401(k) Plan if IRC contribution limits did not apply.
Total. The number in this column provides a single figure that represents the total compensation either earned by each NEO for the years indicated or accrued benefits payable in later years and required to be disclosed by SEC rules in this table. It does not reflect actual compensation paid to the NEO during the year, but is the sum of the dollar values of each type of compensation quantified in the other columns in accordance with SEC rules.
SUMMARY COMPENSATION TABLE
The following table presents information concerning compensation paid or earned by the NEOs for the years ended December 31, 2013, 2012 and 2011 as well as the grant date fair value of stock awards and changes in pension value.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Name and Principal Position | | Year | | | Salary(1) | | | Stock
Awards(2) | | | Non-Equity
Incentive Plan
Compensation(3) | | | Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings(4) | | | All Other
Compensation(5) | | | Total | | Thomas F. Farrell II Chairman and Chief Executive Officer | | | 2013 | | | $ | 433,605 | | | $ | 1,350,305 | | | $ | 1,657,523 | | | $ | — | | | $ | 34,148 | | | $ | 3,475,581 | | | | | 2012 | | | | 381,827 | | | | 1,027,602 | | | | 946,561 | | | | 1,171,041 | | | | 54,815 | | | | 3,581,846 | | | | | 2011 | | | | 393,084 | | | | 1,127,702 | | | | 2,351,094 | | | | 584,944 | | | | 51,827 | | | | 4,508,651 | | Mark F. McGettrick Executive Vice President and Chief Financial Officer | | | 2013 | | | | 349,825 | | | | 573,984 | | | | 868,677 | | | | — | | | | 42,724 | | | | 1,835,210 | | | | | 2012 | | | | 311,880 | | | | 1,632,701 | | | | 480,389 | | | | 1,169,718 | | | | 31,291 | | | | 3,625,979 | | | | | 2011 | | | | 320,948 | | | | 485,013 | | | | 1,008,431 | | | | 802,520 | | | | 33,962 | | | | 2,650,874 | | David A. Christian President and COO (Dominion Generation) | | | 2013 | | | | 375,134 | | | | 439,250 | | | | 734,165 | | | | 166,946 | | | | 60,933 | | | | 1,776,428 | | | | | 2012 | | | | 323,858 | | | | 1,166,905 | | | | 364,726 | | | | 1,188,167 | | | | 51,191 | | | | 3,094,847 | | | | | 2011 | | | | 309,329 | | | | 309,058 | | | | 608,095 | | | | 682,795 | | | | 52,785 | | | | 1,962,062 | | Paul D. Koonce President and COO (DVP) | | | 2013 | | | | 237,744 | | | | 293,781 | | | | 469,098 | | | | 295,808 | | | | 23,376 | | | | 1,319,807 | | | | | 2012 | | | | 429,614 | | | | 1,764,103 | | | | 531,159 | | | | 1,115,497 | | | | 46,657 | | | | 3,887,030 | | | | | 2011 | | | | 423,840 | | | | 471,012 | | | | 1,107,655 | | | | 695,145 | | | | 49,323 | | | | 2,746,975 | | David A. Heacock President and CNO | | | 2013 | | | | 235,768 | | | | 156,325 | | | | 294,660 | | | | 72,705 | | | | 23,584 | | | | 783,042 | | | | | 2012 | | | | 206,435 | | | | 117,665 | | | | 159,303 | | | | 462,314 | | | | 22,968 | | | | 968,685 | | | | | 2011 | | | | 215,395 | | | | 128,803 | | | | 318,493 | | | | 388,820 | | | | 20,921 | | | | 1,072,432 | |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
(1) | The NEOs received the following base salary increases effective March 1, 2013: Messrs. Farrell, Christian, Koonce and Heacock: 3%; and Mr. McGettrick: 5%. Effective January 1, 2013, the CGN Committee increased Mr. Koonce’s base salary 10% to recognize his increased responsibility as CEO of the Energy Infrastructure Group, with the CEO of the Dominion Energy business unit reporting to him in addition to the DVP business unit.
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(2) | The amounts in this column reflect the grant date fair value of stock awards for the respective year grant in accordance with FASB guidance for share-based payments. Dominion did not grant any stock options in 2013. See also Note 19 to the Consolidated Financial Statements in Dominion’s 2013 Annual Report on Form 10-K for more information on the valuation of stock-based awards, the Grants of Plan-Based Awards table for stock awards granted in 2013, and the Outstanding Equity Awards at Fiscal Year-End table for a listing of all outstanding equity awards as of December 31, 2013.
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(3) | The 2013 amounts in this column include the payouts under Dominion’s 2013 AIP and 2012 Performance Grant Awards. All of the NEOs received 100% funding of their 2013 AIP target awards. Messrs. Farrell, McGettrick, Christian and Heacock each received 100% payouts for accomplishment of their goals while Mr. Koonce received a 99.97% payout. The 2013 AIP payout amounts were as follows: Mr. Farrell: $544,651; Mr. McGettrick: $352,623; Mr. Christian: $339,268; Mr. Koonce: $214,948; and Mr. Heacock: $165,843. See CD&A for additional information on the 2013 AIP and the Grants of Plan-Based Awards table for the range of each NEO’s potential award under the 2013 AIP. The 2012 Performance Grant Award was issued on February 1, 2012 and the payout amount was determined based on achievement of performance goals for the performance period ended December 31, 2013. Payouts can range from 0% to 200%. The actual payout was 98.9% of the target amount. The 2012 performance grant payout amounts were as follows: Mr. Farrell: $1,112,872; Mr. McGettrick: $516,054; Mr. Christian: $394,897; Mr. Koonce: $254,150; and Mr. Heacock: $128,817. The 2012 performance grant payouts were allocated based on the percentage of the executive’s services performed for Virginia Power during 2013. See Payout Under 2012 Performance Grants of CD&A for additional information on the 2012 performance grants. The 2012 amounts reflect both the 2012 AIP and the 2011 performance grant payouts, and the 2011 amounts reflect both the 2011 AIP and 2010 performance grant payouts.
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(4) | All amounts in this column are for the aggregate change in the actuarial present value of the NEO’s accumulated benefit under the Dominion Pension Plan and nonqualified executive retirement plans. There are no above-market earnings on nonqualified deferred compensation plans. These accruals are not directly in relation to final payout potential, and can vary significantly year over year based on (i) promotions and corresponding changes in salary; (ii) other one-time adjustments to salary or incentive target for market or other reasons; (iii) actual age versus predicted age at retirement; (iv) discount rate used to determine present value of benefit; and (v) other relevant factors. Reductions in the actuarial present value of an NEO’s accumulated pension benefits are reported as $0. A change in the discount rate can be a significant factor in the change reported in this column. A decrease in the discount rate results in an increase in the present value of the accumulated benefit without any increase in the benefits payable to the NEO at retirement and an increase in the discount rate has the opposite effect. The discount rate used in determining the present value of the accumulated benefit increased from 4.40% used as of December 31, 2012 to a discount rate of 5.30% used as of December 31, 2013. The decrease in present value attributed solely to the change in discount rate was as follows: Mr. Farrell: $(581,168); Mr. McGettrick: $(525,923); Mr. Christian: $(457,868); Mr. Koonce: $(241,417); and Mr. Heacock: $(211,425).
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(5) | All Other Compensation amounts for 2013 are as follows:
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| | | | | | | | | | | | | | | | | | | | | | Name | | Executive
Perquisites(a) | | | Life
Insurance
Premiums | | | Employee
401(k) Plan
Match(b) | | | Company Match
Above IRS
Limits(c) | | | Total All Other
Compensation | | Thomas F. Farrell II | | $ | 8,155 | | | $ | 9,468 | | | $ | 2,459 | | | $ | 14,066 | | | $ | 34,148 | | Mark F. McGettrick | | | 14,872 | | | | 13,859 | | | | 5,009 | | | | 8,984 | | | | 42,724 | | David A. Christian | | | 19,130 | | | | 26,797 | | | | 6,148 | | | | 8,858 | | | | 60,933 | | Paul D. Koonce | | | 10,656 | | | | 5,587 | | | | 3,084 | | | | 4,049 | | | | 23,376 | | David A. Heacock | | | 6,828 | | | | 7,325 | | | | 5,314 | | | | 4,117 | | | | 23,584 | |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
(a) | Unless noted, the amounts in this column for all NEOs are comprised of the following: personal use of company vehicle and financial planning and health and wellness allowance. |
(b) | Employees initially hired before 2008 who contribute to the 401(k) Plan receive a matching contribution of 50 cents for each dollar contributed up to 6% of compensation (subject to IRS limits) for employees who have less than 20 years of service, and 67 cents for each dollar contributed up to 6% of compensation (subject to IRS limits) for employees who have 20 or more years of service. |
(c) | Represents each payment of lost 401(k) Plan matching contribution due to IRS limits. |
GRANTS OF PLAN-BASED AWARDS
The following table provides information about stock awards and non-equity incentive awards granted to the NEOs during the year ended December 31, 2013.
| | | | | | | | | | | | | | | | | | | | | | | | | Name | | Grant
Date(1) | | Grant
Approval
Date(1) | | Estimated Future Payouts Under Non-Equity
Incentive Plan Awards | | | All Other
Stock Awards:
Number of
Shares of
Stock or
Units | | | Grant Date
Fair Value of
Stock and Options
Award(1)(4) | | | | | | Threshold | | | Target | | | Maximum | | | | Thomas F. Farrell II | | | | | | | | | | | | | | | | | | | | | | | | | 2013 Annual Incentive Plan(2) | | | | | | $ | — | | | $ | 544,651 | | | $ | 1,089,302 | | | | | | | | | | 2013 Cash Performance Grant(3) | | | | | | | — | | | | 1,350,300 | | | | 2,700,600 | | | | | | | | | | 2013 Restricted Stock Grant(4) | | 2/1/2013 | | 1/24/2013 | | | | | | | | | | | | | | | 24,927 | | | $ | 1,350,305 | | Mark F. McGettrick | | | | | | | | | | | | | | | | | | | | | | | | | 2013 Annual Incentive Plan(2) | | | | | | | — | | | | 352,623 | | | | 705,246 | | | | | | | | | | 2013 Cash Performance Grant(3) | | | | | | | — | | | | 573,973 | | | | 1,147,946 | | | | | | | | | | 2013 Restricted Stock Grant(4) | | 2/1/2013 | | 1/24/2013 | | | | | | | | | | | | | | | 10,595 | | | | 573,984 | | David A. Christian | | | | | | | | | | | | | | | | | | | | | | | | | 2013 Annual Incentive Plan(2) | | | | | | | — | | | | 339,268 | | | | 678,535 | | | | | | | | | | 2013 Cash Performance Grant(3) | | | | | | | — | | | | 439,218 | | | | 878,435 | | | | | | | | | | 2013 Restricted Stock Grant(4) | | 2/1/2013 | | 1/24/2013 | | | | | | | | | | | | | | | 8,108 | | | | 439,250 | | Paul D. Koonce | | | | | | | | | | | | | | | | | | | | | | | | | 2013 Annual Incentive Plan(2) | | | | | | | — | | | | 215,013 | | | | 430,026 | | | | | | | | | | 2013 Cash Performance Grant(3) | | | | | | | — | | | | 293,759 | | | | 587,518 | | | | | | | | | | 2013 Restricted Stock Grant(4) | | 2/1/2013 | | 1/24/2013 | | | | | | | | | | | | | | | 5,423 | | | | 293,781 | | David A. Heacock | | | | | | | | | | | | | | | | | | | | | | | | | 2013 Annual Incentive Plan(2) | | | | | | | — | | | | 165,843 | | | | 331,685 | | | | | | | | | | 2013 Cash Performance Grant(3) | | | | | | | — | | | | 156,300 | | | | 312,600 | | | | | | | | | | 2013 Restricted Stock Grant(4) | | 2/1/2013 | | 1/24/2013 | | | | | | | | | | | | | | | 2,885 | | | | 156,325 | |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
(1) | On January 24, 2013, the CGN Committee approved the 2013 long-term incentive compensation awards for Dominion officers, which consisted of a restricted stock grant and a cash performance grant. The 2013 restricted stock award was granted on February 1, 2013. Under the 2005 Incentive Compensation Plan, fair market value is defined as the closing price of Dominion common stock on the date of grant or, if that day is not a trading day, on the most recent trading day immediately preceding the date of grant. The fair market value for the February 1, 2013 restricted stock grant was $54.17 per share, which was Dominion’s closing stock price on February 1, 2013.
