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Outlook Dominion Energy’s 2021 net income is expected to increase on a per share basis as compared to 2020 primarily from the following: • The absence of charges associated with the cancellation of the Atlantic Coast Pipeline Project and related portions of the Supply Header Project; • The absence of charges associated with the impairment of interests in certain nonregulated solar generation facilities, the early retirement of certain electric generation facilities and contract termination in connection with the sale of Fowler Ridge; • The absence of charges for expected CCRO and customer arrears forgiveness for Virginia utility customers; • A reduction in merger and integration related costs associated with the SCANA Combination; • A reduction in charges associated with litigation acquired in the SCANA Combination; • Construction and operation of growth projects in electric utility and gas distribution operations; • Share accretion as a result of repurchases of common stock completed in 2020; and • A decrease in planned outage days at Millstone. |
Analysis of Consolidated Operations Presented below are selected amounts related to Virginia Power’s results of operations: An analysis of Virginia Power’s results of operations follows: 2020 VS. 2019 Operating revenue decreased 4%, primarily reflecting: • A $561 million decrease in the fuel cost component included in utility rates as a result of a net decrease in commodity costs associated with sales to electric utility retail customers; • A $100 million decrease in sales to retail customers from a decrease in cooling degree days during the cooling season ($33 million) and a decrease in heating degree days during the heating season ($67 million); • A $66 million decrease in sales to electric retail customers associated with economic and other usage factors; • A $45 million decrease due to the absence of various contracts; and • A $29 million decrease in sales to electric retail customers associated with usage factors impacted by COVID-19; partially offset by • A $387 million increase from riders; • A $64 million increase in off-system PJM sales; and • A $35 million increase in sales to electric retail customers due to customer growth. |
Impairment of assets and other charges increased 44%, primarily due to: • An increase in charges associated with the planned early retirements of certain electric generation facilities ($402 million); • A charge for benefits expected to be provided to retail electric customers in Virginia through the use of a CCRO in accordance with the GTSA ($130 million); • A charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020 ($127 million); and • An increase in dismantling costs associated with certain electric generation facilities ($54 million); partially offset by • The absence of a charge related to the planned early retirement of certain automated meter reading infrastructure ($160 million); • The absence of a $135 million charge related to contract termination with a non-utility generator; • The absence of a $62 million charge related to the abandonment of a project at an electric generating facility; • The absence of a $21 million charge for disallowance of state-regulated plant; and • The absence of a $17 million charge related to the abandonment of certain property, plant and equipment. |
Financial Statements and Supplementary Data Page Number Dominion Energy, Inc. Report of Independent Registered Public Accounting Firm Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018 Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018 Consolidated Balance Sheets at December 31, 2020 and 2019 Consolidated Statements of Equity at December 31, 2020, 2019 and 2018 and for the years then ended Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018 Virginia Electric and Power Company Report of Independent Registered Public Accounting Firm Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018 Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018 Consolidated Balance Sheets at December 31, 2020 and 2019 Consolidated Statements of Common Shareholder’s Equity at December 31, 2020, 2019 and 2018 and for the years then ended Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018 Combined Notes to Consolidated Financial Statements REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders and the Board of Directors of Dominion Energy, Inc. Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheets of Dominion Energy, Inc. and subsidiaries ("Dominion Energy") at December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the "consolidated financial statements"). |
The primary types of sales and service activities reported as operating revenue for Dominion Energy are as follows: Revenue from Contracts with Customers • Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; • Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates and associated hedging activity; • Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services; • 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 and associated hedging activity; • Regulated gas transportation and storage sales consist of state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers, sales of gathering services and sales of transportation services to off-system customers; • Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and • Other nonregulated revenue consists primarily of sales of commodities related to nonregulated extraction activities and other miscellaneous products. |
The inputs and assumptions used in measuring fair value include the following: For commodity derivative contracts: • Forward commodity prices • Transaction prices • Price volatility • Price correlation • Volumes • Commodity location • Interest rates • Credit quality of counterparties and the Companies • Credit enhancements • Time value For interest rate derivative contracts: • Interest rate curves • Credit quality of counterparties and the Companies • Notional value • Credit enhancements • Time value For foreign currency derivative contracts: • Foreign currency forward exchange rates • Interest rates • Credit quality of counterparties and the Companies • Notional value • Credit enhancements • Time value For investments: • Quoted securities prices and indices • Securities trading information including volume and restrictions • Maturity • Interest rates • Credit quality 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: • Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. |
The net expenses for specific items attributable to Dominion Energy’s operating segments in 2020 primarily related to the impact of the following items: • A $751 million ($564 million after-tax) charge primarily related to the planned early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia; • A $405 million ($325 million after-tax) charge associated with certain nonregulated solar generation facilities, attributable to Contracted Assets; • A $221 million ($171 million after-tax) charge associated with the sale of Fowler Ridge, attributable to Contracted Assets; and • A $130 million ($97 million after-tax) charge for the expected CCRO to be provided to Virginia retail electric customers under the GTSA, attributable to Dominion Energy Virginia; • A $127 million ($94 million after-tax) charge for the forgiveness of Virginia retail electric customer accounts in arrears pursuant to legislation enacted in November 2020, attributable to Dominion Energy Virginia; and • A $117 million ($93 million after-tax) of charges associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina; partially offset by • A $335 million ($264 million after-tax) net gain related to investments in nuclear decommissioning trust funds attributable to: • Dominion Energy Virginia ($27 million after-tax); and • Contracted Assets ($237 million after-tax). |
• A $346 million ($257 million after-tax) charge related to the early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia; • A $194 million tax charge for $258 million of income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina; • A $160 million ($119 million after-tax) charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure, attributable to Dominion Energy Virginia; • A $135 million ($100 million after-tax) charge related to Virginia Power’s contract termination with a non-utility generator, attributable to Dominion Energy Virginia; • A $114 million ($86 million after-tax) charge for property, plant and equipment acquired in the SCANA Combination primarily for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina; partially offset by • A $553 million ($411 million after-tax) net gain related to investments in nuclear decommissioning trust funds attributable to: • Dominion Energy Virginia ($49 million after-tax); and • Contracted Assets ($362 million after-tax); and • A $113 million ($84 million after-tax) benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019, attributable to Dominion Energy Virginia. |
The net expenses for specific items attributable to Dominion Energy’s operating segments in 2018 primarily related to the impact of the following items: • A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers, attributable to Dominion Energy Virginia; • A $170 million ($134 million after-tax) net loss related to our investments in nuclear decommissioning trust funds attributable to: • Dominion Energy Virginia ($14 million after-tax); and • Contracted Assets ($120 million after-tax); • An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Dominion Energy Virginia; and • A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Dominion Energy Virginia; partially offset by • A $282 million ($229 million after-tax) benefit associated with the sale of certain nonregulated generation facilities, attributable to Contracted Assets. |
These factors include but are not limited to: • Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; • Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding, climate changes and changes in water temperatures and availability that can cause outages and property damage to facilities; • Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations; • Risks of operating businesses in regulated industries that are subject to changing regulatory structures; • Changes to regulated electric rates collected by Dominion Energy and Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas; • Changes in rules for RTOs and ISOs in which Dominion Energy and Virginia Power join and/or participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; • Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; • Risks associated with entities in which Dominion Energy and Dominion Energy Gas share ownership with third parties, including risks that result from lack of sole decision making authority, disputes that may arise between Dominion Energy and Dominion Energy Gas and third party participants and difficulties in exiting these arrangements; • Changes in future levels of domestic and international natural gas production, supply or consumption; • Fluctuations in future volumes of LNG imports or exports from the U.S. and other countries worldwide or demand for, purchases of, and prices related to natural gas or LNG; • Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals; • The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects; • Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances; • Cost of environmental compliance, including those costs related to climate change; • Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; • Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals; • Unplanned outages at facilities in which the Companies have an ownership interest; • The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events; • Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; • Changes in operating, maintenance and construction costs; • Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; • Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers; • Competition in the development, construction and ownership of certain electric transmission facilities in Dominion Energy and Virginia Power’s service territory in connection with Order 1000; • Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; • Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy and Dominion Energy Gas’ pipeline systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; • Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; • Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews; • Adverse outcomes in litigation matters or regulatory proceedings, including matters acquired in the SCANA Combination; • Counterparty credit and performance risk; • Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion Energy and Virginia Power and in benefit plan trusts by Dominion Energy and Dominion Energy Gas; • Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s earnings and the Companies’ liquidity position and the underlying value of their assets; • Fluctuations in interest rates or foreign currency exchange rates; • Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; • Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; • Political and economic conditions, including inflation and deflation; • Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and • Changes in financial or regulatory accounting principles or policies imposed by governing bodies. |
Analysis of Consolidated Operations Presented below are selected amounts related to Dominion Energy’s results of operations: An analysis of Dominion Energy’s results of operations follows: 2019 vs. 2018 Net revenue increased 23%, primarily reflecting: • A $1.5 billion increase from the SCANA Combination, due to operations acquired ($2.5 billion), partially offset by a $1.0 billion charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project; • A $348 million increase from Virginia Power rate adjustment clauses; • A $257 million increase from the Liquefaction Facility, including terminalling services provided to the Export Customers ($190 million), a decrease in credits associated with the start-up phase ($44 million) and regulated gas transportation contracts to serve the Export Customers ($23 million); • The absence of a $215 million charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers; • A $74 million decrease in Virginia Power electric capacity expense related to the annual PJM capacity performance market effective June 2019 ($63 million) and a contract termination with a non-utility generator ($37 million), partially offset by the annual PJM capacity performance market effective June 2018 ($26 million); • A $57 million increase due to favorable pricing at Millstone, including the effects of the Millstone 2019 power purchase agreements; and • A $40 million decrease in Virginia Power fuel costs due to the expiration of an energy supply contract. |
Impairment of assets and related charges increased $1.1 billion, primarily due to: • Charges associated with litigation acquired in the SCANA Combination ($641 million); • A $346 million charge related to the early retirement of certain Virginia Power electric generation facilities; • A $160 million charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure; • A $135 million charge related to Virginia Power’s contract termination with a non-utility generator; • A $105 million charge for property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery; • A $62 million charge related to the abandonment of a project at a Virginia Power electric generating facility; and • The abandonment of certain property, plant and equipment ($39 million); partially offset by • The absence of a $219 impairment charge on certain gathering and processing assets; • The absence of a $135 million charge for disallowance of FERC-regulated plant; and • The absence of a $37 million write-off associated with the Eastern Market Access Project. |
2018 vs. 2017 Net revenue increased 2%, primarily reflecting: • A $500 million increase due to commencement of commercial operations of the Liquefaction Facility, including terminalling services provided to the Export Customers ($508 million) and regulated gas transportation contracts to serve the Export Customers ($58 million), partially offset by credits associated with the start-up phase of the Liquefaction Facility ($66 million); • An increase in sales to electric utility retail customers from an increase in heating degree days during the heating season of 2018 ($71 million) and an increase in cooling degree days during the cooling season of 2018 ($69 million); • A $130 million increase due to favorable pricing at merchant generation facilities; • A $92 million increase due to growth projects placed in service, other than the Liquefaction Facility; • A $74 million increase in services performed for Atlantic Coast Pipeline; and • A $46 million increase in sales to electric utility retail customers due to customer growth. |