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(2) | Amounts represent the range of potential payouts under the 2013 AIP. Actual amounts paid under the 2013 AIP are found in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. Under Dominion’s AIP, officers are eligible for an annual performance-based award. The CGN Committee establishes target awards for each NEO based on his salary level and expressed as a percentage of the individual NEO’s base salary. The target award is the amount of cash that will be paid if the plan is fully funded and payout goals are achieved. For the 2013 AIP, funding was based on the achievement of consolidated operating earnings goals with the maximum funding capped at 200%, as explained under the Annual Incentive Plan section of the CD&A.
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(3) | Amounts represent the range of potential payouts under the 2013 performance grant of the LTIP. Payouts can range from 0% to 200% of the target award. Awards will be paid by March 15, 2015, depending on the achievement of performance goals for the two-year period ending December 31, 2014. The amount earned will depend on the level of achievement of two performance metrics: TSR—50% and ROIC—50%. TSR measures Dominion’s share performance for the two-year period ended December 31, 2014 relative to the TSR of the companies that are listed as members of the Philadelphia Utility Index as of the end of the performance period. ROIC goal achievement will be scored against 2013 and 2014 budget goals. See Exhibit 10.2 to Dominion’s Form 8-K filed on January 25, 2013 for TSR and ROIC goals.
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| The performance grant is forfeited in its entirety if an officer voluntarily terminates employment or is terminated with cause before the vesting date. The grants have pro-rated vesting for retirement, termination without cause, death or disability. In the case of retirement, pro-rated vesting will not occur if the CEO (or, for the CEO, the CGN Committee) determines the officer’s retirement is detrimental to the company. Payout for an officer who retires or whose employment is terminated without cause, is made following the end of the performance period so that the officer is rewarded only to the extent the performance goals are achieved. In the case of death or disability, payout is made as soon as possible to facilitate the administration of the officer’s estate or financial planning. The payout amount will be the greater of the officer’s target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominion’s financial statements. |
| In the event of a change in control, the performance grant is vested in its entirety and payout of the performance grant will occur as soon as administratively feasible following the change in control date at an amount that is the greater of an officer’s target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominion’s financial statements. |
(4) | The 2013 restricted stock grant fully vests at the end of three years. The restricted stock grant is forfeited in its entirety if an officer voluntarily terminates employment or is terminated with cause before the vesting date. The restricted stock grant provides for pro-rated vesting if an officer retires, dies, becomes disabled, is terminated without cause, or if there is a change in control. In the case of retirement, pro-rated vesting will not occur if the CEO (or for the CEO, the CGN Committee) determines the officer’s retirement is detrimental to the company. In the event of a change in control, pro-rated vesting is provided as of the change in control date, and full vesting if an officer’s employment is terminated, or constructively terminated by the successor entity following the change in control date but before the scheduled vesting date. Dividends on the restricted shares are paid during the restricted period at the same rate declared by Dominion for all shareholders.
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OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
The following table summarizes equity awards made to NEOs that were outstanding as of December 31, 2013. There were no unexercised or unexercisable option awards outstanding for any NEOs as of December 31, 2013.
| | | | | | | | | | | | Stock Awards | | | Name | | Number of
Shares or Units of
Stock that Have
Not Vested (#) | | | Market Value of
Shares or Units of
Stock That Have
Not Vested(1)($) | | Thomas F. Farrell II | | | 25,844 | (2) | | $ | 1,671,848 | | | | | 22,317 | (3) | | | 1,443,687 | | | | | 24,927 | (4) | | | 1,612,528 | | | | | | 36,206 | (5) | | | 2,342,166 | | Mark F. McGettrick | | | 11,279 | (2) | | | 729,639 | | | | | 10,348 | (3) | | | 669,412 | | | | | 10,595 | (4) | | | 685,391 | | | | | | 24,424 | (6) | | | 1,579,989 | | David A. Christian | | | 7,786 | (2) | | | 503,676 | | | | | 7,919 | (3) | | | 512,280 | | | | | 8,108 | (4) | | | 524,507 | | | | | | 17,983 | (6) | | | 1,163,320 | | Paul D. Koonce | | | 5,208 | (2) | | | 336,906 | | | | | 5,096 | (3) | | | 329,660 | | | | | 5,423 | (4) | | | 350,814 | | | | | | 12,028 | (6) | | | 778,091 | | David A. Heacock | | | 2,991 | (2) | | | 193,488 | | | | | 2,583 | (3) | | | 167,094 | | | | | | 2,885 | (4) | | | 186,631 | |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
(1) | The market value is based on closing stock price of $64.69 on December 31, 2013.
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(2) | Shares scheduled to vest on February 1, 2014.
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(3) | Shares scheduled to vest on February 1, 2015.
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(4) | Shares scheduled to vest on February 1, 2016.
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(5) | Shares scheduled to vest on December 17, 2015. Amount includes dividends reinvested into additional shares that are restricted and subject to the same terms and conditions of the underlying restricted stock grant.
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(6) | Shares scheduled to vest on December 20, 2015. Amount includes dividends reinvested into additional shares that are restricted and subject to the same terms and conditions of the underlying restricted stock grant.
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OPTION EXERCISESAND STOCK VESTED
The following table provides information about the value realized by NEOs during the year ended December 31, 2013 on vested restricted stock awards. There were no option exercises by NEOs in 2013.
| | | | | | | | | | | | Stock Awards | | | Name | | Number of
Shares
Acquired on
Vesting | | | Value Realized on
Vesting | | Thomas F. Farrell II | | | 30,038 | | | $ | 1,943,158 | | Mark F. McGettrick | | | 11,799 | | | | 763,277 | | David A. Christian | | | 6,838 | | | | 442,350 | | Paul D. Koonce | | | 6,053 | | | | 391,569 | | David A. Heacock | | | 3,129 | | | | 202,415 | |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
PENSION BENEFITS
The following table shows the actuarial present value of accumulated benefits payable to NEOs, together with the number of years of benefit service credited to each NEO, under the plans listed in the table. Values are computed as of December 31, 2013, using the same interest rate and mortality assumptions used in determining the aggregate pension obligations disclosed in Dominion’s financial statements. The years of credited service and the present value of accumulated benefits were determined by the plan actuaries, using the appropriate accrued service, pay and other assumptions similar to those used for accounting and disclosure purposes. Please refer toActuarial Assumptions Used to Calculate Pension Benefitsfor detailed information regarding these assumptions.
| | | | | | | | | | | | Name | | Plan Name | | Number of
Years
Credited
Service(1) | | | Present Value
of Accumulated
Benefit(2) | | Thomas F. Farrell II | | Dominion Pension Plan | | | 18.00 | | | $ | 335,194 | | | | Benefit Restoration Plan | | | 29.00 | | | | 3,443,656 | | | | | Supplemental Retirement Plan | | | 29.00 | | | | 4,142,899 | | Mark F. McGettrick | | Dominion Pension Plan | | | 29.50 | | | | 726,651 | | | | Benefit Restoration Plan | | | 30.00 | | | | 2,939,371 | | | | | Supplemental Retirement Plan | | | 30.00 | | | | 3,211,235 | | David A. Christian | | Dominion Pension Plan | | | 29.50 | | | | 1,082,455 | | | | Benefit Restoration Plan | | | 29.50 | | | | 2,238,052 | | | | | Supplemental Retirement Plan | | | 29.50 | | | | 2,949,044 | | Paul D. Koonce | | Dominion Pension Plan | | | 15.00 | | | | 273,326 | | | | Benefit Restoration Plan | | | 15.00 | | | | 390,794 | | | | | Supplemental Retirement Plan | | | 15.00 | | | | 1,882,681 | | David A. Heacock | | Dominion Pension Plan | | | 26.50 | | | | 758,509 | | | | Benefit Restoration Plan | | | 26.50 | | | | 614,636 | | | | | Supplemental Retirement Plan | | | 26.50 | | | | 745,467 | |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
(1) | Years of credited service shown in this column for the Dominion Pension Plan are actual years accrued by an NEO from his date of participation to December 31, 2013. Service for the BRP and the ESRP is the NEO’s actual credited service as of December 31, 2013 plus any potential total credited service to the plan maximum, including any extra years of credited service granted to Messrs. Farrell and McGettrick by the CGN Committee for the purpose of calculating benefits under these plans. Please refer to the narrative below and under Dominion Retirement Benefit Restoration Plan, Dominion Executive Supplemental Retirement Plan and Potential Payments Upon Termination or Change In Control for information about the requirements for receiving extra years of credited service and the amount credited, if any, for each NEO.
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(2) | The amounts in this column are based on actuarial assumptions that all of the NEOs would retire at the earliest age they become eligible for unreduced benefits, which is (i) age 60 for Messrs. Farrell, Koonce, Christian and Heacock, and (ii) age 55 for Mr. McGettrick (when he would be treated as age 60 based on his five additional years of credited age). In addition, for purposes of calculating the BRP benefits for Messrs. Farrell and McGettrick, the amounts reflect additional credited years of service granted to them pursuant to their agreements with the company (see Dominion Retirement Benefit Restoration Plan). If the amounts in this column did not include the additional years of credited service, the present value of the BRP benefit would be $1,560,187 lower for Mr. Farrell and $1,217,049 lower for Mr. McGettrick. Dominion Pension Plan and ESRP benefit amounts are not augmented by the additional service credit assumptions.
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Dominion Pension Plan
The Dominion Pension Plan is a tax-qualified defined benefit pension plan. All of the NEOs participate in the Dominion Pension Plan. The Dominion Pension Plan provides unreduced retirement benefits at termination of employment at or after age 65 or, with three years of service, at age 60. A participant who has attained age 55 with three years of service may elect early retirement benefits at a reduced amount. If a participant retires between ages 55 and 60, the benefit is reduced 0.25% per month for each month after age 58 and before age 60, and reduced 0.50% per month for each month between ages 55 and 58. All of the NEOs have more than three years of service.
The Dominion Pension Plan basic benefit is calculated using a formula based on (1) age at retirement; (2) final average earnings; (3) estimated Social Security benefits; and (4) credited service. Final average earnings are the average of the participant’s 60 highest consecutive months of base pay during the last 120 months worked. Final average earnings do not include compensation payable under the AIP, the value of equity awards, gains from the exercise of stock options, long-term cash incentive awards, perquisites or any other form of compensation other than base pay.
Credited service is measured in months, up to a maximum of 30 years of credited service. The estimated Social Security benefit taken into account is the assumed Social Security benefit payable starting at age 65 or actual retirement date, if later, assuming that the participant has no further employment after leaving Dominion. These factors are then applied in a formula.
The formula has different percentages for credited service through December 31, 2000 and on and after January 1, 2001. The benefit is the sum of the amounts from the following two formulas.
| | | | | | | For credited service through December 31, 2000: | 2.03%times Final Average Earningstimes Credited Service before 2001 | | | Minus | | | 2.00%times estimated Social Security benefittimes Credited Service before 2001 | | For credited service on or after January 1, 2001: | 1.80% times Final Average Earningstimes Credited Service after 2000 | | | Minus | | | 1.50%times estimated Social Security benefittimes Credited Service after 2000 |
Credited service is limited to a total of 30 years for all parts of the formula and credited service after 2000 is limited to 30 years minus credited service before 2001.
Benefit payment options are (1) a single life annuity or (2) a choice of a 50%, 75% or 100% joint and survivor annuity. A Social Security leveling option is available with any of the benefit forms. The normal form of benefit is a single life annuity for unmarried participants and a 50% joint and survivor annuity for married participants. All of the payment options are actuarially equivalent in value to the single life annuity. The Social Security leveling option pays a larger benefit equal to the estimated Social Security benefit until the participant is age 62 and then reduced payments after age 62.
The Dominion Pension Plan also includes a special retirement account, which is in addition to the pension benefit. The special retirement account is credited with 2% of base pay each month as well as interest based on the 30-year Treasury bond rate set annu-
ally (2.88% in 2013). The special retirement account can be paid in a lump sum or paid in the form of an annuity benefit.
A participant becomes vested in his or her benefit after completing three years of service. A vested participant who terminates employment before age 55 can start receiving benefit payments calculated using terminated vested reduction factors at any time after attaining age 55. If payments begin before age 65, then the following reduction factors for the portion of the benefits earned after 2000 apply: age 64 – 9%; age 63 – 16%; age 62 – 23%; age 61 – 30%; age 60 – 35%; age 59 – 40%; age 58 – 44%; age 57 – 48%; age 56 – 52%; and age 55 – 55%.
The IRC limits the amount of compensation that may be included in determining pension benefits under qualified pension plans. For 2013, the compensation limit was $255,000. The IRC also limits the total annual benefit that may be provided to a participant under a qualified defined benefit plan. For 2013, this limitation was the lesser of (i) $205,000 or (ii) the average of the participant’s compensation during the three consecutive years in which the participant had the highest aggregate compensation.
Dominion Retirement Benefit Restoration Plan
The BRP is a nonqualified defined benefit pension plan designed to make up for benefit reductions under the Dominion Pension Plan due to the limits imposed by the IRC.
A Dominion employee is eligible to participate in the BRP if (1) he or she is a member of management or a highly compensated employee, (2) his or her Dominion Pension Plan benefit is or has been limited by the IRC compensation or benefit limits, and (3) he or she has been designated as a participant by the CGN Committee. A participant remains a participant until he or she ceases to be eligible for any reason other than retirement or until his or her status as a participant is revoked by the CGN Committee.
Upon retirement, a participant’s BRP benefit is calculated using the same formula (except that the IRS salary limit is not applied) used to determine the participant’s default annuity form of benefit under the Dominion Pension Plan (single life annuity for unmarried participants and 50% joint and survivor annuity for married participants), and then subtracting the benefit the participant is entitled to receive under the Dominion Pension Plan. To accommodate the enactment of Section 409A of the IRC, the portion of a participant’s BRP benefit that had accrued as of December 31, 2004 is frozen, but the calculation of the overall restoration benefit is not changed.
The restoration benefit is generally paid in the form of a single lump sum cash payment. However, a participant may elect to receive a single life or 50% or 100% joint and survivor annuity for the portion of his or her benefit that accrued prior to 2005. For the portion of his or her benefit that accrued in 2005 or later, a participant may also elect to receive a 75% joint and survivor annuity. The lump sum calculation includes an amount approximately equivalent to the amount of taxes the participant will owe on the lump sum payment so that the participant will have sufficient funds, on an after-tax basis, to purchase an annuity contract.
A participant who terminates employment before he or she is eligible for benefits under the Dominion Pension Plan generally is not entitled to a restoration benefit. Messrs. Farrell and McGettrick have been granted age and service credits for purposes of calculating their Dominion Pension Plan and BRP benefits. Per his letter agreement, Mr. Farrell was granted 25 years of service
when he reached age 55 and will continue to accrue service as long as he remains employed. At age 60, Mr. Farrell’s benefits will be calculated based on 30 years of service, if he remains employed. Mr. McGettrick, having attained age 50, has earned benefits calculated based on five additional years of age and service. For each of these NEOs, the additional years of service count toward determining both the amount of benefits and the eligibility to receive them. For additional information regarding service credits, seeDominion Executive Supplemental Retirement Plan.
If a vested participant dies when he or she is retirement eligible (on or after age 55), the participant’s beneficiary will receive the restoration benefit in a single lump sum payment. If a participant dies while employed but before he or she has attained age 55 and the participant is married at the time of death, the participant’s spouse will receive a restoration benefit calculated in the same way (except that the IRS salary limit is not applied) as the 50% qualified pre-retirement survivor annuity payable under the Dominion Pension Plan and paid in a lump sum payment.
Dominion Executive Supplemental Retirement Plan
The Dominion ESRP is a nonqualified defined benefit plan that provides for an annual retirement benefit equal to 25% of a participant’s final cash compensation (base salary plus target annual incentive award) payable for a period of 10 years or, for certain participants designated by the CGN Committee, for the participant’s lifetime. To accommodate the enactment of Section 409A of the IRC, the portion of a participant’s ESRP benefit that had accrued as of December 31, 2004 is frozen, but the calculation of the overall benefit is not changed. Effective July 1, 2013, the ESRP is closed to any new participants.
A Dominion employee is eligible to participate in the ESRP if (1) he or she is a member of management or a highly compensated employee, and (2) he or she has been designated as a participant by the CGN Committee. A participant remains a participant until he or she ceases to be eligible for any reason other than retirement or until his or her status as a participant is revoked by the CGN Committee.
A participant is entitled to the full ESRP benefit if he or she separates from service with Dominion after reaching age 55 and achieving 60 months of service. A participant who separates from service with Dominion with at least 60 months of service but who has not yet reached age 55 is entitled to a reduced, pro-rated retirement benefit. A participant who separates from service with Dominion with fewer than 60 months of service is generally not entitled to an ESRP benefit unless the participant separated from service on account of disability or death.
The ESRP benefit is generally paid in the form of a single lump sum cash payment. However, a participant may elect to receive the portion of his or her benefit that had accrued as of December 31, 2004 in monthly installments. For any new participants, the ESRP benefit must be paid in the form of a single lump sum cash payment. The lump sum calculation includes an amount approximately equivalent to the amount of taxes the participant will owe on the lump sum payment so that the participant will have sufficient funds, on an after-tax basis, to purchase a 10-year or lifetime annuity contract.
All of the NEOs except Mr. Koonce are currently entitled to a full ESRP retirement benefit. If Mr. Koonce terminates employment before he attains age 55, he will receive a pro-rated ESRP benefit. Based on the terms of their individual letter agreements, Messrs. Farrell, McGettrick and Koonce will receive an ESRP benefit calculated as a lifetime benefit. Mr. McGettrick has earned five years of additional age and service credit for purposes of computing his retirement benefits and eligibility for benefits under the ESRP, long-term incentive grants, and retiree medical and life insurance plans as he has met the requirement of remaining employed until he attained age 50. Under his letter agreement, Mr. Christian will receive ESRP benefits calculated as a lifetime benefit provided he remains employed with Dominion until attainment of age 60. As consideration for this benefit, Mr. Christian has agreed not to compete with the company for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.
Actuarial Assumptions Used to Calculate Pension Benefits
Actuarial assumptions used to calculate Dominion Pension Plan benefits are prescribed by the terms of the Dominion Pension Plan based on the IRC and PBGC requirements. The present value of the accumulated benefit is calculated using actuarial and other factors as determined by the plan actuaries and approved by Dominion. Actuarial assumptions used for the December 31, 2013 benefit calculations shown in thePension Benefits table include a discount rate of 5.30% to determine the present value of the future benefit obligations for the Dominion Pension Plan, BRP and ESRP and a lump sum interest rate of 4.55% to estimate the lump sum values of BRP and ESRP benefits. Each NEO is assumed to retire at the earliest age at which he is projected to become eligible for full, unreduced pension benefits. For purposes of estimating future eligibility for unreduced Dominion Pension Plan and ESRP benefits, the effect of future service is considered. Each NEO is assumed to commence Dominion Pension Plan payments at the same age as BRP payments. The longevity assumption used to determine the present value of benefits is the same assumption used for financial reporting of the Dominion Pension Plan liabilities, with no assumed mortality before retirement age. Assumed mortality after retirement is based on tables from the Society of Actuaries’ RP-2000 study, projected from 2000 to a point five years beyond the calculation date (this year, to 2018) with 100% of the Scale AA factors, and further adjusted for Dominion experience by using an age set-forward factor. For BRP and ESRP benefits, other actuarial assumptions include an assumed tax rate of 42%. BRP and ESRP benefits are assumed to be paid as lump sums; Dominion Pension Plan benefits are assumed to be paid as annuities.
The discount rate for calculating lump sum BRP and ESRP payments at the time an officer terminates employment is selected by Dominion’s Administrative Benefits Committee and adjusted periodically. For year 2013, a 4.61% discount rate was used to determine the lump sum payout amounts. The discount rate for each year will be based on a rolling average of the blended rate published by the PBGC in October of the previous five years.
NONQUALIFIED DEFERRED COMPENSATION
| | | | | | | | | | | | | | Name | | Aggregate Earnings
in Last FY
(as of 12/31/2013)* | | | Aggregate
Withdrawals/
Distributions
(as of 12/31/2013) | | | Aggregate Balance
at Last FYE
(as of 12/31/2013) | | Thomas F. Farrell II | | $ | — | | | $ | — | | | $ | — | | Mark F. McGettrick | | | — | | | | — | | | | — | | David A. Christian | | | 74 | | | | — | | | | 17,824 | | Paul D. Koonce | | | 105,424 | | | | — | | | | 665,581 | | David A. Heacock | | | — | | | | — | | | | — | |
*No preferential earnings are paid and therefore no earnings from these plans are included in the Summary Compensation Table.
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
At this time, Dominion does not offer any nonqualified elective deferred compensation plans to its officers or other employees. TheNonqualified Deferred Compensation table reflects, in aggregate, the plan balances for two former plans offered to Dominion officers and other highly compensated employees: the Frozen Deferred Compensation Plan and the Frozen DSOP, which were frozen as of December 31, 2004. Although the Frozen DSOP was an option plan rather than a deferred compensation plan, Dominion is including information regarding the plan and any balances in this table to make full disclosure about possible future payments to officers under Dominion’s employee benefit plans.
Frozen Deferred Compensation Plan
The Frozen Deferred Compensation Plan includes amounts previously deferred from one of the following categories of compensation: (i) salary; (ii) bonus; (iii) vesting restricted stock; and (iv) gains from stock option exercises. The plan also provided for company contributions of lost company 401(k) Plan match contributions and transfers from several CNG deferred compensation plans. The Frozen Deferred Compensation Plan offers 28 investment funds for the plan balances, including a Dominion Resources Stock Fund. Participants may change investment elections on any business day. Any vested restricted stock and gains from stock option exercises that were deferred were automatically allocated to the Dominion Resources Stock Fund and this allocation cannot be changed. Earnings are calculated based on the performance of the underlying investment fund. The following funds had rates of returns for 2013 as follows: Dominion Resources Stock Fund, 29.8%; and Dominion Fixed Income Fund, 3.01%.
The Dominion Fixed Income Fund is an investment option that provides a fixed rate of return each year based on a formula that is tied to the adjusted federal long-term rate published by the IRS in November prior to the beginning of the year. Dominion’s Asset Management Committee determines the rate based on its estimate of the rate of return on Dominion assets in the trust for the Frozen Deferred Compensation Plan.