Outlook Dominion Energy’s 2020 net income is expected to increase on a per share basis as compared to 2019 primarily from the following: • The absence of charges for refunds of amounts previously collected from retail electric customers of DESC for the NND Project; • The absence of charges associated with the early retirement of certain Virginia Power electric generation facilities and automated meter reading infrastructure; • A reduction in merger and integration-related costs associated with the SCANA Combination, including charges related to a voluntary retirement program; Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued • A decrease in charges associated with litigation acquired in the SCANA Combination; • Construction and operation of growth projects in gas transmission and distribution; • Construction and operation of growth projects in electric utility operations; • Lower depreciation on Virginia Power’s nuclear plants associated with expected approval of license extensions from the NRC; • Reduced interest expense as a result of early redemptions of long-term debt; and • Delivery under the Millstone 2019 power purchase agreements for an entire year. |
Presented below, on an after-tax basis, are the key factors impacting Gas Distribution’s net income contribution: 2019 VS. 2018 2018 VS. 2017 Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued Dominion Energy South Carolina Presented below are selected operating statistics related to Dominion Energy South Carolina’s operations: 2019 VS. 2018 Presented below, on an after-tax basis, are the key factors impacting Dominion Energy South Carolina’s net income contribution: Contracted Generation Presented below are selected operating statistics related to Contracted Generation’s operations: Presented below, on an after-tax basis, are the key factors impacting Contracted Generation’s net income contribution: 2019 VS. 2018 2018 VS. 2017 Corporate and Other Presented below are the Corporate and Other segment’s after-tax results: Total Specific Items Corporate and Other includes specific items attributable to Dominion Energy’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. |
Analysis of Consolidated Operations Presented below are selected amounts related to Virginia Power’s results of operations: An analysis of Virginia Power’s results of operations follows: 2019 VS. 2018 Net revenue increased 14%, primarily reflecting: • A $348 million increase from rate adjustment clauses; • The absence of a $215 million charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers; • A $74 million decrease in electric capacity expense primarily related to the annual PJM capacity performance market effective June 2019 ($63 million) and a contract termination with a non-utility generator ($37 million), partially offset by the annual PJM capacity performance market effective June 2018 ($26 million); and • A $40 million decrease in fuel costs due to the expiration of an energy supply contract; partially offset by • A $45 million decrease in sales to retail customers from lower heating degree days during the heating season, partially offset by a $25 million increase from higher cooling degree days during the cooling season. |
2018 VS. 2017 Net revenue decreased 8%, primarily reflecting: • A $238 million decrease for regulated generation and distribution operations as a result of the 2017 Tax Reform Act; • A $215 million charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers; • A $94 million increase in net electric capacity expense related to the annual PJM capacity performance market effective June 2017 ($112 million) and the annual PJM capacity performance market effective June 2018 ($39 million), partially offset by a benefit related to non-utility generators ($57 million); and • An $89 million decrease from rate adjustment clauses, which includes the impacts of the 2017 Tax Reform Act; partially offset by • An increase in sales to retail customers from an increase in heating degree days during the heating season of 2018 ($71 million) and an increase in cooling degree days during the cooling season of 2018 ($69 million); and • A $46 million increase in sales to retail customers due to customer growth. |
The primary types of sales and service activities reported as operating revenue for Dominion Energy, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows: Revenue from Contracts with Customers • Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; • Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated hedging activity; • Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services; • 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 and associated hedging activity; • Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; • Nonregulated gas transportation and storage sales consist primarily of LNG terminalling services; • Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and • Other nonregulated revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity. |
The primary types of sales and service activities reported as operating revenue for Dominion Energy, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows: • Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; • Nonregulated electric sales consisted primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity; • Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity; • Nonregulated gas sales consisted 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; • Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. |
The inputs and assumptions used in measuring fair value include the following: For commodity derivative contracts: • Forward commodity prices • Transaction prices • Price volatility • Price correlation • Volumes • Commodity location • Interest rates • Credit quality of counterparties and the Companies • Credit enhancements • Time value For interest rate derivative contracts: • Interest rate curves • Credit quality of counterparties and the Companies • Notional value • Credit enhancements • Time value For foreign currency derivative contracts: • Foreign currency forward exchange rates • Interest rates • Credit quality of counterparties and the Companies • Notional value • Credit enhancements • Time value For investments: • Quoted securities prices and indices • Securities trading information including volume and restrictions • Maturity • Interest rates • Credit quality 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: • Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. |
The net expenses for specific items in 2019 primarily related to the impact of the following items: • A $1.0 billion ($756 million after-tax) charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project, attributable to Dominion Energy South Carolina; • $641 million ($480 million after-tax) of charges associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina; • $484 million ($315 million after-tax) of charges for merger and integration-related costs associated with the SCANA Combination, including a $444 million ($332 million after-tax) charge related to a voluntary retirement program, attributable to: • Dominion Energy Virginia ($151 million after-tax); • Gas Distribution ($56 million after-tax); • Dominion Energy South Carolina ($75 million after-tax); and • Contracted Generation ($38 million after-tax); partially offset by • Gas Transmission & Storage ($5 million after-tax benefit); • A $346 million ($257 million after-tax) charge related to the early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia; • A $194 million tax charge for $258 million of income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina; • A $160 million ($119 million after-tax) charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure, attributable to Dominion Energy Virginia; • A $135 million ($100 million after-tax) charge related to Virginia Power’s contract termination with a non-utility generator, attributable to Dominion Energy Virginia; • A $114 million ($86 million after-tax) charge for property, plant and equipment acquired in the SCANA Combination primarily for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina; partially offset by • A $553 million ($411 million after-tax) net gain related to investments in nuclear decommissioning trust funds attributable to: • Dominion Energy Virginia ($49 million after-tax); and • Contracted Generation ($362 million after-tax); and • A $113 million ($84 million after-tax) benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019, attributable to Dominion Energy Virginia. |
The net expenses for specific items in 2018 primarily related to the impact of the following items: • A $219 million ($164 million after-tax) charge related to the impairment of certain gathering and processing assets attributable to Gas Transmission & Storage; • A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers, attributable to Dominion Energy Virginia; • A $170 million ($134 million after-tax) net loss related to our investments in nuclear decommissioning trust funds attributable to: • Dominion Energy Virginia ($14 million after-tax); and • Contracted Generation ($120 million after-tax); • A $124 million ($88 million after-tax) charge for disallowance of FERC-regulated plant attributable to Gas Transmission & Storage; • An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Dominion Energy Virginia; and • A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Dominion Energy Virginia; partially offset by • An $828 million ($619 million after-tax) benefit associated with the sale of certain merchant generation facilities and equity method investments attributable to: • Contracted Generation ($229 million after-tax); and • Gas Transmission & Storage ($390 million after-tax). |
Signature Title /s/ Thomas F. Farrell, II Thomas F. Farrell, II Chairman of the Board of Directors, President and Chief Executive Officer /s/ James A. Bennett James A. Bennett Director /s/ Helen E. Dragas Helen E. Dragas Director /s/ James O. Ellis, Jr. James O. Ellis, Jr. Director /s/ D. Maybank Hagood D. Maybank Hagood Director /s/ John W. Harris John W. Harris Director /s/ Ronald W. Jibson Ronald W. Jibson Director /s/ Mark J. Kington Mark J. Kington Director /s/ Joseph M. Rigby Joseph M. Rigby Director /s/ Pamela J. Royal Pamela J. Royal Director /s/ Robert H. Spilman, Jr. Robert H. Spilman, Jr. Director /s/ Susan N. Story Susan N. Story Director /s/ Michael E. Szymanczyk Michael E. Szymanczyk Director /s/ James R. Chapman James R. Chapman Executive Vice President, Chief Financial Officer and Treasurer /s/ Michele L. Cardiff Michele L. Cardiff Vice President, Controller and Chief Accounting Officer Virginia 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. |
Potential difficulties Dominion Energy may encounter in the integration process include the following: • The complexities associated with integrating SCANA, including its utility businesses, while at the same time continuing to provide consistent, high quality services; • The complexities of integrating a company with different markets and customers; • The inability to attract and retain key employees; • Potential unknown liabilities and unforeseen increased expenses associated with the SCANA Combination; • Difficulties in managing political and regulatory conditions related to SCANA’s utility businesses; • The moratorium on filing requests for adjustments in SCE&G’s base electric rates until May 2020 with no changes in rates until January 1, 2021, which limits Dominion Energy’s ability to recover increases in non-fuel related costs of electric operations for SCE&G’s customers; • The stipulation agreement approved by the North Carolina Commission, which provides for a rate moratorium at PSNC until November 1, 2021, with certain exceptions; and • Performance shortfalls as a result of the diversion of Dominion Energy management’s attention caused by integrating SCANA’s businesses. |
These factors include but are not limited to: • Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; • Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities; • Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations; • Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances; • Cost of environmental compliance, including those costs related to climate change; • Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; • Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals; • Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; • Unplanned outages at facilities in which the Companies have an ownership interest; • Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy and Dominion Energy Gas’ earnings and the Companies’ liquidity position and the underlying value of their assets; • Counterparty credit and performance risk; • Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; • Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; • Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion Energy and Virginia Power and in benefit plan trusts by Dominion Energy and Dominion Energy Gas; • Fluctuations in interest rates or foreign currency exchange rates; • Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; • Changes in financial or regulatory accounting principles or policies imposed by governing bodies; • Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; • Risks of operating businesses in regulated industries that are subject to changing regulatory structures; • Impacts of acquisitions, including the recently completed SCANA Combination, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews; • Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; • Changes in rules for RTOs and ISOs in which Dominion Energy and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; • Political and economic conditions, including inflation and deflation; • Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; • Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy and Dominion Energy Gas’ pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; • Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers; • Competition in the development, construction and ownership of certain electric transmission facilities in Dominion Energy and Virginia Power’s service territories in connection with Order 1000; • Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; • Changes to regulated electric rates collected by Dominion Energy and Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas; • Changes in operating, maintenance and construction costs; • Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals; • The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement or intervention in such projects; • Adverse outcomes in litigation matters or regulatory proceedings, including matters acquired in the SCANA Combination; and • The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events. |
Analysis of Consolidated Operations Presented below are selected amounts related to Dominion Energy’s results of operations: An analysis of Dominion Energy’s results of operations follows: 2018 VS. 2017 Net revenue increased 2%, primarily reflecting: • A $500 million increase due to commencement of commercial operations of the Liquefaction Project, including terminalling services provided to the export customers ($508 million) and regulated gas transportation contracts to serve the export customers ($58 million), partially offset by credits associated with the start-up phase of the Liquefaction Project ($66 million); • An increase in sales to electric utility retail customers from an increase in heating degree days during the heating season of 2018 ($71 million) and an increase in cooling degree days during the cooling season of 2018 ($69 million); • A $130 million increase due to favorable pricing at merchant generation facilities; • A $92 million increase due to growth projects placed in service, other than the Liquefaction Project; • A $74 million increase in services performed for Atlantic Coast Pipeline; and • A $46 million increase in sales to electric utility retail customers due to customer growth. |