The default benefit commencement date is February 28 after the year in which the participant retires, but the participant may select a different benefit commencement date in accordance with the plan. Participants may change their benefit commencement date election; however, a new election must be made at least six
months before an existing benefit commencement date. Withdrawals less than six months prior to an existing benefit commencement date are subject to a 10% early withdrawal penalty. Account balances must be fully paid out no later than the February 28 that is 10 calendar years after a participant retires or becomes disabled. If a participant retires from the company, he or she may continue to defer an account balance provided that the total balance is distributed by this deadline. In the event of termination of employment for reasons other than death, disability or retirement before an elected benefit commencement date, benefit payments will be distributed in a lump sum as soon as administratively practicable. Hardship distributions, prior to an elected benefit commencement date, are available under certain limited circumstances.
Participants may elect to have their benefit paid in a lump sum payment or equal annual installments over a period of whole years from one to 10 years. Participants have the ability to change their distribution schedule for benefits under the plan by giving six months’ notice to the plan administrator. Once a participant begins receiving annual installment payments, the participant can make a one-time election to either (1) receive the remaining account balance in the form of a lump sum distribution or (2) change the remaining installment payment period. Any election must be approved by the company before it is effective. All distributions are made in cash with the exception of the Deferred Restricted Stock Account and the Deferred Stock Option Account, which are distributed in the form of Dominion common stock.
Frozen DSOP
The Frozen DSOP enabled employees to defer all or a portion of their salary and bonus and receive options on various mutual funds. Participants also received lost company match contributions to the 401(k) Plan in the form of options under this plan. DSOP options can be exercised at any time before their expiration date. On exercise, the participant receives the excess of the value, if any, of the underlying mutual funds over the strike price. The participant can currently choose among options on 27 mutual funds, and there is not a Dominion stock alternative or a fixed income fund. Participants may change options among the mutual funds on any business day. Benefits grow/decline based on the total return of the mutual funds selected. Any options that expire do not have any value. Options expire under the following terms:
Ÿ | | Options expire on the last day of the 120th month after retirement or disability;
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Ÿ | | Options expire on the last day of the 24th month after the participant’s death (while employed);
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Ÿ | | Options expire on the last day of the 12th month after the participant’s severance;
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Ÿ | | Options expire on the 90th day after termination with cause; and
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Ÿ | | Options expire on the last day of the 120th month after severance following a change in control.
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The NEOs that are participants in the Frozen DSOP held options on the publicly available mutual fund, Vanguard Short-Term Bond Index, which had a rate of return for 2013 of 0.07%.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGEIN CONTROL
Under certain circumstances, the company provides benefits to eligible employees upon termination of employment, including a termination of employment involving a change in control of the company, that are in addition to termination benefits for other employees in the same situation.
Change in Control
As discussed in theEmployee and Executive Benefits section of the CD&A, Dominion has entered into an Employment Continuity Agreement with each of its officers, including the NEOs. Each agreement has a three-year term and is automatically extended annually for an additional year, unless cancelled by Dominion.
Employment Continuity Agreements require two triggers for the payment of most benefits:
Ÿ | | There must be a change in control; and
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Ÿ | | The executive must either be terminated without cause, or terminate his or her employment with the surviving company after a constructive termination. Constructive termination means the executive’s salary, incentive compensation or job responsibility is reduced after a change in control or the executive’s work location is relocated more than 50 miles without his or her consent.
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For purposes of the Employment Continuity Agreements, a change in control will occur if (i) any person or group becomes a beneficial owner of 20% or more of the combined voting power of Dominion voting stock or (ii) as a direct or indirect result of, or in connection with, a cash tender or exchange offer, merger or other business combination, sale of assets, or contested election, the directors constituting the Dominion Board of Directors before any such transaction cease to represent a majority of Dominion’s or its successor’s Board within two years after the last of such transactions.
If an executive’s employment following a change in control is terminated without cause or due to a constructive termination, the executive will become entitled to the following termination benefits:
Ÿ | | Lump sum severance payment equal to three times base salary plus AIP award (determined as the greater of (i) the target annual award for the current year or (ii) the highest actual AIP payout for any one of the three years preceding the year in which the change in control occurs).
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Ÿ | | Full vesting of benefits under ESRP and BRP with five years of additional credited age and five years of additional credited service from the change in control date.
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Ÿ | | Group-term life insurance. If the officer elects to convert group-term insurance to an individual policy, the company pays the premiums for 12 months.
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Ÿ | | Executive life insurance. Premium payments will continue to be paid by the company until the earlier of: (1) the fifth anniversary of the termination date, or (2) the later of the 10th anniversary of the policy or the date the officer attains age 64.
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Ÿ | | Retiree medical coverage will be determined under the relevant plan with additional age and service credited as provided under an officer’s letter agreement (if any) and including five additional years credited to age and five additional years credited to service.
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Ÿ | | Outplacement services for one year (up to $25,000).
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Ÿ | | If any payments are classified as excess parachute payments for purposes of Section 280G of the IRC and the executive incurs the excise tax, the company will pay the executive an amount equal to the 280G excise tax plus a gross-up multiple.
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In January 2013, the CGN Committee approved the elimination of the excise tax gross up provision included in the Employment Continuity Agreement for any new officer elected after February 1, 2013.
The terms of awards made under the LTIP, rather than the terms of Employment Continuity Agreements, will determine the vesting of each award in the event of a change in control. These provisions are described in theLong-Term Incentive Program section of the CD&A and footnotes to theGrants of Plan-Based Awards table.
Other Post Employment Benefit for Mr. Farrell
Mr. Farrell will become entitled to a payment of one times salary upon his retirement as consideration for his agreement not to compete with the company for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.
The following table provides the incremental payments that would be earned by each NEO if his employment had been terminated, or constructively terminated, as of December 31, 2013. These benefits are in addition to retirement benefits that would be payable on any termination of employment. Please refer to thePension Benefits table for information related to the present value of accumulated retirement benefits payable to the NEOs.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Name | | Non-Qualified
Plan Payment | | | Restricted
Stock(1) | | | Performance
Grant(1) | | | Non-Compete
Payments(2) | | | Severance
Payments | | | Retiree Medical
and Executive
Life Insurance(3) | | Outplacement
Services | | | Excise Tax &
Tax Gross-Up | | | Total | | Thomas F. Farrell II(4) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Retirement | | | $— | | | $ | 3,040,477 | | | $ | 645,795 | | | $ | 435,721 | | | | $— | | | $— | | | $— | | | | $— | | | $ | 4,121,993 | | Death / Disability | | | — | | | | 4,484,824 | | | | 645,795 | | | | — | | | | — | | | — | | | — | | | | — | | | | 5,130,619 | | Change in Control(5) | | | 336,818 | | | | 3,131,991 | | | | 704,505 | | | | — | | | | 3,207,734 | | | — | | | 8,038 | | | | — | | | | 7,389,086 | | Mark F. McGettrick(4) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Retirement | | | — | | | | 1,346,540 | | | | 274,509 | | | | — | | | | — | | | — | | | — | | | | — | | | | 1,621,049 | | Death / Disability | | | — | | | | 1,917,084 | | | | 274,509 | | | | — | | | | — | | | — | | | — | | | | — | | | | 2,191,593 | | Change in Control(5) | | | — | | | | 2,318,076 | | | | 299,464 | | | | — | | | | 2,342,891 | | | — | | | 12,278 | | | | — | | | | 4,972,709 | | David A. Christian(4) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Retirement | | | — | | | | 977,290 | | | | 210,061 | | | | — | | | | — | | | — | | | — | | | | — | | | | 1,187,351 | | Death / Disability | | | — | | | | 1,397,392 | | | | 210,061 | | | | — | | | | — | | | — | | | — | | | | — | | | | 1,607,453 | | Change in Control(5) | | | 138,649 | | | | 1,726,691 | | | | 229,157 | | | | — | | | | 2,271,402 | | | — | | | 15,068 | | | | 1,806,233 | | | | 6,187,200 | | Paul D. Koonce | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Termination Without Cause | | | — | | | | 645,368 | | | | 140,494 | | | | — | | | | — | | | — | | | — | | | | — | | | | 785,862 | | Voluntary Termination | | | — | | | | — | | | | — | | | | — | | | | — | | | — | | | — | | | | — | | | | — | | Termination With Cause | | | — | | | | — | | | | — | | | | — | | | | — | | | — | | | — | | | | — | | | | — | | Death / Disability | | | — | | | | 926,343 | | | | 140,494 | | | | — | | | | — | | | — | | | — | | | | — | | | | 1,066,837 | | Change in Control(5) | | | 1,112,408 | | | | 1,150,184 | | | | 153,265 | | | | — | | | | 1,442,855 | | | 35,977 | | | 10,078 | | | | 1,725,712 | | | | 5,630,479 | | David A. Heacock(4) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Retirement | | | — | | | | 351,932 | | | | 74,752 | | | | — | | | | — | | | — | | | — | | | | — | | | | 426,684 | | Change in Control(5) | | | 715,138 | | | | 195,413 | | | | 81,548 | | | | — | | | | 1,259,576 | | | 68,617 | | | 13,025 | | | | 1,032,354 | | | | 3,365,671 | |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.
(1) | Grants made in 2011, 2012 and 2013 under the LTIP vest pro rata upon termination without cause, death or disability. These grants vest pro rata upon retirement provided the CEO (or in the case of the CEO, the CGN Committee) does not determine the NEO’s retirement is detrimental to Dominion; amounts shown assume this determination was made. However, the December 2010 restricted stock award issued to Mr. Farrell and the December 2012 restricted stock awards issued to Messrs. McGettrick, Christian and Koonce do not vest prorated if the executive is terminated or leaves for any reason other than following change of control, death or disability. The amounts shown in the restricted stock column are based on the closing stock price of $64.69 on December 31, 2013.
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(2) | Pursuant to a letter agreement dated February 28, 2003, Mr. Farrell will be entitled to a special payment of one times salary upon retirement in exchange for a two-year non-compete agreement. Mr. Farrell would not be entitled to this non-compete payment in the event of his death.
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(3) | Amounts in this column represent the value of the annual incremental benefit the NEOs would receive for executive life insurance and retiree medical coverage. Mr. McGettrick is eligible for retiree medical and executive life insurance upon any termination due to his letter agreement. Messrs. Farrell and Christian are entitled to executive life insurance coverage and retiree medical benefit upon any termination since they are retirement eligible and have completed 10 years of service. Mr. Koonce is eligible for retiree medical and executive life insurance upon a change in control. Mr. Heacock is eligible for retiree medical upon a change in control.
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(4) | For the NEOs who are eligible for retirement (Messrs. Farrell, McGettrick, Christian and Heacock), this table assumes they would retire in connection with any termination event.