2017 VS. 2016 Net revenue increased 8%, primarily reflecting: • A $663 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017; • A $97 million electric capacity benefit related to non-utility generators ($133 million) and a benefit due to the annual PJM capacity performance market effective June 2016 ($123 million), partially offset by the annual PJM capacity performance market effective June 2017 ($159 million); • An $86 million increase due to additional generation output from merchant solar generating projects; • A $71 million increase in sales to electric utility retail customers due to the effect of changes in customer usage and other factors, including $25 million related to customer growth; • A $63 million increase from regulated natural gas transmission growth projects placed in service; • A $46 million increase from rate adjustment clauses associated with electric utility operations; and • A $34 million increase in services performed for Atlantic Coast Pipeline. |
Analysis of Consolidated Operations Presented below are selected amounts related to Virginia Power’s results of operations: An analysis of Virginia Power’s results of operations follows: 2018 VS. 2017 Net revenue decreased 8%, primarily reflecting: • A $238 million decrease for regulated generation and distribution operations as a result of the 2017 Tax Reform Act; • A $215 million charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers; • A $94 million increase in net electric capacity expense related to the annual PJM capacity performance market effective June 2017 ($112 million) and the annual PJM capacity performance market effective June 2018 ($39 million), partially offset by a benefit related to non-utility generators ($57 million); and • An $89 million decrease from rate adjustment clauses, which includes the impacts of the 2017 Tax Reform Act; partially offset by • An increase in sales to retail customers from an increase in heating degree days during the heating season of 2018 ($71 million) and an increase in cooling degree days during the cooling season of 2018 ($69 million); and • A $46 million increase in sales to retail customers due to customer growth. |
The primary types of sales and service activities reported as operating revenue for Dominion Energy, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows: REVENUE FROM CONTRACTS WITH CUSTOMERS • Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; • Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated hedging activity; • Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services; • 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 and associated hedging activity; • Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; • Nonregulated gas transportation and storage sales consist primarily of LNG terminalling services; • Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and • Other nonregulated revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity. |
The primary types of sales and service activities reported as operating revenue for Dominion Energy, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows: • Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; • Nonregulated electric sales consisted primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity; • Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity; • Nonregulated gas sales consisted 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; • Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. |
The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows: REVENUE FROM CONTRACTS WITH CUSTOMERS • Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services; • Nonregulated gas sales consist primarily of sales of gas purchased from third parties and royalty revenues; • Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; • NGL revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity; • Management service revenue consists primarily of services performed for Atlantic Coast Pipeline; • Other regulated revenue consists primarily of miscellaneous regulated revenues; and • Other nonregulated revenue consists primarily of miscellaneous service revenue. |
The inputs and assumptions used in measuring fair value include the following: For commodity derivative contracts: • Forward commodity prices • Transaction prices • Price volatility • Price correlation • Volumes • Commodity location • Interest rates • Credit quality of counterparties and the Companies • Credit enhancements • Time value For interest rate derivative contracts: • Interest rate curves • Credit quality of counterparties and the Companies • Notional value • Credit enhancements • Time value For foreign currency derivative contracts: • Foreign currency forward exchange rates • Interest rates • Credit quality of counterparties and the Companies • Notional value • Credit enhancements • Time value For investments: • Quoted securities prices and indices • Securities trading information including volume and restrictions • Maturity • Interest rates • Credit quality 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: • Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. |
The net expenses for specific items in 2018 primarily related to the impact of the following items: • A $219 million ($164 million after-tax) charge related to the impairment of certain gathering and processing assets attributable to Gas Infrastructure; • A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers, attributable to: • Power Generation ($109 million after-tax); and • Power Delivery ($51 million after-tax); • A $170 million ($134 million after-tax) net loss related to our investments in nuclear decommissioning trust funds attributable to Power Generation; • A $124 million ($88 million after-tax) charge for disallowance of FERC-regulated plant attributable to Gas Infrastructure; • An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Power Generation; and • A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Power Delivery; partially offset by • An $828 million ($619 million after-tax) benefit associated with the sale of certain merchant generation facilities and equity method investments attributable to: • Power Generation ($229 million after-tax); and • Gas Infrastructure ($390 million after-tax). |
Signature Title /s/ Thomas F. Farrell, II Thomas F. Farrell, II Chairman of the Board of Directors, President and Chief Executive Officer /s/ James A. Bennett James A. Bennett Director /s/ Helen E. Dragas Helen E. Dragas Director /s/ James O. Ellis, Jr. James O. Ellis, Jr. Director /s/ D. Maybank Hagood D. Maybank Hagood Director /s/ John W. Harris John W. Harris Director /s/ Ronald W. Jibson Ronald W. Jibson Director /s/ Mark J. Kington Mark J. Kington Director /s/ Joseph M. Rigby Joseph M. Rigby Director /s/ Pamela J. Royal Pamela J. Royal Director /s/ Robert H. Spilman, Jr. Robert H. Spilman, Jr. Director /s/ Susan N. Story Susan N. Story Director /s/ Michael E. Szymanczyk Michael E. Szymanczyk Director /s/ James R. Chapman James R. Chapman Executive Vice President, Chief Financial Officer and Treasurer /s/ Michele L. Cardiff Michele L. Cardiff Vice President, Controller and Chief Accounting Officer Virginia 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. |
The principal components of the strategy, which include initiatives that address electric energy production and delivery, natural gas storage, transmission and delivery and energy management, are as follows: • Expand Dominion Energy’s and Virginia Power’s renewable energy portfolio, including solar, wind power, and biomass, to further diversify Dominion Energy’s and Virginia Power’s fleet, meet state renewable energy targets and lower the carbon footprint; • Pursue the extension of operating licenses of existing nuclear units which provide carbon-free generation; • Evaluate effective battery solutions, such as hydroelectric pumped storage, which help support a grid with increased renewables; • Enhance conservation and energy efficiency programs on both the electric and gas side of our businesses to help customers use energy wisely and reduce environmental impacts; • Sell, close, place in cold reserve or convert to cleaner fuels a number of coal-fired generation units owned by Dominion Energy and Virginia Power; • Evaluate behind-the-meter and rate design solutions and other business opportunities; • Construct new electric and gas transmission infrastructure to modernize the grid, to expand availability of cleaner fuel, to reduce emissions, to promote energy and economic security and help deliver more green energy to population centers where it is needed most; • Replace older distribution pipeline mains and services; and • Implement and enhance voluntary methane mitigation measures through participation in the EPA’s Natural Gas Star and Methane Challenge programs; and continue to evaluate business opportunities presented by a lower carbon economy and innovative technologies. |
Potential difficulties Dominion Energy may encounter in the integration process include the following: • The complexities associated with integrating SCANA and its utility businesses, while at the same time continuing to provide consistent, high quality services; • The complexities of integrating a company with different core services, markets and customers; • The inability to attract and retain key employees; • Potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the merger; • Difficulties in managing political and regulatory conditions related to SCANA’s utility businesses after the merger; • The cost recovery plan includes a moratorium on filing requests for adjustments in SCE&G’s base electric rates until 2021 if the merger is approved by the South Carolina Commission, which would limit Dominion Energy’s ability to recover increases in non-fuel related costs of electric operations for SCE&G’s customers; and • Performance shortfalls as a result of the diversion of Dominion Energy management’s attention caused by completing the merger and integrating SCANA’s utility businesses. |
These factors include but are not limited to: • Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; • Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities; • Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations, including provisions of the 2017 Tax Reform Act that take effect beginning in 2018; • Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances; • Cost of environmental compliance, including those costs related to climate change; • Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; • Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals; • Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; • Unplanned outages at facilities in which the Companies have an ownership interest; • Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s and Dominion Energy Gas’ earnings and the Companies’ liquidity position and the underlying value of their assets; • Counterparty credit and performance risk; • Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; • Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; • Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion Energy and Virginia Power and in benefit plan trusts by Dominion Energy and Dominion Energy Gas; • Fluctuations in interest rates or foreign currency exchange rates; • Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; • Changes in financial or regulatory accounting principles or policies imposed by governing bodies; • Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; • Risks of operating businesses in regulated industries that are subject to changing regulatory structures; • Impacts of acquisitions, divestitures, transfers of assets to joint ventures or Dominion Energy Midstream, and retirements of assets based on asset portfolio reviews; • The expected timing and likelihood of completion of the proposed acquisition of SCANA, including the ability to obtain the requisite approvals of SCANA’s shareholders and the terms and condition of any regulatory approvals; • Receipt of approvals for, and timing of, closing dates for other acquisitions and divestitures; • The timing and execution of Dominion Energy Midstream’s growth strategy; • Changes in rules for regional transmission organizations and independent system operators in which Dominion Energy and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; • Political and economic conditions, including inflation and deflation; • Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued • Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy and Dominion Energy Gas’ pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; • Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers; • Competition in the development, construction and ownership of certain electric transmission facilities in Virginia Power’s service territory in connection with FERC Order 1000; • Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; • Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas; • Changes in operating, maintenance and construction costs; • Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals; • The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement or intervention in such projects; • Adverse outcomes in litigation matters or regulatory proceedings; and • The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events. |
Analysis of Consolidated Operations Presented below are selected amounts related to Dominion Energy’s results of operations: An analysis of Dominion Energy’s results of operations follows: 2017 VS. 2016 Net revenue increased 8%, primarily reflecting: • A $663 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017; • A $97 million electric capacity benefit related to non-utility generators ($133 million) and a benefit due to the annual PJM capacity performance market effective June 2016 ($123 million), partially offset by the annual PJM capacity performance market effective June 2017 ($159 million); • An $86 million increase due to additional generation output from merchant solar generating projects; • A $71 million increase in sales to electric utility retail customers due to the effect of changes in customer usage and other factors, including $25 million related to customer growth; • A $63 million increase from regulated natural gas transmission growth projects placed in service; • A $46 million increase from rate adjustment clauses associated with electric utility operations; and • A $34 million increase in services performed for Atlantic Coast Pipeline. |
These increases were partially offset by: • A $47 million decrease from merchant generation operations, primarily due to lower realized prices at certain merchant generation facilities ($64 million) and an increase in planned and unplanned outage days in 2016 ($26 million), partially offset by additional solar generating facilities placed into service ($37 million); • A $19 million decrease from regulated natural gas transmission operations, primarily due to: • A $14 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by expansion projects placed in service ($18 million) and increased regulated gas sales ($20 million); and • A $17 million decrease in NGL activities, due to decreased prices ($15 million) and volumes ($2 million); partially offset by • A $12 million increase in other revenues, primarily due to an increase in services performed for Atlantic Coast Pipeline ($21 million), partially offset by decreased amor- tization of deferred revenue associated with conveyed shale development rights ($4 million); and • A $12 million decrease from regulated natural gas distribution operations, primarily due to a decrease in rate adjustment clause revenue related to low income assistance programs ($26 million) and a decrease in sales to customers due to a reduction in heating degree days ($6 million), partially offset by an increase in AMR and PIR program revenues ($18 million). |
VS. 2015 Net revenue decreased 3%, primarily reflecting: • A $34 million decrease from regulated natural gas transmission operations, primarily reflecting: • A $36 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by increased regulated gas sales ($16 million) and expansion projects placed in service ($9 million); and • An $18 million decrease from NGL activities, due to decreased prices ($16 million) and volumes ($2 million); partially offset by • A $21 million increase in services performed for Atlantic Coast Pipeline; and • A $12 million decrease from regulated natural gas distribution operations, primarily reflecting: • A decrease in rate adjustment clause revenue related to low income assistance programs ($26 million); and • A $9 million decrease in other revenue primarily due to a decrease in pooling and metering activities ($3 million), a decrease in Blue Racer management fees ($3 million) and a decrease in gathering activities ($2 million); partially offset by • An $18 million increase in AMR and PIR program revenues; and • An $8 million increase in off-system sales. |
The inputs and assumptions used in measuring fair value include the following: For commodity derivative contracts: • Forward commodity prices • Transaction prices • Price volatility • Price correlation • Volumes • Commodity location • Interest rates • Credit quality of counterparties and the Companies • Credit enhancements • Time value For interest rate derivative contracts: • Interest rate curves • Credit quality of counterparties and the Companies • Notional value • Credit enhancements • Time value For foreign currency derivative contracts: • Foreign currency forward exchange rates • Interest rates • Credit quality of counterparties and the Companies • Notional value • Credit enhancements • Time value For investments: • Quoted securities prices and indices • Securities trading information including volume and restrictions • Maturity • Interest rates • Credit quality The 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. |
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/ 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/ Ronald W. Jibson Ronald W. Jibson Director /s/ Mark J. Kington Mark J. Kington Director /s/ Joseph M. Rigby Joseph M. Rigby Director /s/ Pamela J. Royal Pamela J. Royal Director /s/ Robert H. Spilman, Jr. Robert H. Spilman, Jr. Director /s/ Susan N. Story Susan N. Story Director /s/ Michael E. Szymanczyk Michael E. Szymanczyk Director /s/ Mark F. McGettrick Mark F. McGettrick Executive Vice President and Chief Financial Officer /s/ Michele L. Cardiff Michele L. Cardiff Vice President, Controller and Chief Accounting Officer Virginia 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. |
The principal components of the strategy include initiatives that address electric energy management, electric energy production, electric energy delivery and natural gas storage, transmission and delivery, as follows: • Enhance conservation and energy efficiency programs to help customers use energy wisely and reduce environmental impacts; • Expand the Companies’ renewable energy portfolio, principally solar, wind power, fuel cells and biomass, to help diversify the Companies’ fleet, meet state renewable energy targets and lower the carbon footprint; • Evaluate other new generating capacity, including low emissions natural-gas fired and emissions-free nuclear units to meet customers’ future electricity needs; • Construct new electric transmission infrastructure to modernize the grid, promote economic security and help deliver more green energy to population centers where it is needed most; • Construct new natural gas infrastructure to expand availability of this cleaner fuel, to reduce emissions, and to promote energy and economic security both in the U.S. and abroad; • Implement and enhance voluntary methane mitigation measures through the EPA’s Natural Gas Star and Methane Challenge programs; and • As part of their commitment to compliance with such environmental laws, Dominion and Virginia Power have sold or closed a number of coal-fired generation units over the past several years, and may close additional units in the future. |
These factors include but are not limited to: • Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; • Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities; • Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations; • Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances; • Cost of environmental compliance, including those costs related to climate change; • Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; • Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals; • Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; • Unplanned outages at facilities in which the Companies have an ownership interest; • Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s and Dominion Gas’ earnings and the Companies’ liquidity position and the underlying value of their assets; • Counterparty credit and performance risk; • Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; • Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; • Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion and Dominion Gas; • Fluctuations in interest rates or foreign currency exchange rates; • Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; • Changes in financial or regulatory accounting principles or policies imposed by governing bodies; • Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; • Risks of operating businesses in regulated industries that are subject to changing regulatory structures; • Impacts of acquisitions, including the recently completed Dominion Questar Combination, divestitures, transfers of assets to joint ventures or Dominion Midstream, including the recently completed contribution of Questar Pipeline to Dominion Midstream, and retirements of assets based on asset portfolio reviews; • Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; • The timing and execution of Dominion Midstream’s growth strategy; • Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; • Political and economic conditions, including inflation and deflation; • Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; • Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion and Dominion Gas’ pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; • Additional competition in industries in which the Companies operate, including in electric markets in which Dominion’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers; • Competition in the development, construction and ownership of certain electric transmission facilities in Virginia Power’s service territory in connection with FERC Order 1000; • Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; • Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion and Dominion Gas; • Changes in operating, maintenance and construction costs; • Timing and receipt of regulatory approvals necessary for planned construction or expansion projects and compliance with conditions associated with such regulatory approvals; • The inability to complete planned construction, conversion or expansion projects at all, or with the outcomes or within the terms and time frames initially anticipated; • Adverse outcomes in litigation matters or regulatory proceedings; and • The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events. |
These increases were partially offset by: • A $47 million decrease from merchant generation operations, primarily due to lower realized prices at certain merchant generation facilities ($64 million) and an increase in planned and unplanned outage days in 2016 ($26 million), partially offset by additional solar generating facilities placed into service ($37 million); • A $19 million decrease from regulated natural gas transmission operations, primarily due to: • A $14 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by expansion projects placed in service ($18 million) and increased regulated gas sales ($20 million); and • A $17 million decrease in NGL activities, due to decreased prices ($15 million) and volumes ($2 million); partially offset by • A $12 million increase in other revenues, primarily due to an increase in services performed for Atlantic Coast Pipeline ($21 million), partially offset by decreased amortization of deferred revenue associated with conveyed shale development rights ($4 million); and • A $12 million decrease from regulated natural gas distribution operations, primarily due to a decrease in rate adjustment clause revenue related to low income assistance programs ($26 million) and a decrease in sales to customers due to a reduction in heating degree days ($6 million), partially offset by an increase in AMR and PIR program revenues ($18 million). |
• The absence of losses related to the retail electric energy marketing business which was sold in the first quarter of 2014 ($129 million); • A $77 million increase from merchant generation operations, primarily due to increased generation output reflecting the absence of planned outages at certain merchant generation facilities ($83 million) and additional solar generating facili- Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued ties placed into service ($53 million), partially offset by lower realized prices ($58 million); • A $38 million increase from regulated natural gas distribution operations, primarily due to an increase in rate adjustment clause revenue related to low income assistance programs ($12 million), an increase in AMR and PIR program revenues ($24 million) and various expansion projects placed into service ($22 million); partially offset by a decrease in gathering revenues ($9 million); and • A $30 million increase from regulated natural gas transmission operations, primarily reflecting: • A $61 million increase in gas transportation and storage activities, primarily due to the addition of DCG ($62 million), decreased fuel costs ($24 million) and various expansion projects placed into service ($24 million), partially offset by decreased regulated gas sales ($46 million); and • A $46 million net increase primarily due to services performed for Atlantic Coast Pipeline and Blue Racer; partially offset by • A $61 million decrease from NGL activities, primarily due to decreased prices. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued Analysis of Consolidated Operations Presented below are selected amounts related to Dominion Gas’ results of operations: An analysis of Dominion Gas’ results of operations follows: 2016 VS. 2015 Net revenue decreased 3%, primarily reflecting: • A $34 million decrease from regulated natural gas transmission operations, primarily reflecting: • A $36 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by increased regulated gas sales ($16 million) and expansion projects placed in service ($9 million); and • An $18 million decrease from NGL activities, due to decreased prices ($16 million) and volumes ($2 million); partially offset by • A $21 million increase in services performed for Atlantic Coast Pipeline; and • A $12 million decrease from regulated natural gas distribution operations, primarily reflecting: • A decrease in rate adjustment clause revenue related to low income assistance programs ($26 million); and • A $9 million decrease in other revenue primarily due to a decrease in pooling and metering activities ($3 million), a decrease in Blue Racer management fees ($3 million) and a decrease in gathering activities ($2 million); partially offset by • An $18 million increase in AMR and PIR program revenues; and • An $8 million increase in off-system sales. |
The inputs and assumptions used in measuring fair value include the following: For commodity derivative contracts: • Forward commodity prices • Transaction prices • Price volatility • Price correlation • Volumes • Commodity location • Interest rates • Credit quality of counterparties and the Companies • Credit enhancements • Time value For interest rate derivative contracts: • Interest rate curves • Credit quality of counterparties and the Companies • Notional value • Credit enhancements • Time value For foreign currency derivative contracts: • Foreign currency forward exchange rates • Interest rates • Credit quality of counterparties and the Companies • Notional value • Credit enhancements • Time value For investments: • Quoted securities prices and indices • Securities trading information including volume and restrictions • Maturity • Interest rates • Credit quality The 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. |
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/ Helen E. Dragas Helen E. Dragas Director /s/ James O. Ellis, Jr. James O. Ellis, Jr. Director /s/ Ronald W. Jibson Ronald W. Jibson Director /s/ John W. Harris John W. Harris Director /s/ Mark J. Kington Mark J. Kington Director /s/ Joseph M. Rigby Joseph M. Rigby Director /s/ Pamela J. Royal Pamela J. Royal Director /s/ Robert H. Spilman, Jr. Robert H. Spilman, Jr. Director /s/ Susan N. Story Susan N. Story 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/ Michele L. Cardiff Michele L. Cardiff Vice President, Controller and Chief Accounting Officer Virginia 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. |
The six principal components of the strategy include initiatives that address electric energy management, electric energy production, electric energy delivery and natural gas storage, transmission and delivery, as follows: • Enhance conservation and energy efficiency programs to help customers use energy wisely and reduce environmental impacts; • Expand the Companies’ renewable energy portfolio, principally wind power, solar, fuel cells and biomass, to help diversify the Companies’ fleet, meet state renewable energy targets and lower the carbon footprint; • Evaluate other new generating capacity, including low emissions natural-gas fired and emissions-free nuclear units to meet customers’ future electricity needs; • Construct new electric transmission infrastructure to modernize the grid, promote economic security and help deliver more green energy to population centers where it is needed most; • Construct new natural gas infrastructure to expand availability of this cleaner fuel, to reduce emissions, and to promote energy and economic security both in the U.S. and abroad; and • Implement and enhance voluntary methane mitigation measures through the EPA’s Natural Gas Star Program. |
These factors include but are not limited to: • Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; • Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities; • Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations; • Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances; • Cost of environmental compliance, including those costs related to climate change; • Changes in enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; • Changes in regulator implementation of environmental standards and litigation exposure for remedial activities; • Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals; • Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; • Unplanned outages at facilities in which the Companies have an ownership interest; • Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s and Dominion Gas’ earnings and the Companies’ liquidity position and the underlying value of their assets; • Counterparty credit and performance risk; • Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; • Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; • Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion and Dominion Gas; • Fluctuations in interest rates; • Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; • Changes in financial or regulatory accounting principles or policies imposed by governing bodies; • Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; • Risks of operating businesses in regulated industries that are subject to changing regulatory structures; • Impacts of acquisitions, divestitures, transfers of assets to joint ventures or Dominion Midstream, and retirements of assets based on asset portfolio reviews; • The expected timing and likelihood of completion of the proposed acquisition of Questar, including the ability to obtain the requisite approvals of Questar’s shareholders and the terms and conditions of any required regulatory approvals; • Receipt of approvals for, and timing of, closing dates for other acquisitions and divestitures; • The timing and execution of Dominion Midstream’s growth strategy; • Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; • Political and economic conditions, including inflation and deflation; • Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; • Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion and Dominion Gas’ pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; • Additional competition in industries in which the Companies operate, including in electric markets in which Dominion’s merchant generation facilities operate, and competition in the development, construction and ownership of certain electric transmission facilities in Virginia Power’s service territory in connection with FERC Order 1000; • Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; • Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion and Dominion Gas; • Changes in operating, maintenance and construction costs; • Timing and receipt of regulatory approvals necessary for planned construction or expansion projects and compliance with conditions associated with such regulatory approvals; • The inability to complete planned construction, conversion or expansion projects at all, or with the outcomes or within the terms and time frames initially anticipated; • Adverse outcomes in litigation matters or regulatory proceedings; and • The impact of operational hazards including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events. |