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(5) | Change in control amounts assume that a change in control and a termination or constructive termination takes place on December 31, 2013. The amounts indicated upon a change in control are the incremental amounts attributable to five years of additional age and service credited pursuant to the Employment Continuity Agreements that each NEO would receive over the amounts payable upon a retirement (Messrs. Farrell, McGettrick, Christian and Heacock) or termination without cause (Mr. Koonce). The restricted stock and performance grant amounts represent the value of the awards upon a change in control that is above what would be received upon a retirement or termination without cause.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters DOMINION The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the headingsShare Ownership-Director and Officer Share Ownership andSignificant Shareholders in the 20142015 Proxy Statement is incorporated by reference. The information regarding equity securities of Dominion that are authorized for issuance under its equity compensation plans contained under the headingExecutive Compensation-Equity Compensation Plans in the 20142015 Proxy Statement is incorporated by reference. VIRGINIA POWER
The table below sets forth as of February 15, 2014, the number of shares of Dominion common stock owned by directors and executive officers of Virginia Power named on the Summary Compensation Table. Dominion owns all of the outstanding common stock of Virginia Power. None of the executive officers or directors own any of the outstanding preferred stock of Virginia Power.
| | | | | | | | | | | | | Name of Beneficial Owner | | Shares | | | Restricted
Shares | | | Total(1) | | Thomas F. Farrell II | | | 666,908 | | | | 321,415 | | | | 988,323 | | Mark F. McGettrick | | | 189,925 | | | | 109,594 | | | | 299,519 | | Paul D. Koonce | | | 75,733 | | | | 66,669 | | | | 142,402 | | David A. Christian | | | 64,765 | | | | 67,165 | | | | 131,930 | | David A. Heacock | | | 28,487 | | | | 15,652 | | | | 44,139 | | Mark O. Webb | | | 5,681 | | | | 3,430 | | | | 9,111 | | All directors and executive officers as a group (8 persons)(2) | | | 1,084,562 | | | | 603,649 | | | | 1,688,211 | |
(1) | Includes shares as to which voting and/or investment power is shared with or controlled by another person as follows: Mr. Farrell, 20,000 (shares held jointly); Mr. Webb, 409 (shares held jointly) and 90 (shares held by spouse); all directors and executive officers as a group, 44,458. |
(2) | Neither any individual director or executive officer, nor all of the directors and executive officers as a group, own more than 1% of Dominion common shares outstanding as of February 15, 2014. |
Item 13. Certain Relationships and Related Transactions, and Director Independence DOMINION The information regarding related party transactions required by this item found under the headingRelated Party Transactions, and information regarding director independence found under the headingDirector Independence, in the 20142015 Proxy Statement is incorporated by reference. VIRGINIA POWER
Related Party Transactions
Virginia Power’s Board of Directors has adopted the Related Party Guidelines also approved by Dominion’s Board of Direc-
tors. These guidelines were adopted for the purpose of identifying potential conflicts of interest arising out of financial transactions, arrangements and relations between Virginia Power and any related persons. Under the guidelines, a related person is a director, executive officer, director nominee, a beneficial owner of more than 5% of Dominion’s common stock, or any immediate family member of one of the foregoing persons. A related party transaction is any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships in excess of $120,000 in which Virginia Power (and/or any of its consolidated subsidiaries) is a party and in which the related person has or will have a direct or indirect material interest.
In determining whether a direct or indirect interest is material, the significance of the information to investors in light of all circumstances is considered. The importance of the interest to the person having the interest, the relationship of the parties to the transaction with each other and the amount involved are also among the factors considered in determining the significance of the information to the investors.
Dominion’s CGN Committee has reviewed certain categories of transactions and determined that transactions between Dominion and a related person that fall within such categories will not result in the related person receiving a direct or indirect material interest. Under the guidelines, such transactions are not deemed related party transactions and therefore not subject to review by the CGN Committee. The categories of excluded transactions include, among other items, compensation and expense reimbursement paid to directors and executive officers in the ordinary course of performing their duties; transactions with other companies where the related party’s only relationship is as an employee, if the aggregate amount involved does not exceed the greater of $1 million or 2% of that company’s gross revenues; and charitable contributions which are less than the greater of $1 million or 2% of the charity’s annual receipts. The full text of the guidelines can be found on Dominion’s website at http://www.dom.com/investors/corporate-governance/pdf/related_party_guidelines.pdf.
Virginia Power collects information about potential related party transactions in its annual questionnaires completed by directors and executive officers. Management reviews the potential related party transactions and assesses whether any of the identified transactions constitute a related party transaction. Any identified related party transactions are then reported to Dominion’s CGN Committee. Dominion’s CGN Committee reviews and considers relevant facts and circumstances and determines whether to ratify or approve the related party transactions identified. Dominion’s CGN Committee may only approve or ratify related party transactions that are in, or are not inconsistent with, the best interests of Dominion and its shareholders and are in compliance with Virginia Power’s Code of Ethics.
Since January 1, 2013, there have been no related party transactions involving Virginia Power that were required either to be approved under Virginia Power’s policies or reported under the SEC related party transactions rules.
Director Independence
Under NYSE listing standards, Messrs. Farrell, McGettrick and Webb are not independent as they were executive officers of Virginia Power and its parent company, Dominion. All of Virginia Power’s outstanding common stock is owned by Dominion and therefore, Virginia Power is a “controlled” company under the rules of the NYSE. Because Virginia Power meets the definition of a “controlled company” and has only preferred stock listed on the NYSE, it is exempt under Section 303A of the NYSE Rules from the provisions relating to board committees and the requirement to have a majority of its board be independent.
Item 14. Principal Accountant Fees and Services DOMINION The information concerning principal accountant fees and services contained under the headingAuditors-Fees and Pre-Approval Policy in the 20142015 Proxy Statement is incorporated by reference.
VIRGINIA POWERAND DOMINION GAS The following table presents fees paid to Deloitte & Touche LLP for services related to Virginia Power and Dominion Gas for the fiscal years ended December 31, 20132014 and 2012.2013. | | | | | | | | | | Type of Fees | | 2013 | | | 2012 | | | (millions) | | | | | | | Audit fees | | $ | 1.89 | | | $ | 1.79 | | Audit-related fees | | | 0.02 | | | | — | | Tax fees | | | — | | | | — | | All other fees | | | — | | | | — | | | | | $ | 1.91 | | | $ | 1.79 | |
| | | | | | | | | | Type of Fees | | 2014 | | | 2013 | | | (millions) | | | | | | | Virginia Power | | | | | | | | | Audit fees | | $ | 1.96 | �� | | $ | 1.89 | | Audit-related fees | | | — | | | | 0.02 | | Tax fees | | | — | | | | — | | All other fees | | | — | | | | — | | Total fees | | $ | 1.96 | | | $ | 1.91 | | Dominion Gas | | | | | | | | | Audit fees | | $ | 0.52 | | | $ | — | | Audit-related fees | | | 0.14 | | | | — | | Tax fees | | | — | | | | — | | All other fees | | | — | | | | — | | Total fees | | $ | 0.66 | | | $ | — | | | | | | | | | | | |
Audit Fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power’s and Dominion Gas’ annual consolidated financial statements, the review of financial statements included in Virginia Power’s and Dominion Gas’ quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC. Audit-Related Fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Virginia Power’s and Dominion Gas’ consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and attest services not required by statutesstatute or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions. Virginia Power’s Boardand Dominion Gas’ Boards of Directors hashave adopted the Dominion Audit Committee pre-approval policy for itstheir independent auditor’s services and fees and hashave delegated the execution of this policy to the Dominion Audit Committee. In accordance with this delegation, each year the Dominion Audit Committee pre-approves a schedule that details the services to be provided for the following year and an estimated charge for such services. At its December 2013January 2015 meeting, the Dominion Audit Committee approved Virginia Power’s scheduleand Dominion Gas’ schedules of services and fees for 2014.2015. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Audit Committee or a member of the Dominion Audit Committee. The audit fees for Dominion Gas presented above for the year ended December 31, 2014, were for professional services rendered during the period subsequent to Dominion Gas becoming an SEC registrant. Total audit fees and audit-related fees incurred prior to Dominion Gas becoming an SEC registrant were $680 thousand and $70 thousand, respectively, and were paid by Dominion.
Part IV Item 15. Exhibits and Financial Statement Schedules (a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted. 1. Financial Statements See Index on page 57.56. 2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes. 3. Exhibits (incorporated by reference unless otherwise noted) | | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | | 2 | | Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1,Form 8-K filed March 15, 2010, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 3.1.a | | Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 3.1.b | | Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on March 3, 2011October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, FileNo. 1-2255). | | | | | | | X | | | | | | | | | | | | 3.1.c | | Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 29, 2011,4, 2014, File No. 1-2255)333-195066). | | | | | | | | | | | X | | | | | | | | 3.2.a | | Dominion Resources, Inc. Amended and Restated Bylaws, effective May 3, 2013 (Exhibit 3.1, Form 8-K filed May 3, 2013, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 3.2.b | | Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255). | | | | | | | X | | | | | | | | | | | | 3.2.c | | Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066). | | | | | | | | | | | X | | | | | | | | 4 | | Dominion Resources, Inc. and, Virginia Electric and Power Company and Dominion Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets. | | | X | | | | X | | | | X | | | | | | | | 4.1.a | | See Exhibit 3.1.a above. | | | X | | | | | | | | | | | | | | | | 4.1.b | | See Exhibit 3.1.b above. | | | | | | | X | | | | | | | | | | | | 4.2 | | Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indenture (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); Ninety-Second Supplemental Indenture, dated as of July 1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255). | | | X | | | | X | | | | | | | | | | | | 4.3 | | Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of FirstTenth Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and(Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of EleventhTwelfth Supplemental Indenture, dated DecemberJanuary 1, 20032006 (Exhibit 4.2, Form 8-K filed December 11, 2003,January 12, 2006, File No. 1-2255); FormsForm of Twelfth and Thirteenth Supplemental Indentures,Indenture, dated as of January 1, 2006 (Exhibits 4.2 and(Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); FormsForm of Sixteenth and Seventeenth Supplemental Indentures,Indenture, dated November 1, 2007 (Exhibits 4.2 and(Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed | | | X | | | | X | |
| | | | | | | | | Exhibit
Number
| | Description
| | Dominion | | | Virginia
Power | | | | | | | November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-FirstTwenty- | | | X | | | | X | | | | | |
| | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | Dominion
Gas | | | | | | | | First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No.1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, FileNo. 1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No.1-2255). | | | | | | | | | | | | | | | 4.4 | | Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a FirstForm of Second Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement filed April 22, 1998, File No. 333-50653); Forms of Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits(Exhibit 4.6, and 4.13, Form 8-K filed January 12, 2001, File No. 1-8489). | | | X | | | | | | | | 4.5 | | Indenture, dated May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012); Fifteenth Supplemental Indenture, dated October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651); Seventeenth Supplemental Indenture, dated August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Eighteenth Supplemental Indenture, dated December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Nineteenth Supplemental Indenture, dated January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Twentieth Supplemental Indenture, dated March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-3196); Twenty-First Supplemental Indenture, dated June 27, 2007 (Exhibit 4.2, Form 8-K filed July 3, 2007, File No. 1-8489). | | | X | | | | | | | | | 4.64.5 | | Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2, Form 8-A filed April 21, 1995, File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8%8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2, Form 8-A filed December 12, 1996, File No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008)2026); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2, Form 8-A filed October 22, 1998, File No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004); Second Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.4, Form 8-K filed July 3, 2007, File No. 1-8489). | | | X | | | | | | | | | | | 4.74.6 | | Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of FirstSixteenth Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K filed June 22, 2000, File No. 1-8489); Forms of Second and Third Supplemental Indentures, dated July 1, 2000 (Exhibits 4.2 and 4.3, Form 8-K filed July 11, 2000, File No. 1-8489); Fourth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.2, Form 8-K filed September 8, 2000, File No. 1-8489); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K filed September 11, 2000, File No. 1-8489); | | | X | | | |
| | | | | | | | | Exhibit
Number
| | Description
| | Dominion | | | Virginia
Power | | | | | | | Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and(Exhibit 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); FormsForm of Seventeenth and Eighteenth Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489; Forms of Twentieth and Twenty-First Supplemental Indentures,Indenture, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-ThirdTwenty-Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits(Exhibit 4.2, and 4.3, Form 8-K filed January 14, 2004, FileNo. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No.333-120339); Forms Form of Twenty-Eighth and Twenty-Ninth Supplemental Indentures,Indenture, dated June 1, 2005 (Exhibits 4.2 and(Exhibit 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-FirstThirty-Second Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits(Exhibit 4.2, and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29,30, 2007, File No. 1-8489); Forms of Thirty-Fifth Thirty-Sixth and Thirty-SeventhThirty-Sixth Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2 4.3 and 4.4,4.3, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, FileNo. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011 (Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K, filed March 7, 2011, File No. 1- 8489)1-8489); Forty- ThirdForty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3,Form 8-K, filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 15, 2011, File No.1-8489); Forty-Fifth | | | X | | | | | |
| | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | Dominion
Gas | | | | | | | | Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No.1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Eighth Supplemental Indenture, dated March 1, 2014 (Exhibit 4.3, Form 8-K, filed March 24, 2014, File No. 1-8489); Forty-Ninth Supplemental Indenture, dated November 1, 2014 (Exhibit 4.3, Form 8-K, filed November 25, 2014, File No. 1-8489); Fiftieth Supplemental Indenture, dated November 1, 2014 (Exhibit 4.4, Form 8-K, filed November 25, 2014, File No. 1-8489); Fifty-First Supplemental Indenture, dated November 1, 2014 (Exhibit 4.5, Form 8-K, filed November 25, 2014, File No. 1-8489). | | | | | | | | | | | | | | 4.84.7 | | Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K filed April 12, 2001, File No. 1-3196); Forms of Second and Third Supplemental Indentures, dated October 25, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed October 23, 2001, File No. 1-3196); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K filed May 22, 2002, File No. 1-3196); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196); Seventh Supplemental Indenture, dated June 27, 2007 (Exhibit 4.6, Form 8-K filed July 3, 2007, File No. 1-8489). | | | X | | | | | |
| | | | | | | | | | | Exhibit
Number
| | Description
| | Dominion | | | Virginia
Power | | 4.9 | | Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, FileNo. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489); Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2014, File No. 1-8489). | | | X | | | | | | | | | | | 4.104.9 | | Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, FileNo. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489). | | | X | | | | | | | | | | | 4.114.10 | | Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No.1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No.1-8489). | | | X | | | | | | | | | | | 4.124.11 | | Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated July 18, 2014 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2014 filed July 30, 2014, File No. 1-8489). | | | X | | | | | | | | | | | 4.134.12 | | Series A Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.7, Form 8-K filed June 7, 2013, File No.1-8489). | | | X | | | | | | | | | | | 4.144.13 | | Series B Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.8, Form 8-K filed June 7, 2013, File No.1-8489). | | | X | | | | | |
| | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | | | | | | | 4.14 | | 2014 Series A Purchase Contract and Pledge Agreement, dated as of July 1, 2014, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.5, Form 8-K filed July 1, 2014, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 4.15 | | Indenture, dated as of October 1, 2013, between Dominion Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form S-4 filed April 4, 2014, File No. 333-195066); First Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.2, Form S-4 filed April 4, 2014, File No. 333-195066); Second Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.3, Form S-4 filed April 4, 2014, File No. 333-195066); Third Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.4, Form S-4 filed April 4, 2014, File No. 333-195066); Fourth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.2, Form 8-K filed December 8, 2014, File No. 333-195066); Fifth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.3, Form 8-K filed December 8, 2014, File No. 333-195066); Sixth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.4, Form 8-K filed December 8, 2014, File No. 333-195066). | | | X | | | | | | | | X | | | | | | | | 10.1 | | DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 10.2 | | DRS Services Agreement, dated as of January 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255). | | | | | | | X | | | | | | | | | | | | 10.3 | | Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489). | | | X | | | | X | | | | | | | | | | | | 10.4 | | $3.0 billion Three-Year4,000,000,000 Five-Year Amended and Restated Revolving Credit Agreement, dated September 24, 2010May 19, 2014, among Dominion Resources, Inc., Virginia Electric and Power Company, JP MorganDominion Gas Holdings, LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, The Royal Bank of Scotland plc, Bank of America, N.A., Barclays Capital, The Royal Bank of Scotland plc,PLC and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein.therein (Exhibit 10.1, Form 8-K filed September 28, 2010, File No. 1-8489), as amended October 1, 2011 (Exhibit 10.1, Form 8-K filed October 3, 2011,May 19, 2014, File No. 1-8489 and File No. 1-2255). | | | X | | | | X | | | | X | | | | | | | | 10.5 | | $500 million Three-Year500,000,000 Five-Year Amended and Restated Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, Keybank National Association, as Administrative Agent, Bayerische Landesbank, New York Branch, and U.S. Bank National Association, as Syndication Agents,Agent, and other lenders named therein.therein (Exhibit 10.2,10.1, Form 8-K filed September 28, 2010,June 2, 2014, File No.1-8489) , as amended October 1, 2011 (Exhibit 10.2, Form 8-K filed October 3, 2011, File No. 1-8489 and File No. 1-2255). | | | X | | | | X | | | | X | | | | | | | | 10.6 | | Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West | | | X | | | | X | |
| | | | | | | | | | | Exhibit
Number
| | Description
| | Dominion | | | Virginia
Power | | | | | | | | Virginia and Virginia Electric and Power Company (Exhibit 10,Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003, File No. 1-8489 and File No. 1-2255). | | | X | | | | X | | | | | | | | | | | | 10.7* | | Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, FileNo. 1-8489), as amended September 26, 2014 (Exhibit 10.1, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). | | | X | | | | X | | | | X | | | | | | | | 10.8* | | Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | | 10.9* | | Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company dated January 24, 2013 (effective for certain officers elected subsequent to February 1, 2013) (filed herewith)(Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2013 filed February 27, 2014, File No. 1-8489 and File No. 1-2255). | | | X | | | | X | | | | X | |
| | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | | | | | | | 10.10* | | Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489), as amended September 26, 2014 (Exhibit 10.2, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). | | | X | | | | X | | | | X | | | | | | | | 10.11* | | Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | | 10.12* | | Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489), as amended and restated effective July 1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013 filed August 6, 2013 File No. 1-8489), as amended September 26, 2014 (Exhibit 10.3, Form10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). | | | X | | | | X | | | | X | | | | | | | | 10.13* | | Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255), as amended September 26, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). | | | X | | | | X | | | | X | | | | | | | | 10.14* | | Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 10.15* | | Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No.1-8489). | | | X | | | | | | | | | | | | | | | | 10.16* | | Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 10.17* | | Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 10.18* | | Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011May 7, 2014 (Exhibit 10.22,10.4, Form 10-K10-Q for the fiscal quarter ended June 30, 2014 filed February 28, 2011,July 30, 2014, File No. 1-8489)1-8489 and File No. 1-2250). | | | X | | | | X | | | | X | | | | | | | | 10.19* | | Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No.1-8489). | | | X | | | | X | | | | X | | | | | | | | 10.20* | | Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No.1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No.1-8489). | | | X | | | | | |
| | | | | | | | | | | Exhibit
Number
| | Description
| | Dominion | | | Virginia
Power | | | 10.21* | | Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | | 10.22* | | Supplemental Retirement Agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255). | | | X | | | | X | | | | X | |
| | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | | | | | | | 10.23* | | Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255). | | | X | | | | X | | | | X | | | | | | | | 10.24* | | Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255). | | | X | | | | X | | | | | | 10.25* | | 2009 Performance Grant Plan under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.1, Form 8-K filed January 29, 2009, File No. 1-8489). | | | X | | | | X | | | | | | | 10.26*10.25* | | Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.27*10.26* | | Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective December 20, 2011 (Exhibit 10.32, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255). | | | X | | | | X | | | | X | | | | | | | 10.28*10.27* | | 2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.29*10.28* | | Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.30*10.29* | | Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.31*10.30* | | 2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.32*10.31* | | Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.33*10.32* | | Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.34*10.33* | | 2012 Performance Grant Plan under the 2012 Long-Term Incentive Program approved January 19, 2012 (Exhibit 10.1, Form 8-K filed January 20, 2012, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.35*10.34* | | Form of Restricted Stock Award Agreement under the 2012 Long-term Incentive Program approved January 19, 2012 (Exhibit 10.2, Form 8-K filed January 20, 2012, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.36*10.35* | | 2013 Performance Grant Plan under 2013 Long-Term Incentive Program approved January 24, 2013 (Exhibit 10.1, Form 8-K filed January 25, 2013, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.37*10.36* | | Form of Restricted Stock Award Agreement under the 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.2, Form 8-K filed January 25, 2013, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.38*10.37* | | Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010 (Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.39*10.38* | | Retirement Agreement, dated as of June 20, 2013, between Dominion Resources, Inc. and Gary L. Sypolt (Exhibit 10.1, Form 8-K filed June 24, 2013, File No. 1-8489). | | | X | | | | | | | | | | | | | | | 10.40*10.39* | | 2014 Performance Grant Plan under 2014 Long-Term Incentive Program approved January 16, 2014 (filed herewith)(Exhibit 10.40, Form 10-K for the fiscal year ended December 31, 2013, FileNo. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.41*10.40* | | Form of Restricted Stock Award Agreement under the 2014 Long-term Incentive Program approved January 16, 2014 (filed herewith)(Exhibit 10.41, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | | 10.41* | | Form of Special Performance Grant for Thomas F. Farrell II and Mark F. McGettrick approved January 16, 2014 (Exhibit 10.42, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489). | | | X | | | | X | | | | X | |
| | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | | | | | | | 10.42* | | Form of Special2015 Performance Grant for Thomas F. Farrell II and Mark F. McGettrickPlan under 2015 Long-Term Incentive Program approved January 16, 201422, 2015 (filed herewith). | | | X | | | | X | | | | X | | | | | | | | 10.43* | | Form of Restricted Stock Award Agreement under the 2015 Long-term Incentive Program approved January 22, 2015 (filed herewith). | | | X | | | | X | | | | X | | | | | | | | 10.44* | | Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith). | | | X | | | | | | | | | | | | | | | 10.44*10.45* | | Non-employee directors’ annual compensation for Dominion Resources, Inc. (filed herewith). | | | X | | | | | | | | | | | | | | | | 10.46* | | Dominion Resources, Inc. 2014 Incentive Compensation Plan, effective May 7, 2014 (Exhibit 10.1, Form 8-K filed May 7, 2014, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | | 10.47 | | Registration Rights Agreement, dated as of October 22, 2013, by and among Dominion Gas Holdings, LLC and RBC Capital Markets, LLC, RBS Securities Inc. and Scotia Capital (USA) Inc., as the initial purchasers of the Notes (Exhibit 10.1, Form S-4 filed April 4, 2014, File No. 333-195066). | | | | | | | | | | | X | | | | | | | | 10.48 | | Inter-Company Credit Agreement, dated October 17, 2013, between Dominion Resources, Inc. and Dominion Gas Holdings, LLC (Exhibit 10.2, Form S-4 filed April 4, 2014, FileNo. 333-195066). | | | X | | | | | | | | X | | | | | | | | 10.49 | | DRS Services Agreement, dated September 12, 2013, between Dominion Gas Holdings, LLC and Dominion Resources Services, Inc. (Exhibit 10.3, Form S-4 filed April 4, 2014, File No. 333-195066). | | | | | | | | | | | X | | | | | | | | 10.50 | | DRS Services Agreement, dated January 1, 2003, between Dominion Transmission Inc. and Dominion Resources Services, Inc. (Exhibit 10.4, Form S-4 filed April 4, 2014, FileNo. 333-195066). | | | | | | | | | | | X | | | | | | | | 10.51 | | DRS Services Agreement, dated January 1, 2003, between The East Ohio Company and Dominion Resources Services, Inc. (Exhibit 10.5, Form S-4 filed April 4, 2014, File No. 333-195066). | | | | | | | | | | | X | | | | | | | | 10.52 | | DRS Services Agreement, dated January 1, 2003, between Dominion Iroquois, Inc. and Dominion Resources Services, Inc. (Exhibit 10.6, Form S-4 filed April 4, 2014, File No. 333-195066). | | | | | | | | | | | X | | | | | | | | 12.a | | Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith). | | | X | | | | | | | | | | | | | | | | 12.b | | Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith). | | | | | | | X | | | | | | | | | | | | 12.c | | Ratio of earnings to fixed charges and dividends for Virginia Electric and Power CompanyDominion Gas Holdings, LLC (filed herewith). | | | | | | | | | | | X | | | | | | | | 21 | | Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith). | | | X | | | | X | | | | | | | | | | | | 23 | | Consent of Deloitte & Touche LLP (filed herewith). | | | X | | | | X | | | | X | | | | | | | | 31.a | | Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | X | | | | | | | | | | | | | | | | 31.b | | Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | X | | | | | | | | | | | | | | | | 31.c | | Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | | | | | X | | | | | | | | | | | | 31.d | | Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | | | | | X | | | | | | | | | | | | 31.e | | Certification by Chief Executive Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | | | | | | | | | X | | | | | | | | 31.f | | Certification by Chief Financial Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | | | | | | | | | X | | | | | | | | 32.a | | Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). | | | X | | | | | | | | | |
| | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | | | | | | | 32.b | | Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). | | | | | | | X | | | | | | | | | | | 99.132.c | | Towers Watson Energy Services Survey participants (filedCertification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). | | | | | | | | | | | X | | | | | | | | 101 | | The following financial statements from Dominion Resources, Inc. and, Virginia Electric and Power Company and Dominion Gas Holdings, LLC Annual Report on Form 10-K for the year ended December 31, 2013,2014, filed on February 27, 2014,2015, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. | | | X | | | | X | | | | X | |
| * | Indicates management contract or compensatory plan or arrangement |
Signatures DOMINION Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | DOMINION RESOURCES, INC. | | | | By: | | /s/ Thomas F. Farrell II | | | (Thomas F. Farrell II, Chairman, President and Chief Executive Officer) |
Date: February 27, 20142015 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 27th day of February, 2014.2015. | | | | Signature | | Title | | | /s/ Thomas F. Farrell II Thomas F. Farrell II | | Chairman of the Board of Directors, President and Chief Executive Officer | | | /s/ William P. Barr William P. Barr | | Director | | | /s/ Peter W. Brown Peter W. Brown | | Director | | | /s/ Helen E. Dragas Helen E. Dragas | | Director | | | /s/ James O. Ellis, Jr. James O. Ellis, Jr. | | Director | | | /s/ John W. Harris John W. Harris | | Director | | | /s/ Robert S. Jepson, Jr.