Analysis of Consolidated Operations Presented below are selected amounts related to Dominion’s results of operations: An analysis of Dominion’s results of operations follows: 2015 VS. 2014 Net revenue increased 10%, primarily reflecting: • The absence of losses related to the repositioning of Dominion’s producer services business in the first quarter of 2014, reflecting the termination of natural gas trading and certain energy marketing activities ($313 million); • A $159 million increase from electric utility operations, primarily reflecting: • An increase from rate adjustment clauses ($225 million); • An increase in sales to retail customers, primarily due to a net increase in cooling degree days ($38 million); and • A decrease in capacity related expenses ($33 million); partially offset by • An $85 million write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015; • A decrease in sales to customers due to the effect of changes in customer usage and other factors ($24 million); and • A decrease due to a charge based on the 2015 Biennial Review Order to refund revenues to customers ($20 million). |
• The absence of losses related to the retail electric energy marketing business which was sold in the first quarter of 2014 ($129 million); • A $77 million increase from merchant generation operations, primarily due to increased generation output reflecting the absence of planned outages at certain merchant generation facilities ($83 million) and additional solar generating facilities placed into service ($53 million), partially offset by lower realized prices ($58 million); • A $38 million increase from regulated natural gas distribution operations, primarily due to an increase in rate adjustment clause revenue related to low income assistance programs ($12 million), an increase in AMR and PIR program revenues ($24 million) and various expansion projects placed into service ($22 million); partially offset by a decrease in gathering revenues ($9 million); and • A $30 million increase from regulated natural gas transmission operations, primarily reflecting: • A $61 million increase in gas transportation and storage activities, primarily due to the addition of DCG ($62 million), decreased fuel costs ($24 million) and various expansion projects placed into service ($24 million), partially offset by decreased regulated gas sales ($46 million); and • A $46 million net increase primarily due to services performed for Atlantic Coast Pipeline and Blue Racer; partially offset by • A $61 million decrease from NGL activities, primarily due to decreased prices. |
Analysis of Consolidated Operations Presented below are selected amounts related to Dominion Gas’ results of operations: An analysis of Dominion Gas’ results of operations follows: 2015 VS. 2014 Net revenue increased 1%, primarily reflecting: • A $43 million increase from regulated natural gas distribution operations, primarily due to an increase in AMR and PIR program revenues ($24 million) and various expansion projects placed into service ($22 million); partially offset by • A $27 million decrease from regulated natural gas transmission operations, primarily reflecting: • A $62 million decrease from NGL activities, primarily due to decreased prices; partially offset by • A $2 million increase in gas transportation and storage activities, primarily due to decreased fuel costs ($24 million) and various expansion projects placed into service ($24 million), partially offset by decreased regulated gas sales ($46 million); and • A $33 million net increase in other revenue primarily due to services performed for Atlantic Coast Pipeline and Blue Racer ($47 million), partially offset by a decrease in non-regulated gas sales ($8 million) and decreased farmout revenues ($6 million). |
The inputs and assumptions used in measuring fair value include the following: For commodity derivative contracts: • Forward commodity prices • Transaction prices • Price volatility • Price correlation • Volumes • Commodity location • Interest rates • Credit quality of counterparties and the Companies • Credit enhancements • Time value Combined Notes to Consolidated Financial Statements, Continued For interest rate derivative contracts: • Interest rate curves • Credit quality of counterparties and the Companies • Volumes • Credit enhancements • Time value For investments: • Quoted securities prices and indices • Securities trading information including volume and restrictions • Maturity • Interest rates • Credit quality • NAV (for alternative investments and common/collective trust funds) The 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. |
The net expenses for specific items in 2013 primarily related to the impact of the following items: • 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 • 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 • An $81 million ($49 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation. |
The six principal components of the strategy include initiatives that address electric energy management, electric energy production, electric energy delivery and natural gas storage, transmission and delivery, as follows: Enhance conservation and energy efficiency programs to help customers use energy wisely and reduce environmental impacts; Expand the Companies’ renewable energy portfolio, principally wind power, solar, fuel cells and biomass, to help diversify the Companies’ fleet, meet state renewable energy targets and lower the carbon footprint; Build other new generating capacity, including low-emissions natural-gas fired and emissions-free nuclear units to meet customers’ future electricity needs; Construct new electric transmission infrastructure to modernize the grid, promote economic security and help deliver more green energy to population centers where it is needed most; Construct new natural gas infrastructure to expand availability of this cleaner fuel, to reduce emissions, and to promote energy and economic security both in the U.S. and abroad; and Implement and enhance voluntary methane mitigation measures through the EPA’s Natural Gas Star Program. |
These factors include but are not limited to: Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities; Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations; Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances; Cost of environmental compliance, including those costs related to climate change; Changes in enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; Changes in regulator implementation of environmental standards and litigation exposure for remedial activities; Difficult to anticipate mitigation requirements associated with environmental approvals; Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; Unplanned outages at facilities in which the Companies have an ownership interest; Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s and Dominion Gas’ earnings and the Companies’ liquidity position and the underlying value of their assets; Counterparty credit and performance risk; Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion and Dominion Gas; Fluctuations in interest rates; Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; Changes in financial or regulatory accounting principles or policies imposed by governing bodies; Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; Risks of operating businesses in regulated industries that are subject to changing regulatory structures; Impacts of acquisitions, divestitures, transfers of assets to joint ventures or Dominion Midstream, and retirements of assets based on asset portfolio reviews; Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; The timing and execution of Dominion Midstream’s growth strategy; Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; Political and economic conditions, including inflation and deflation; Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Gas’ pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; Additional competition in industries in which the Companies operate, including in electric markets in which Dominion’s merchant generation facilities operate, and competition in the development, construction and ownership of certain electric transmission facilities in Virginia Power’s service territory in connection with FERC Order 1000; Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion; Changes in operating, maintenance and construction costs; Timing and receipt of regulatory approvals necessary for planned construction or expansion projects and compliance with conditions associated with such regulatory approvals; The inability to complete planned construction, conversion or expansion projects at all, or with the outcomes or within the terms and time frames initially anticipated; Adverse outcomes in litigation matters or regulatory proceedings; and The impact of operational hazards including adverse developments with respect to pipeline safety or integrity, and other catastrophic events. |
Dominion’s anticipated 2015 results reflect the following significant factors: A return to normal weather in its electric utility operations; Growth in weather-normalized electric utility sales of approximately 1%, comparable to 2014 growth; Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue; The absence of certain charges incurred in 2014, including 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, charges associated with Dominion’s Liability Management Exercise, charges related to the repositioning of Dominion’s producer services business, which was completed in the first quarter of 2014, and charges related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities; Construction and operation of growth projects in gas transmission and distribution; partially offset by An increase in depreciation, depletion, and amortization; Higher operating and maintenance expenses; and A higher effective tax rate, driven primarily by higher state income tax expense and lower investment tax credits. |
The inputs and assumptions used in measuring fair value include the following: For commodity and foreign currency derivative contracts: Forward commodity prices Forward foreign currency prices Transaction prices Price volatility Price correlation Volumes Commodity location Interest rates Credit quality of counterparties and the Companies Credit enhancements Time value For interest rate derivative contracts: Interest rate curves Credit quality of counterparties and the Companies Volumes Credit enhancements Time value For investments: Quoted securities prices and indices Securities trading information including volume and restrictions Maturity Interest rates Credit quality NAV (for alternative investments and common/collective trust funds) The 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. |
The net expenses for specific items in 2013 primarily related to the impact of the following items: 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 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 An $81 million ($49 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation. |
Virginia Power currently offers the following DSM programs in Virginia: Residential Low Income Program: free energy audit for income-qualifying customers, which identifies, installs improvements and suggests additional implementation measures that will help these customers save money on energy bills; Residential Air Conditioner Cycling Program: incentives for residential customers who allow Virginia Power to cycle their central air conditioners and heat pump systems during peak periods; Residential Bundle Program: a bundle of four residential programs to be available with incentives to qualifying residential customers, including the Residential Home Energy Check-up Program, Residential Duct Testing & Sealing Program, Residential Heat Pump Tune-Up Program and Residential Heat Pump Upgrade Program; Non-Residential Energy Audit Program: an on-site energy audit providing qualified non-residential customers with energy assessments; Non-Residential Duct Testing & Sealing: an incentive for qualified non-residential customers to seal poorly performing duct and air distribution systems in qualifying non-residential facilities; and Non-Residential Distributed Generation: a program for qualified non-residential customers that provides an incentive to curtail load by operating customer-owned backup generation when requested by Virginia Power during periods of peak demand. |
These factors include but are not limited to: Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities; Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations; Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances; Cost of environmental compliance, including those costs related to climate change; Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; Unplanned outages at facilities in which Dominion has an ownership interest; Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Domin- ion’s and Virginia Power’s liquidity position and the under- lying value of their assets; Counterparty credit and performance risk; Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion; Fluctuations in interest rates; Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; Changes in financial or regulatory accounting principles or policies imposed by governing bodies; Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; Risks of operating businesses in regulated industries that are subject to changing regulatory structures; Impacts of acquisitions, divestitures, transfers of assets to joint ventures or an MLP, and retirements of assets based on asset portfolio reviews; Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; The timing and execution of our MLP strategy; Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; Political and economic conditions, including inflation and deflation; Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; Additional competition in industries in which Dominion operates, including in electric markets in which Dominion’s merchant generation facilities operate, and competition in the development, construction and ownership of certain electric transmission facilities in Virginia Power’s service territory in connection with FERC Order 1000; Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion; Changes in operating, maintenance and construction costs; Timing and receipt of regulatory approvals necessary for planned construction or expansion projects; The inability to complete planned construction, conversion or expansion projects at all, or with the outcomes or within the terms and time frames initially anticipated; Adverse outcomes in litigation matters or regulatory proceedings; and The impact of operational hazards and other catastrophic events. |
The inputs and assumptions used in measuring fair value include the following: For commodity and foreign currency derivative contracts: Forward commodity prices Forward foreign currency prices Combined Notes to Consolidated Financial Statements, Continued Transaction prices Price volatility Price correlation Mean reversion Volumes Commodity location Load shaping Usage factors Interest rates Credit quality of counterparties and Dominion and Virginia Power Credit enhancements Time value For interest rate derivative contracts: Interest rate curves Credit quality of counterparties and Dominion and Virginia Power Volumes Credit enhancements Time value For investments: Quoted securities prices and indices Securities trading information including volume and restrictions Maturity Interest rates Credit quality NAV (for alternative investments and common/collective trust funds) Dominion and Virginia Power 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. |
The net expenses for specific items in 2013 primarily related to the impact of the following items: 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 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 An $81 million ($49 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation. |
The net expenses for specific items in 2011 primarily related to the impact of the following items: 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; A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP; A $66 million ($39 million after-tax) loss from the operations of Kewaunee, attributable to Dominion Generation; 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; 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 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 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. |
The conservation and load management plan includes the following DSM programs, which were approved by the Virginia Commission in March 2010 and rolled out in May 2010: Residential Lighting Program-an instant, in-store discount on the purchase of qualifying compact fluorescent lights; this program ended in Virginia on December 31, 2011; Residential Low Income Program-free energy audit for income-qualifying customers, which identifies, installs improvements and suggests additional implementation measures that will help these customers save money on energy bills; Residential Air Conditioner Cycling Program-incentives for residential customers who allow Virginia Power to cycle their central air conditioners and heat pump systems during peak periods; Commercial Heating, Ventilating and Air Conditioning Upgrade Program-incentives for commercial customers to improve the energy efficiency of their heating and/or cooling units; and Commercial Lighting Program-incentives for commercial customers to install energy-efficient lighting. |
These factors include but are not limited to: Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, earthquakes and changes in water temperature and availability that can cause outages and property damage to facilities; Federal, state and local legislative and regulatory developments; Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances; Cost of environmental compliance, including those costs related to climate change; Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; Unplanned outages of the Companies’ facilities; Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Dominion’s and Virginia Power’s liquidity position and the underlying value of their assets; Counterparty credit and performance risk; Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion; Fluctuations in interest rates; Changes in federal and state tax laws and regulations; Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; Changes in financial or regulatory accounting principles or policies imposed by governing bodies; Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; Risks of operating businesses in regulated industries that are subject to changing regulatory structures; Impacts of acquisitions, divestitures and retirements of assets based on asset portfolio reviews; Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs and new and evolving capacity models; Political and economic conditions, including inflation and deflation; Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in customer growth or usage patterns, including as a result of energy conservation programs, and changes in demand for Dominion’s natural gas services; Additional competition in the electric industry, including in electric markets in which Dominion’s merchant generation facilities operate, and competition in the construction and ownership of electric transmission facilities in Virginia Power’s service territory, in connection with FERC Order 1000; Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion; Timing and receipt of regulatory approvals necessary for planned construction or expansion projects; The inability to complete planned construction projects within the terms and time frames initially anticipated; and Adverse outcomes in litigation matters or regulatory proceedings. |
The inputs and assumptions used in measuring fair value include the following: For commodity and foreign currency derivative contracts: Forward commodity prices Forward foreign currency prices Transaction prices Price volatility Volumes Commodity location Interest rates Credit quality of counterparties and Dominion and Virginia Power Credit enhancements Time value For interest rate derivative contracts: Interest rate curves Credit quality of counterparties and Dominion and Virginia Power Volumes Credit enhancements Time value For investments: Quoted securities prices and indices Securities trading information including volume and restrictions Maturity Interest rates Credit quality NAV (only for alternative investments) Dominion and Virginia Power 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. |
The proposed DSM programs include: Commercial Energy Audit Program-an on-site energy audit providing commercial customers with information to evaluate potential energy cost savings options; Commercial Duct Testing & Sealing-an incentive for commercial customers to seal duct and air distribution systems to improve system efficiency; Commercial Refrigeration Program-an incentive for commercial customers to install more efficient refrigeration technologies; Commercial Distributed Generation-a redesigned distributed generation program allowing customers to commit their on-site back-up generators to Virginia Power during periods of peak demand; Residential Lighting Phase II-an extension of the initial in-store discount on the purchase of qualifying compact fluorescent lighting as well as light-emitting diode bulbs to phase out and replace conventional incandescent bulbs; and Residential Bundle Program-a bundle of four residential programs to be available to residential customers, including a Residential Home Energy Check-up Program, Residential Duct Testing & Sealing Program, Residential Heat Pump Tune-Up Program and Residential Heat Pump Upgrade Program. |
These factors include but are not limited to: Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, and earthquakes that can cause outages and property damage to facilities; Federal, state and local legislative and regulatory developments; Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances; Cost of environmental compliance, including those costs related to climate change; Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; Unplanned outages of the Companies’ facilities; Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Dominion’s and Virginia Power’s liquidity position and the underlying value of their assets; Counterparty credit and performance risk; Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion; Fluctuations in interest rates; Changes in federal and state tax laws and regulations; Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; Changes in financial or regulatory accounting principles or policies imposed by governing bodies; Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; The risks of operating businesses in regulated industries that are subject to changing regulatory structures; Receipt of approvals for and timing of closing dates for acquisitions and divestitures; Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, pricing rules and rules involving revenue calculations and new and evolving capacity models; Political and economic conditions, including inflation and deflation; Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; Industrial, commercial and residential growth or decline in the Companies’ service areas and changes in customer growth or usage patterns, including as a result of energy conservation programs; Additional competition in electric markets in which Dominion’s merchant generation facilities operate; Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion; Timing and receipt of regulatory approvals necessary for planned construction or expansion projects; The inability to complete planned construction projects within the terms and time frames initially anticipated; and Adverse outcomes in litigation matters. |
VS. 2009 Net Revenue increased 8%, primarily reflecting: A $1.1 billion increase from electric utility operations, primarily reflecting: The absence of a charge for the settlement of Virginia Power’s 2009 base rate case proceedings ($570 million); The impact of rate adjustment clauses ($279 million); An increase in sales to retail customers primarily due to an increase in cooling degree days ($248 million); and An increase in ancillary revenues received from PJM ($78 million), primarily reflecting an increase in the scheduled dispatch of gas and oil-fired generation units to meet higher demand; partially offset by A decrease primarily due to the impact of unfavorable economic conditions on customer usage and other factors ($75 million); A $98 million increase from regulated natural gas distribution operations primarily reflecting increased rider revenue associated with the recovery of bad debt expense ($60 million) and an increase in base rates ($40 million); and A $46 million increase related to natural gas transmission operations largely due to the completion of the Cove Point expansion project. |
The inputs and assumptions used in measuring fair value include the following: For commodity and foreign currency derivative contracts: Forward commodity prices Forward foreign currency prices Price volatility Volumes Commodity location Interest rates Credit quality of counterparties and Dominion and Virginia Power Credit enhancements Time value For interest rate derivative contracts: Interest rate curves Credit quality of counterparties and Dominion and Virginia Power Credit enhancements Time value For investments: Quoted securities prices and indices Securities trading information including volume and restrictions Maturity Interest rates Credit quality NAV (only for alternative investments) Dominion and Virginia Power 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. |
The following items, which are after-tax, are included in Dominion’s 2011 reported earnings, but are excluded from consolidated operating earnings: $178 million impairment charge related to certain utility and merchant coal-fired power stations; $59 million of restoration costs associated with Hurricane Irene; $39 million net loss from operations at Kewaunee, which is being marketed for sale; $34 million impairment of excess emission allowances resulting from a new EPA air pollution rule; $21 million of severance costs and other charges resulting from expected closings of Salem Harbor and State Line; $19 million net charge in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2009-2010 test years; $13 million of earthquake related costs, largely related to inspections following the safe shutdown of reactors at North Anna; $14 million benefit related to litigation with the DOE for spent nuclear fuel-related costs at Millstone and $3 million net benefit related to other items. |
These factors include but are not limited to: Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; Extreme weather events, including hurricanes, high winds and severe storms, that can cause outages and property damage to facilities; Federal, state and local legislative and regulatory developments; Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances; Cost of environmental compliance, including those costs related to climate change; Risks associated with the operation of nuclear facilities; Unplanned outages of the Companies’ facilities; Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Dominion’s and Virginia Power’s liquidity position and the underlying value of their assets; Counterparty credit and performance risk; Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; Risks associated with Virginia Power’s membership and participation in PJM related to obligations created by the default of other participants; Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion; Fluctuations in interest rates; Changes in federal and state tax laws and regulations; Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; Changes in financial or regulatory accounting principles or policies imposed by governing bodies; Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; The risks of operating businesses in regulated industries that are subject to changing regulatory structures; Receipt of approvals for and timing of closing dates for acquisitions and divestitures; Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs and new and evolving capacity models; Political and economic conditions, including the threat of domestic terrorism, inflation and deflation; Industrial, commercial and residential growth or decline in the Companies’ service areas and changes in customer growth or usage patterns, including as a result of energy conservation programs; Additional competition in electric markets in which Dominion’s merchant generation facilities operate; Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion; Timing and receipt of regulatory approvals necessary for planned construction or expansion projects; The inability to complete planned construction projects within the terms and time frames initially anticipated; and Adverse outcomes in litigation matters. |
Analysis of Consolidated Operations Presented below are selected amounts related to Dominion’s results of operations: An analysis of Dominion’s results of operations follows: 2010 VS. 2009 Net Revenue increased 8%, primarily reflecting: A $1.1 billion increase from electric utility operations, primarily reflecting: The absence of a charge for the settlement of Virginia Power’s 2009 base rate case proceedings ($570 million); The impact of Riders C1 and C2, R, S and T ($279 million); An increase in sales to retail customers primarily due to an increase in cooling degree days ($248 million); and An increase in ancillary revenues received from PJM ($78 million), primarily reflecting an increase in the scheduled dispatch of gas and oil-fired generation units to meet higher demand; partially offset by A decrease primarily due to the impact of unfavorable economic conditions on customer usage and other factors ($75 million); A $98 million increase from regulated natural gas distribution operations primarily reflecting increased rider revenue associated with the recovery of bad debt expense ($60 million) and an increase in base rates ($40 million); and A $46 million increase related to natural gas transmission operations largely due to the completion of the Cove Point expansion project. |
The inputs and assumptions used in measuring fair value include the following: For commodity and foreign currency derivative contracts: Forward commodity prices Forward foreign currency prices Price volatility Volumes Commodity location Interest rates Credit quality of counterparties and Dominion and Virginia Power Credit enhancements Time value For interest rate derivative contracts: Interest rate curves Credit quality of counterparties and Dominion and Virginia Power Credit enhancements Time value Combined Notes to Consolidated Financial Statements, Continued For investments: Quoted securities prices Securities trading information including volume and restrictions Maturity Interest rates Credit quality NAV (only for alternative investments) Dominion and Virginia Power 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. |
The 2010 peer group was the same as the 2009 peer group and consisted of the following 14 energy companies: Ameren Corporation American Electric Power Company, Inc. Constellation Energy Group, Inc. DTE Energy Company Duke Energy Corporation Entergy Corporation Exelon Corporation FirstEnergy Corp. NextEra Energy, Inc. (formerly FPL Group, Inc.) NiSource, Inc. PPL Corporation Progress Energy, Inc. Public Service Enterprise Group Inc. Southern Company The CGN Committee, PM&P and management use peer company data to: (i) compare Dominion’s stock and financial performance against its 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, total direct compensation generally and for specific positions; and (iv) compare Employment Continuity Agreements and other benefits. |
These factors include but are not limited to: Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; Extreme weather events, including hurricanes, high winds and severe storms, that can cause outages and property damage to facilities; Federal, state and local legislative and regulatory developments; Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for greenhouse gases and other emissions, more extensive permitting requirements and the regulation of additional substances; Cost of environmental compliance, including those costs related to climate change; Risks associated with the operation of nuclear facilities; Unplanned outages of the Companies’ generation facilities; Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Domin - ion’s and Virginia Power’s liquidity position and the underlying value of their assets; Counterparty credit risk; Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; Risks associated with Virginia Power’s membership and participation in PJM related to obligations created by the default of other participants; Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion; Fluctuations in interest rates; Changes in federal and state tax laws and regulations; Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; Changes in financial or regulatory accounting principles or policies imposed by governing bodies; Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; The risks of operating businesses in regulated industries that are subject to changing regulatory structures; Receipt of approvals for and timing of closing dates for acquisitions and divestitures; Completion and timing of the planned monetization of Dominion’s Marcellus Shale assets; Changes in rules for RTOs in which Dominion and Virginia Power participate, including changes in rate designs and new and evolving capacity models; Political and economic conditions, including the threat of domestic terrorism, inflation and deflation; Changes to regulated electric rates collected by Virginia Power, including the outcome of the base rate review initiated in 2009; Timing and receipt of regulatory approvals necessary for planned construction or expansion projects; The inability to complete planned construction projects within the terms and time frames initially anticipated; and Adverse outcomes in litigation matters. |