Robert S. Jepson, Jr.
| | Director | | | /s/ Mark J. Kington Mark J. Kington | | Director | | | /s/ Pamela J. Royal Pamela J. Royal | | Director | | | /s/ Robert H. Spilman, Jr. Robert H. Spilman, Jr. | | Director | | | /s/ Michael E. Szymanczyk Michael E. Szymanczyk | | Director | | | /s/ David A. Wollard David A. Wollard | | Director | | | /s/ Mark F. McGettrick Mark F. McGettrick | | Executive Vice President and Chief Financial Officer | | | /s/ Ashwini SawhneyMichele L. Cardiff Ashwini SawhneyMichele L. Cardiff
| | Vice President, Controller and Chief Accounting Officer |
VIRGINIA POWERVirginia Power
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | VIRGINIA ELECTRIC AND POWER COMPANY | | | | By: | | /S/ THOMAS F. FARRELL II | | | (Thomas F. Farrell II, Chairman of the Board of Directors and Chief Executive Officer) |
Date: February 27, 2015 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 27th day of February, 2015. | | | | Signature | | Title | | | /s/ Thomas F. Farrell II Thomas F. Farrell II | | Chairman of the Board of Directors and Chief Executive Officer | | | /s/ Mark F. McGettrick Mark F. McGettrick | | Director, Executive Vice President and Chief Financial Officer | | | /s/ Mark O. Webb Mark O. Webb | | Director | | | /s/ Michele L. Cardiff Michele L. Cardiff | | Vice President, Controller and Chief Accounting Officer |
Dominion Gas Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | DOMINION GAS HOLDINGS, LLC | | | | By: | | /S/ THOMAS F. FARRELL II | | | (Thomas F. Farrell II, Chairman of the Board of Directors and Chief Executive Officer) |
Date: February 27, 20142015 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 27th day of February, 2014.2015. | | | | Signature | | Title | | | /S/ THOMASs/ Thomas F. FARRELLFarrell II Thomas F. Farrell II | | Chairman of the Board of Directors and Chief Executive Officer | | | /S/ MARKs/ Mark F. MCGETTRICK McGettrick Mark F. McGettrick | | Director, Executive Vice President and Chief Financial Officer | | | /S/ ASHWINI SAWHNEY s/ Mark O. Webb Ashwini SawhneyMark O. Webb
| | Director | | | /s/ Michele L. Cardiff Michele L. Cardiff | | Vice President, Controller and Chief Accounting Officer | | | /S/ MARK O. WEBB
Mark O. Webb
| | Director |
Exhibit Index | | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | | 2 | | Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1,Form 8-K filed March 15, 2010, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 3.1.a | | Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 3.1.b | | Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on March 3, 2011October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, FileNo. 1-2255). | | | | | | | X | | | | | | | | | | | | 3.1.c | | Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 29, 2011,4, 2014, File No. 1-2255)333-195066). | | | | | | | | | | | X | | | | | | | | 3.2.a | | Dominion Resources, Inc. Amended and Restated Bylaws, effective May 3, 2013 (Exhibit 3.1, Form 8-K filed May 3, 2013, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 3.2.b | | Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255). | | | | | | | X | | | | | | | | | | | | 3.2.c | | Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066). | | | | | | | | | | | X | | | | | | | | 4 | | Dominion Resources, Inc. and, Virginia Electric and Power Company and Dominion Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets. | | | X | | | | X | | | | X | | | | | | | | 4.1.a | | See Exhibit 3.1.a above. | | | X | | | | | | | | | | | | | | | | 4.1.b | | See Exhibit 3.1.b above. | | | | | | | X | | | | | | | | | | | | 4.2 | | Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indenture (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); Ninety-Second Supplemental Indenture, dated as of July 1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255). | | | X | | | | X | | | | | | | | | | | | 4.3 | | Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of FirstTenth Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and(Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of EleventhTwelfth Supplemental Indenture, dated DecemberJanuary 1, 20032006 (Exhibit 4.2, Form 8-K filed December 11, 2003,January 12, 2006, File No. 1-2255); FormsForm of Twelfth and Thirteenth Supplemental Indentures,Indenture, dated as of January 1, 2006 (Exhibits 4.2 and(Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); FormsForm of Sixteenth and Seventeenth Supplemental Indentures,Indenture, dated November 1, 2007 (Exhibits 4.2 and(Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No.1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, FileNo.1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filedTwenty- | | | X | | | | X | | | | | |
| | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | | Dominion
Gas | | | Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No.1-2255). | | | | | | | | | | | | | | | 4.4 | | Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a FirstForm of Second Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement filed April 22, 1998, File No. 333-50653); Forms of Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits(Exhibit 4.6, and 4.13, Form 8-K filed January 12, 2001, File No. 1-8489). | | | X | | | | | | | | 4.5 | | Indenture, dated May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012); Fifteenth Supplemental Indenture, dated October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651); Seventeenth Supplemental Indenture, dated August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Eighteenth Supplemental Indenture, dated December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Nineteenth Supplemental Indenture, dated January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Twentieth Supplemental Indenture, dated March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-3196); Twenty-First Supplemental Indenture, dated June 27, 2007 (Exhibit 4.2, Form 8-K filed July 3, 2007, File No. 1-8489). | | | X | | | | | | | | | 4.64.5 | | Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2, Form 8-A filed April 21, 1995, File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8%8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2, Form 8-A filed December 12, 1996, File No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008)2026); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2, Form 8-A filed October 22, 1998, File No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004); Second Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.4, Form 8-K filed July 3, 2007, File No. 1-8489). | | | X | | | | | | | | | | | 4.74.6 | | Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of FirstSixteenth Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K filed June 22, 2000, File No. 1-8489); Forms of Second and Third Supplemental Indentures, dated July 1, 2000 (Exhibits 4.2 and 4.3, Form 8-K filed July 11, 2000, File No. 1-8489); Fourth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.2, Form 8-K filed September 8, 2000, File No. 1-8489); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K filed September 11, 2000, File No. 1-8489); Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental | | | X | | | |
| | | | | | | | | Exhibit
Number
| | Description
| | Dominion | | | Virginia
Power | | | | | | | Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and(Exhibit 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); FormsForm of Seventeenth and Eighteenth Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489; Forms of Twentieth and Twenty-First Supplemental Indentures,Indenture, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-ThirdTwenty-Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits(Exhibit 4.2, and 4.3, Form 8-K filed January 14, 2004, FileNo. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No.333-120339); Forms Form of Twenty-Eighth and Twenty-Ninth Supplemental Indentures,Indenture, dated June 1, 2005 (Exhibits 4.2 and(Exhibit 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-FirstThirty-Second Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits(Exhibit 4.2, and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29,30, 2007, File No. 1-8489); Forms of Thirty-Fifth Thirty-Sixth and Thirty-SeventhThirty-Sixth Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2 4.3 and 4.4,4.3, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, FileNo. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011 (Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K, filed March 7, 2011, File No. 1- 8489)1-8489); Forty- ThirdForty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3,Form 8-K, filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 15, 2011, File No.1-8489); Forty-Fifth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No.1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Eighth Supplemental Indenture, dated March 1, 2014 (Exhibit 4.3, Form 8-K, filed March 24, 2014, File No. 1-8489); Forty-Ninth Supplemental Indenture, dated November 1, 2014 (Exhibit 4.3, Form 8-K, filed November 25, 2014, File No. 1-8489); Fiftieth | | | X | | | | | |
| | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | Dominion
Gas | | | | Supplemental Indenture, dated November 1, 2014 (Exhibit 4.4, Form 8-K, filed November 25, 2014, File No. 1-8489); Fifty-First Supplemental Indenture, dated November 1, 2014 (Exhibit 4.5, Form 8-K, filed November 25, 2014, File No. 1-8489). | | | | | | | | | | | | | | | | 4.84.7 | | Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K filed April 12, 2001, File No. 1-3196); Forms of Second and Third Supplemental Indentures, dated October 25, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed October 23, 2001, File No. 1-3196); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K filed May 22, 2002, File No. 1-3196); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196); Seventh Supplemental Indenture, dated June 27, 2007 (Exhibit 4.6, Form 8-K filed July 3, 2007, File No. 1-8489). | | | X | | | | | | | | | | | | | 4.94.8 | | Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, FileNo. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489); Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2014, File No. 1-8489). | | | X | | | | | | | |
| | | | | | | | | | | Exhibit
Number
| | Description
| | Dominion | | | Virginia
Power | | 4.10 | | Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, FileNo. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489). | | | X | | | | | | | | | | | | | 4.114.10 | | Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No.1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No.1-8489). | | | X | | | | | | | | | | | | | 4.124.11 | | Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated July 18, 2014 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2014 filed July 30, 2014, File No. 1-8489). | | | X | | | | | | | | | | | | | 4.134.12 | | Series A Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.7, Form 8-K filed June 7, 2013, File No.1-8489). | | | X | | | | | | | | | | | | | 4.144.13 | | Series B Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.8, Form 8-K filed June 7, 2013, File No.1-8489). | | | X | | | | | | | | | | | | | | 4.14 | | 2014 Series A Purchase Contract and Pledge Agreement, dated as of July 1, 2014, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.5, Form 8-K filed July 1, 2014, File No. 1-8489). | | | X | | | | | | | | | | | | | | 4.15 | | Indenture, dated as of October 1, 2013, between Dominion Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form S-4 filed April 4, 2014, File No. 333-195066); First Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.2, | | | X | | | | | | X | |
| | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | �� | Virginia
Power | | | Dominion