Other operations and maintenance expense increased 17%, primarily reflecting the combined effects of: A $455 million ceiling test impairment charge related to the carrying value of E&P properties due to declines in natural gas and oil prices; A $142 million write-off of previously deferred RTO costs in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings; A $74 million increase in salaries, wages and benefits largely due to higher pension and other postretirement benefit costs; and A $69 million increase reflecting the absence of the net benefit recorded in 2008 related to the re-establishment of a regulatory asset in connection with the planned sale of Peoples and Hope ($47 million) and a 2009 charge due to a reduction in this regulatory asset ($22 million); partially offset by A $103 million downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service; The absence of a $59 million charge related to the impairment of a DCI investment sold in 2008; and A $29 million decrease largely due to the deferral of transmission-related expenditures collectible under certain rate adjustment clauses. |
2008 VS. 2007 Net Revenue increased 6%, primarily reflecting: A $500 million increase from merchant generation operations, primarily reflecting higher realized sales prices for nuclear and fossil operations ($500 million) and the absence of a charge related to the termination of a long-term power sales agreement at State Line in 2007 ($231 million), partially offset by lower overall sales volumes due to outages at certain fossil and nuclear generating facilities ($105 million), increased fuel expenses primarily reflecting the impact of higher commodity prices ($54 million) and increased fuel consumption ($72 million) at certain fossil generation facilities; A $453 million increase in net revenue from electric utility operations resulting primarily from the reinstatement of annual fuel rate adjustments, effective July 1, 2007, for the Virginia jurisdiction of Virginia Power’s generation operations, with deferred fuel accounting for over- or under-recoveries of fuel costs; and Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued A $129 million increase in sales of gas production from Dominion’s remaining E&P operations, primarily due to: A $70 million increase in sales from Appalachian properties due to higher prices ($51 million) and increased production ($19 million); and Increased production associated with VPP royalty interests ($59 million). |
Dominion’s anticipated 2010 results reflect the following significant factors: The absence of an impairment charge in 2009 related to the carrying value of Dominion’s E&P properties due to declines in gas and oil prices; The absence of a charge in 2009 in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings; A benefit from rate adjustment clauses associated with the recovery of construction-related financing costs for Bear Garden and Virginia City Hybrid Energy Center; Minimal exposure to commodity prices reflecting hedges in place due to Dominion’s commodities hedging program; Favorable interest rates reflecting hedges in place for Dominion’s and Virginia Power’s planned debt issuances in 2010; The planned monetization of Dominion’s Marcellus Shale acreage with proceeds used to offset its anticipated 2010 equity financing needs; Implementation of operations and maintenance cost-containment measures; and An expected after-tax loss, as well as after-tax expenses, including transaction and benefit-related costs, in connection with the February 2010 sale of Peoples discussed in Note 4 to the Consolidated Financial Statements. |
Dominion executed Replacement Capital Covenants (RCCs) in connection with its issuance of the following hybrid securities: $300 million of 2006 Series A Enhanced Junior Subordinated Notes due 2066 (June 2006 hybrids) $500 million of 2006 Series B Enhanced Junior Subordinated Notes due 2066 (September 2006 hybrids) $685 million of 2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to maturity extensions to no later than 2079 (June 2009 hybrids) Under the terms of the RCCs, Dominion promises and 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 the respective RCC termination date, 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. |
PM&P provided the following services related to the 2009 executive compensation program: performed a detailed review of base salary plus annual bonus potential (total cash compensation), the value of targeted long-term incentives, and total direct compensation (the sum of total cash and targeted long-term incentive compensation) for the NEOs, and provided a full report to the CGN Committee on its findings; participated in the selection of the peer companies, providing independent advice to the CGN Committee on the process used to select the peer group and the appropriateness of the peer group; participated in CGN Committee executive sessions without management present to discuss CEO compensation and any other relevant matters, including the appropriate relationship between pay and performance and emerging trends, to answer technical questions, and to review and comment on management proposals and analyses of compensation data; and generally reviewed and offered advice as requested by or on behalf of the CGN Committee regarding other aspects of the executive compensation program, including special projects, best practices and other matters. |
ELEMENTS OF DOMINION’S COMPENSATION PROGRAM The executive compensation program consists of four basic elements: Pay Element Primary Objectives Key Features & Behavioral Focus Base Salary Provide competitive level of fixed cash compensation for performing day-to-day responsibilities Attract and retain talent Targeted at market median with adjustments based on internal equity and other Company considerations Rewards individual performance and level of experience Annual Incentive Plan Provide competitive level of at-risk cash compensation for achievement of short-term financial and operational goals Align short-term compensation with the annual budget, earnings goals, business plans and core values Cash payments based on achievement of annual financial and individual operating and stewardship goals Rewards achievement of annual financial goals for Dominion and business unit and individual goals selected to support longer-term strategies Long-Term Incentive Program Provide competitive level of at-risk compensation for achievement of long-term performance goals Create long-term shareholder value Retain talent A combination of performance-based cash and restricted stock awards (for 2009, a 50/50 mix) Encourages and rewards officers for making decisions and investments that create long-term shareholder value as reflected in superior relative TSR, as well as achieving desired returns on invested capital and BVP Employee and Executive Benefits Provide competitive retirement and other benefit programs that attract and retain highly-qualified individuals Provide competitive terms to encourage officers to remain with Dominion during any potential change in control to ensure an orderly transition of management Dominion-wide benefit programs, supplemented by executive retirement plans, limited perquisites, and change in control and other agreements Encourages officers to remain with Dominion long-term and to act in the best interest of shareholders, even during any potential change in control Factors in Setting Compensation In setting compensation for 2009, Dominion did not follow the same process it has followed in recent years due to volatile market conditions and budget considerations. |
The Virginia Commission approved a settlement proposed by us and other parties, which provided for the following effective July 1, 2008: i) an increase of our fuel tariff to 3.893 cents per kWh for the collection of the current period and partial recovery of the prior year under-recovered fuel balance; ii) the recovery of $231 million of the approximately $697 million prior year under-recovered fuel balance, with the balance to be recovered in subsequent fuel periods as provided by Virginia law; iii) the fuel tariff of 3.893 cents per kWh is estimated to result in an under-recovery of $231 million of projected fuel expenses during the current period; and iv) we will not propose to recover a return or interest or any other form of carrying costs on the balance of uncollected fuel expenses described in subsection (ii) above, including the estimated $231 million under-recovery of current period expenses described in subsection (iii), provided that the total amount on which we will not propose to recover interest or any other form of carrying costs is limited to $697 million. |
These factors include but are not limited to: Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; Extreme weather events, including hurricanes and winter storms, that can cause outages and property damage to our facilities; State and federal legislative and regulatory developments and changes to environmental and other laws and regulations, including those related to climate change, GHG emissions and other emissions to which we are subject; Cost of environmental compliance, including those costs related to climate change; Risks associated with the operation of nuclear facilities; Fluctuations in energy-related commodity prices and the effect these could have on our earnings, liquidity position and the underlying value of our assets; Counterparty credit risk; Capital market conditions, including price risk due to marketable securities held as investments in nuclear decommissioning and benefit plan trusts; Fluctuations in interest rates; Changes in federal and state tax laws and regulations; Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; Changes in financial or regulatory accounting principles or policies imposed by governing bodies; Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; The risks of operating businesses in regulated industries that are subject to changing regulatory structures; Receipt of approvals for and timing of closing dates for acquisitions and divestitures; Changes in rules for RTOs in which we participate, including changes in rate designs and new and evolving capacity models; Political and economic conditions, including the threat of domestic terrorism, inflation and deflation; Changes to rates for our regulated electric utility operations, including the outcome of our 2009 base rate review, and the timing of such collection as it relates to fuel costs; Timing and receipt of regulatory approvals necessary for planned construction or expansion projects; The inability to complete planned construction projects within the terms and time frames initially anticipated; Completing the divestiture of Peoples and Hope; and Adverse outcomes in litigation matters. |
2008 VS. 2007 Operating Revenue increased 10% to $16.3 billion, primarily reflecting: A $753 million increase in revenue from our electric utility operations resulting primarily from an increase in fuel revenue largely due to the impact of a comparatively higher fuel rate in certain customer jurisdictions; A $626 million increase from merchant generation operations, primarily reflecting higher realized prices for nuclear and fossil operations ($500 million) and the absence of a charge related to the termination of a long-term power sales agreement at State Line in 2007 ($231 million), partially offset by lower overall volumes due to outages at certain fossil and nuclear generating facilities ($105 million); A $330 million increase in our producer services business primarily as a result of higher realized prices for natural gas aggregation activities and favorable price changes associated with natural gas trading activities; A $129 million increase in sales of gas production from our remaining E&P operations, primarily due to: A $70 million increase in sales from our Appalachian properties due to higher prices ($51 million) and increased production ($19 million); and Increased production associated with reacquired overriding royalty interests arising from the VPPs terminated in 2007 ($59 million); A $133 million increase in regulated gas sales attributable to our gas distribution operations primarily resulting from the impact of higher prices; A $131 million increase in nonregulated gas sales by our gas distribution operations, primarily due to the sale of gas inventory by Dominion East Ohio related to its plan to exit the gas merchant function in Ohio and have all customers select an alternate gas supplier; A $117 million increase in gas sales by retail energy marketing operations primarily due to higher prices; A $109 million increase in gas transportation and storage revenue primarily due to a $66 million increase in revenue from our gas distribution operations due to higher prices ($52 million) and increased volumes ($14 million) and a $43 million increase attributable to our gas transmission operations primarily reflecting increased transport and storage activities and gathering and extraction services; A $76 million increase in electricity sales by retail energy marketing operations due to higher sales prices ($54 million) and the acquisition of an additional retail business in September 2008 ($69 million), partially offset by lower volumes ($47 million); and A $44 million increase in sales of extracted products from our gas transmission operations as a result of higher realized prices; These increases were partially offset by: A $716 million decrease due to the sale of the majority of our U.S. E&P operations in 2007, reflecting the absence of $1.4 billion of revenue from these operations, partially offset by the absence of a $541 million charge predominantly due to the discontinuance of hedge accounting for certain gas and oil derivatives and subsequent changes in the fair value of these derivatives; and a $171 million charge primarily due to the termination of VPP agreements in connection with the sale; and A $179 million decrease in nonutility coal sales primarily related to exiting this activity. |
2007 VS. 2006 Operating Revenue decreased 14% to $14.8 billion, primarily reflecting: A $665 million decrease in our producer services business largely due to the net impact of a decrease in economic hedging activity ($612 million) and a decrease in physical realized prices ($113 million), partially offset by an increase in physical realized volumes ($60 million), all associated with natural gas aggregation and marketing activities; A $632 million decrease in sales of gas and oil production primarily due to lower volumes due to the sale of our U.S. non-Appalachian E&P business; A $541 million decrease predominantly due to the discontinuance of hedge accounting for certain gas and oil derivatives and subsequent changes in the fair value of these derivatives as a result of the sale of our U.S. non-Appalachian E&P business; A $422 million decrease in revenue from sales of oil purchased by E&P operations, primarily due to the impact of netting sales and purchases of oil under buy/sell arrangements associated with the implementation of EITF 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, in 2006, as discussed in Note 3 to our Consolidated Financial Statements; A $309 million decrease in nonutility coal sales, primarily from reduced sales volumes ($281 million) related to exiting certain sales activities and lower prices ($28 million); A $273 million decrease reflecting the absence of business interruption insurance revenue received in 2006, associated with the 2005 hurricanes; A $231 million charge related to the termination of a long-term power sales agreement at State Line; A $222 million decrease in regulated gas sales by our gas distribution operations reflecting the combined effects of: A $185 million decrease reflecting lower gas prices; and A $198 million decrease resulting from the migration of customers to energy choice programs; partially offset by A $161 million increase in volumes due to an increase in the number of heating degree days, primarily in the first quarter of 2007, and changes in customer usage patterns and other factors; A $171 million decrease primarily due to the termination of VPP agreements as a result of the sale of our U.S. non-Appalachian E&P business. |
As compared to the prior year, we experienced a 15% increase in cooling degree days and a 10% increase in heating degree days; An $80 million increase in sales to wholesale customers; and A $42 million increase resulting primarily from higher ancillary service revenue reflecting higher regulation and operating reserves revenue received from PJM; A $508 million increase for merchant generation operations, primarily reflecting higher realized prices for nuclear and fossil operations ($354 million), including higher capacity revenue associated with new capacity markets in ISO New England and PJM, and increased volumes for fossil operations ($154 million); A $139 million increase in gas sales by retail energy marketing operations due to increased customer accounts ($189 million), partially offset by lower contracted sales prices ($50 million); and An $88 million increase in gas transportation and storage revenue primarily attributable to our gas distribution operations due to increased volumes and higher prices. |
Report of Independent Registered Public Accounting Firm Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006 Consolidated Balance Sheets at December 31, 2008 and 2007 Consolidated Statements of Common Shareholders’ Equity at December 31, 2008, 2007 and 2006 and for the years then ended Consolidated Statements of Comprehensive Income at December 31, 2008, 2007 and 2006 and for the years then ended Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006 Notes to Consolidated Financial Statements REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Dominion Resources, Inc. Richmond, Virginia We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, common shareholders’ equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. |
The Virginia Commission approved a settlement proposed by us and other parties, which provided for the following, effective July 1, 2008: i) an increase of our fuel tariff to 3.893 cents per kWh for the collection of the current period and partial recovery of the prior year under-recovered fuel balance; ii) the recovery of $231 million of the approximately $697 million prior year under-recovered fuel balance, with the balance to be recovered in subsequent fuel periods as provided by Virginia law; iii) the fuel tariff of 3.893 cents per kWh is estimated to result in an under-recovery of $231 million of projected fuel expenses during the current period; and iv) we will not propose to recover a return or interest or any other form of carrying costs on the balance of uncollected fuel expenses described in subsection (ii) above, including the estimated $231 million under-recovery of current period expenses described in subsection (iii), provided that the total amount on which we will not propose to recover interest or any other form of carrying costs is limited to $697 million. |
These factors include but are not limited to: Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; Extreme weather events, including hurricanes and winter storms, that can cause outages and property damage to our facilities; State and federal legislative and regulatory developments and changes to environmental and other laws and regulations, including those related to climate change, to which we are subject; Cost of environmental compliance, including those costs related to climate change; Risks associated with the operation of nuclear facilities; Fluctuations in energy-related commodity prices and the effect these could have on our earnings, liquidity position and the underlying value of our assets; Counterparty credit risk; Capital market conditions, including price risk due to marketable securities held as investments in nuclear decommissioning and benefit plan trusts; Fluctuations in interest rates; Changes in federal and state tax laws and regulations; Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; Changes in financial or regulatory accounting principles or policies imposed by governing bodies; Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; The risks of operating businesses in regulated industries that are subject to changing regulatory structures; Receipt of approvals for and timing of closing dates for acquisitions and divestitures; Changes in rules for regional transmission organizations (RTOs) in which we participate, including changes in rate designs and new and evolving capacity models; Political and economic conditions, including the threat of domestic terrorism, inflation and deflation; The inability to complete planned construction projects within the terms and time frames initially anticipated; and Completing the divestiture of the Peoples Natural Gas Company (Peoples) and Hope Gas, Inc. (Hope), and the disposition of investments held by our financial services subsidiary, Dominion Capital, Inc. (DCI). |
These FTRs are used to offset congestion costs associated with PJM spot market activity, which are included in Electric fuel and energy purchases expense; A $35 million increase in generation-related outage costs primarily due to an increase in the number of scheduled outages; A $29 million increase related to major storm damage and service restoration costs associated with our distribution operations, including costs resulting from tropical storm Ernesto in September 2006; A $27 million charge resulting from the cancellation of a pipeline project; These increases were partially offset by: A $96 million decrease in hedge ineffectiveness expense associated with our E&P operations, primarily due to a decrease in the fair value differential between the delivery location and commodity specifications of derivative contracts held by us as compared to our forecasted gas and oil sales and the increased use of basis swaps; A $62 million benefit resulting from favorable changes in the fair value of certain gas and oil derivatives that were de-designated as hedges following the 2005 hurricanes; A benefit resulting from the absence of the following items recognized in 2005: A $423 million loss related to the discontinuance of hedge accounting for certain gas and oil derivatives resulting from an interruption of gas and oil production in the Gulf of Mexico caused by the 2005 hurricanes; A $77 million charge resulting from the termination of a long-term power purchase agreement; A $59 million loss related to the discontinuance of hedge accounting for certain oil derivatives primarily resulting from a delay in reaching anticipated production levels in the Gulf of Mexico, and subsequent changes in the fair value of those derivatives; and A $51 million charge related to credit exposure associated with the bankruptcy of Calpine Corporation; partially offset by A $24 million net benefit resulting from the establishment of certain regulatory assets and liabilities in connection with the settlement of a North Carolina rate case in the first quarter of 2005. |
n After the initial rate case, review base rates biennially, as a result of which the Virginia Commission: n establishes an ROE no lower than that reported by a group of utilities within the southeastern U.S., with certain limitations on earnings and rate adjustments; however, if the Virginia Commission finds that such ROE limit at that time exceeds the ROE set at the time of the initial base rate case in 2009 by more than the percentage increase in the Consumer Price Index in the interim, it may reduce that lower ROE limit to a level that increases the initial ROE by only as much as the change in the Consumer Price Index; n shall increase base rates, if needed, to allow the utility the opportunity to recover its costs and earn a fair rate of return if the utility is found to have earnings more than 50 basis points below the established ROE; n may order a credit to customers if the utility is found to have earnings more than 50 basis points above the established ROE, and reduce rates if the utility is found to have such excess earnings during two consecutive biennial review periods; and n may authorize performance incentives if appropriate. |
These factors include but are not limited to: n Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; n Extreme weather events, including hurricanes and winter storms, that can cause outages, production delays and property damage to our facilities; n State and federal legislative and regulatory developments, including a movement towards a hybrid form of regulation, and changes to environmental and other laws and regulations to which we are subject; n Cost of environmental compliance; n Risks associated with the operation of nuclear facilities; n Fluctuations in energy-related commodity prices and the effect these could have on our earnings, liquidity position and the underlying value of our assets; n Counterparty credit risk; n Capital market conditions, including price risk due to marketable securities held as investments in nuclear decommissioning and benefit plan trusts; n Fluctuations in interest rates; n Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; n Changes in financial or regulatory accounting principles or policies imposed by governing bodies; n Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; n The risks of operating businesses in regulated industries that are subject to changing regulatory structures; n Changes in our ability to recover investments made under traditional regulation through rates; n Receipt of approvals for and timing of closing dates for acquisitions and divestitures, including our divestiture of The Peoples Natural Gas Company (Peoples) and Hope Gas, Inc. (Hope) and any divestiture of our exploration and production (E&P) business; n Risks associated with any realignment of our operating assets, including the potential dilutive effect on earnings in the near term, costs associated with any sale of our E&P business and the costs and reinvestment risks related to deployment of proceeds from any sale; n Political and economic conditions, including the threat of domestic terrorism, inflation and deflation; n Completing the divestiture of investments held by our financial services subsidiary, Dominion Capital, Inc. (DCI); n Additional risk exposure associated with the termination of business interruption and offshore property damage insurance related to our E&P operations and our inability to replace such insurance on commercially reasonable terms; and n Changes in rules for regional transmission organizations (RTOs) in which we participate, including changes in rate designs and new and evolving capacity models. |
The effect of this increase is offset by a corresponding increase in Operating Revenue; n A $166 million charge from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope; n A $105 million increase attributable to higher production handling, transportation and operating costs related to E&P operations; n A $97 million increase resulting primarily from higher salaries, wages and benefits expenses; n $91 million of impairment charges related to DCI investments; n A $79 million increase resulting from Kewaunee, which was acquired in July 2005; n A $65 million decrease in gains from the sale of emissions allowances held for consumption; n A $60 million charge to eliminate the application of hedge accounting for certain interest rate swaps associated with our junior subordinated notes payable to affiliated trusts that sold trust preferred securities; n A $41 million reduction in proceeds related to financial transmission rights (FTRs) granted by PJM to our utility generation operations. |
These FTRs are used to offset congestion costs associated with PJM spot market activity, which are included in Electric fuel and energy purchases expense; n A $35 million increase in generation-related outage costs primarily due to an increase in the number of scheduled outages; n A $29 million increase related to major storm damage and service restoration costs associated with our distribution operations, primarily resulting from tropical storm Ernesto in September 2006; n A $27 million charge resulting from the cancellation of a pipeline project; These increases were partially offset by: n A $62 million benefit resulting from favorable changes in the fair value of certain gas and oil derivatives that were de-designated as hedges following the 2005 hurricanes; n A $96 million decrease in hedge ineffectiveness expense associated with our E&P operations, primarily due to a decrease in the fair value differential between the delivery location and commodity specifications of derivative contracts held by us as compared to our forecasted gas and oil sales and the increased use of basis swaps; n A benefit resulting from the absence of the following items recognized in 2005: n A $423 million loss related to the discontinuance of hedge accounting for certain gas and oil hedges resulting from an interruption of gas and oil production in the Gulf of Mexico caused by the 2005 hurricanes; n A $77 million charge resulting from the termination of a long-term power purchase agreement; n A $59 million loss related to the discontinuance of hedge accounting for certain oil derivatives primarily resulting from a delay in reaching anticipated production levels in the Gulf of Mexico, and subsequent changes in the fair value of those derivatives; and n A $51 million charge related to credit exposure associated with the bankruptcy of Calpine Corporation; partially offset by n A $24 million net benefit resulting from the establishment of certain regulatory assets and liabilities in connection with the settlement of a North Carolina rate case in the first quarter of 2005. |
Other operations and maintenance expense increased 11% to $3.1 billion, resulting from: n A $423 million loss related to the discontinuance of hedge accounting for certain gas and oil hedges resulting from an interruption of gas and oil production in the Gulf of Mexico caused by the 2005 hurricanes; n A $361 million increase due to the addition of Dominion New England and Kewaunee and a full year of commercial operations at Fairless; n A $193 million increase in salaries and benefits, due to higher incentive-based compensation ($106 million), wages ($43 million) and pension and medical benefits ($44 million); n A $77 million charge resulting from the termination of a long-term power purchase agreement; n A $75 million increase in hedge ineffectiveness expense associated with E&P operations, primarily due to an increase in the fair value differential between the delivery location and commodity specifications of our derivative contracts and the delivery location and commodity specifications of our forecasted gas and oil sales; n A $59 million loss related to the discontinuance of hedge accounting in March 2005 for certain oil hedges primarily resulting from a delay in reaching anticipated production levels in the Gulf of Mexico, and subsequent changes in the fair value of those hedges; n A $51 million charge related to credit exposure associated with the bankruptcy of Calpine Corporation; n A $35 million charge related to our investment in and planned divestiture of DCI assets; These increases were partially offset by the following: n A $344 million decrease related to the designation of certain commodity derivative contracts as held for non-trading purposes effective January 1, 2005, which were previously held for trading purposes as discussed in Operating Revenue; n A $186 million benefit related to FTRs; n A $139 million gain resulting from the sale of emissions allowances held for consumption; n A $24 million net benefit resulting from the establishment of certain regulatory assets and liabilities in connection with the settlement of a North Carolina rate case in the first quarter of 2005; and n The net impact of the following items recognized in 2004: n A $184 million charge related to the sale of our interest in a long-term power tolling contract in connection with our exit from certain energy trading activities; n A $96 million loss related to the discontinuance of hedge accounting for certain oil hedges resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges during the third quarter; n A $72 million charge associated with the impairment of retained interests from mortgage securitizations and venture capital and other equity investments held by DCI; and n A $71 million net charge resulting from the termination of certain long-term power purchase agreements; partially offset by n A $120 million benefit due to favorable changes in the fair value of certain oil options related to E&P operations. |
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