Gas | | | | Form S-4 filed April 4, 2014, File No. 333-195066); Second Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.3, Form S-4 filed April 4, 2014, File No. 333-195066); Third Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.4, Form S-4 filed April 4, 2014, File No. 333-195066); Fourth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.2, Form 8-K filed December 8, 2014, File No. 333-195066); Fifth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.3, Form 8-K filed December 8, 2014, File No. 333-195066); Sixth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.4, Form 8-K filed December 8, 2014, File No. 333-195066). | | | | | | | | | | | | | | | | | | | 10.1 | | DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 10.2 | | DRS Services Agreement, dated as of January 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255). | | | | | | | X | | | | | | | | | | | | 10.3 | | Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489). | | | X | | | | X | | | | | | | | | | | | 10.4 | | $3.0 billion Three-Year4,000,000,000 Five-Year Amended and Restated Revolving Credit Agreement, dated September 24, 2010May 19, 2014, among Dominion Resources, Inc., Virginia Electric and Power Company, JP MorganDominion Gas Holdings, LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, The Royal Bank of Scotland plc, Bank of America, N.A., Barclays Capital, The Royal Bank of Scotland plc,PLC and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein.therein (Exhibit 10.1, Form 8-K filed September 28, 2010, File No. 1-8489), as amended October 1, 2011 (Exhibit 10.1, Form 8-K filed October 3, 2011,May 19, 2014, File No. 1-8489 and File No. 1-2255). | | | X | | | | X | | | | X | | | | | | | | 10.5 | | $500 million Three-Year500,000,000 Five-Year Amended and Restated Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, Keybank National Association, as Administrative Agent, Bayerische Landesbank, New York Branch, and U.S. Bank National Association, as Syndication Agents,Agent, and other lenders named therein.therein (Exhibit 10.2,10.1, Form 8-K filed September 28, 2010,June 2, 2014, File No.1-8489) , as amended October 1, 2011 (Exhibit 10.2, Form 8-K filed October 3, 2011, File No. 1-8489 and File No. 1-2255). | | | X | | | | X | | | | X | | | | | | | | 10.6 | | Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10,Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003, File No. 1-8489 and File No. 1-2255). | | | X | | | | X | | | | | | | | | | | | 10.7* | | Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, FileNo. 1-8489), as amended September 26, 2014 (Exhibit 10.1, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). | | | X | | | | X | | | | X | | | | | | | | 10.8* | | Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489). | | | X | | | | X | | | | X | |
| | | | | | | | | | | Exhibit
Number
| | Description
| | Dominion | | | Virginia
Power | | | 10.9* | | Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company dated January 24, 2013 (effective for certain officers elected subsequent to February 1, 2013) (filed herewith)(Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2013 filed February 27, 2014, File No. 1-8489 and File No. 1-2255). | | | X | | | | X | | | | X | | | | | | | | 10.10* | | Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489), as amended September 26, 2014 (Exhibit 10.2, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). | | | X | | | | X | | | | X | | | | | | | | 10.11* | | Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489). | | | X | | | | X | | | | X | |
| | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | | | | | | | 10.12* | | Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489), as amended and restated effective July 1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013 filed August 6, 2013 File No. 1-8489), as amended September 26, 2014 (Exhibit 10.3, Form10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). | | | X | | | | X | | | | X | | | | | | | | 10.13* | | Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255), as amended September 26, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). | | | X | | | | X | | | | X | | | | | | | | 10.14* | | Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 10.15* | | Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No.1-8489). | | | X | | | | | | | | | | | | | | | | 10.16* | | Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 10.17* | | Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489). | | | X | | | | | | | | | | | | | | | | 10.18* | | Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011May 7, 2014 (Exhibit 10.22,10.4, Form 10-K10-Q for the fiscal quarter ended June 30, 2014 filed February 28, 2011,July 30, 2014, File No. 1-8489)1-8489 and File No. 1-2250). | | | X | | | | X | | | | X | | | | | | | | 10.19* | | Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No.1-8489). | | | X | | | | X | | | | X | | | | | | | | 10.20* | | Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No.1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No.1-8489). | | | X | | | | X | | | | X | | | | | | | | 10.21* | | Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | | 10.22* | | Supplemental Retirement Agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255). | | | X | | | | X | | | | X | | | | | | | | 10.23* | | Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255). | | | X | | | | X | | | | X | | | | | | | | 10.24* | | Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 | | | X | | | | X | | | | X | |
| | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | 10.24* | | Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit(Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255). | | | X | | | | | | | X | | | | | | | | | 10.25* | | 2009 Performance Grant Plan under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.1, Form 8-K filed January 29, 2009, File No. 1-8489). | | | X | | | | X | | | | | | 10.26* | | Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.27*10.26* | | Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective December 20, 2011 (Exhibit 10.32, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255). | | | X | | | | X | | | | X | | | | | | | 10.28*10.27* | | 2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.29*10.28* | | Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.30*10.29* | | Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.31*10.30* | | 2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.32*10.31* | | Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.33*10.32* | | Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.34*10.33* | | 2012 Performance Grant Plan under the 2012 Long-Term Incentive Program approved January 19, 2012 (Exhibit 10.1, Form 8-K filed January 20, 2012, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.35*10.34* | | Form of Restricted Stock Award Agreement under the 2012 Long-term Incentive Program approved January 19, 2012 (Exhibit 10.2, Form 8-K filed January 20, 2012, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.36*10.35* | | 2013 Performance Grant Plan under 2013 Long-Term Incentive Program approved January 24, 2013 (Exhibit 10.1, Form 8-K filed January 25, 2013, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.37*10.36* | | Form of Restricted Stock Award Agreement under the 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.2, Form 8-K filed January 25, 2013, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.38*10.37* | | Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010 (Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.39*10.38* | | Retirement Agreement, dated as of June 20, 2013, between Dominion Resources, Inc. and Gary L. Sypolt (Exhibit 10.1, Form 8-K filed June 24, 2013, File No. 1-8489). | | | X | | | | | | | | | | | | | | | 10.40*10.39* | | 2014 Performance Grant Plan under 2014 Long-Term Incentive Program approved January 16, 2014 (filed herewith)(Exhibit 10.40, Form 10-K for the fiscal year ended December 31, 2013, FileNo. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.41*10.40* | | Form of Restricted Stock Award Agreement under the 2014 Long-term Incentive Program approved January 16, 2014 (filed herewith)(Exhibit 10.41, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.42*10.41* | | Form of Special Performance Grant for Thomas F. Farrell II and Mark F. McGettrick approved January 16, 2014 (filed herewith)(Exhibit 10.42, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | 10.43*10.42* | | Base salaries for named executive officers of Dominion Resources, Inc.2015 Performance Grant Plan under 2015 Long-Term Incentive Program approved January 22, 2015 (filed herewith). | | | X | | | | X | | | | X | | | | | | | 10.44*10.43* | | Non-employee directors’ annual compensation for Dominion Resources, Inc.Form of Restricted Stock Award Agreement under the 2015 Long-term Incentive Program approved January 22, 2015 (filed herewith). | | | X | | | | | | | | | | 12.a | | Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith). | | | X | | | | | | | | | | 12.b | | Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith). | | | | | | | X | |
| | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | 12.c | | | | | | 10.44* | | Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith). | | | X | | | | | | | | | | | | | | | | 10.45* | | Non-employee directors’ annual compensation for Dominion Resources, Inc. (filed herewith). | | | X | | | | | | | | | | | | | | | | 10.46* | | Dominion Resources, Inc. 2014 Incentive Compensation Plan, effective May 7, 2014 (Exhibit 10.1, Form 8-K filed May 7, 2014, File No. 1-8489). | | | X | | | | X | | | | X | | | | | | | | 10.47 | | Registration Rights Agreement, dated as of October 22, 2013, by and among Dominion Gas Holdings, LLC and RBC Capital Markets, LLC, RBS Securities Inc. and Scotia Capital (USA) Inc., as the initial purchasers of the Notes (Exhibit 10.1, Form S-4 filed April 4, 2014, File No. 333-195066). | | | | | | | | | | | X | | | | | | | | 10.48 | | Inter-Company Credit Agreement, dated October 17, 2013, between Dominion Resources, Inc. and Dominion Gas Holdings, LLC (Exhibit 10.2, Form S-4 filed April 4, 2014, FileNo. 333-195066). | | | X | | | | | | | | X | | | | | | | | 10.49 | | DRS Services Agreement, dated September 12, 2013, between Dominion Gas Holdings, LLC and Dominion Resources Services, Inc. (Exhibit 10.3, Form S-4 filed April 4, 2014, File No. 333-195066). | | | | | | | | | | | X | | | | | | | | 10.50 | | DRS Services Agreement, dated January 1, 2003, between Dominion Transmission Inc. and Dominion Resources Services, Inc. (Exhibit 10.4, Form S-4 filed April 4, 2014, FileNo. 333-195066). | | | | | | | | | | | X | | | | | | | | 10.51 | | DRS Services Agreement, dated January 1, 2003, between The East Ohio Company and Dominion Resources Services, Inc. (Exhibit 10.5, Form S-4 filed April 4, 2014, File No. 333-195066). | | | | | | | | | | | X | | | | | | | | 10.52 | | DRS Services Agreement, dated January 1, 2003, between Dominion Iroquois, Inc. and Dominion Resources Services, Inc. (Exhibit 10.6, Form S-4 filed April 4, 2014, File No. 333-195066). | | | | | | | | | | | X | | | | | | | | 12.a | | Ratio of earnings to fixed charges and dividendsfor Dominion Resources, Inc. (filed herewith). | | | X | | | | | | | | | | | | | | | | 12.b | | Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith). | | | | | | | X | | | | | | | | | | | | 12.c | | Ratio of earnings to fixed charges for Dominion Gas Holdings, LLC (filed herewith). | | | | | | | | | | | X | | | | | | | | 21 | | Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith). | | | X | | | | X | | | | | | | | | | | | 23 | | Consent of Deloitte & Touche LLP (filed herewith). | | | X | | | | X | | | | X | | | | | | | | 31.a | | Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | X | | | | | | | | | | | | | | | | 31.b | | Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | X | | | | | | | | | | | | | | | | 31.c | | Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | | | | | X | | | | | | | | | | | | 31.d | | Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | | | | | X | | | | | | | | | | | | 31.e | | Certification by Chief Executive Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | | | | | | | | | X | | | | | | | | 31.f | | Certification by Chief Financial Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | | | | | | | | | | | X | | | | | | | | 32.a | | Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). | | | X | | | | | | | | | | | | | | | | 32.b | | Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). | | | | | | | X | | | | | |
| | | | | 99.1 | | Towers Watson Energy Services Survey participants (filed | | 177 |
| | | | | | | | | | | | | | | Exhibit Number | | Description | | Dominion | | | Virginia
Power | | | Dominion
Gas | | | | | | | | 32.c | | Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). | | | | | | | | | | | X | | | | | | | | 101 | | The following financial statements from Dominion Resources, Inc. and, Virginia Electric and Power Company and Dominion Gas Holdings, LLC Annual Report on Form 10-K for the year ended December 31, 2013,2014, filed on February 27, 2014,2015, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. | | | X | | | | X | | | | X | |
| * | Indicates management contract or compensatory plan or arrangement |
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