ITEM 1. BUSINESS
THE COMPANY
Virginia Electric and Power Company is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. In Virginia, we conduct business under the name “Dominion Virginia Power.” In North Carolina, we conduct business under the name “Dominion North Carolina Power” and serve retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, we sell electricity at wholesale to rural electric cooperatives, municipalities and into wholesale electricity markets. The terms “Company,” “we,” “our” and “us” are used in this report and, depending on the context of their use, may refer to Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Electric and Power Company, including all of its consolidated subsidiaries.
All of our common stock is owned by our parent company, Dominion Resources, Inc. (Dominion), a fully integrated gas and electric holding company.
As of December 31, 2006, we had approximately 6,900 full-time employees. Approximately 3,200 employees are subject to collective bargaining agreements.
We were incorporated in 1909 as a Virginia public service corporation. Our principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and our telephone number is (804) 819-2000.
OPERATING SEGMENTS
We manage our operations through three primary operating segments: Delivery, Energy and Generation. We also report corporate and other functions as a segment. While we manage our daily operations as described below, our assets remain wholly owned by us and our legal subsidiaries. For additional financial information on business segments and geographic areas, including revenues from external customers, see Notes 1 and 25 to our Consolidated Financial Statements. For additional information on operating revenue related to our principal products and services, see Note 5 to our Consolidated Financial Statements.
Delivery
Delivery includes our electric distribution and customer service businesses. Electric distribution operations serve residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina.
COMPETITION
Within Delivery’s service territory in Virginia and North Carolina, there is no competition for electric distribution service.
REGULATION
Delivery’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia State Corporation Commission (Virginia Commission) and the North Carolina Utilities Commission (North Carolina Commission). See Regulation-State Regulations for additional information.
PROPERTIES
The Delivery segment’s electric distribution network includes approximately 55,000 miles of distribution lines, exclusive of
service level lines in Virginia and North Carolina. The rights-of-way grants for most of our electric lines have been obtained from the apparent owner of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.
SOURCES OF ENERGY SUPPLY
Delivery’s supply of electricity to serve retail customers is produced or procured by the Generation segment. See Generation for additional information.
SEASONALITY
Delivery’s business varies seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for electricity to meet cooling and heating needs.
Energy
Energy includes our regulated electric transmission system serving Virginia and northeastern North Carolina. In 2005, we became a member of PJM Interconnection, LLC (PJM), a regional transmission organization (RTO), and integrated our electric transmission facilities into the PJM wholesale electricity markets.
COMPETITION
Since the integration of our electric transmission facilities into PJM, our electric transmission services are administered by PJM and are no longer subject to competition in relation to transmission service provided to customers within the PJM region.
REGULATION
Energy’s electric transmission rates, tariffs and terms of service are subject to regulation by the Federal Energy Regulatory Commission (FERC). Electric transmission siting authority remains the exclusive jurisdiction of the Virginia and North Carolina Commissions. However, the Energy Policy Act of 2005 (EPACT) provides FERC with certain limited backstop authority for transmission siting, the implications of which remain unclear. See Regulation-State Regulations and Regulation-Federal Regulations for additional information.
PROPERTIES
The Energy segment has approximately 6,000 miles of electric transmission lines of 69 kilovolt (kV) or more located in the states of North Carolina, Virginia and West Virginia. Portions of the electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines.
While we continue to own and maintain these electric transmission facilities, they are now a part of PJM, which coordinates the planning, operation, emergency assistance, and exchanges of capacity and energy for such facilities.
Each year, as part of PJM’s Regional Transmission Expansion Plan (RTEP) process, reliability projects are authorized. In June 2006, PJM, through the RTEP process, authorized construction of numerous electric transmission upgrades through 2011. We are involved in two of the major construction projects. The first project is an approximately 270-mile 500-kV transmission line from southwestern Pennsylvania to Virginia, of which we will construct approximately 70 miles in Virginia and a subsidiary of Allegheny Energy, Inc. will construct the remainder. The second project is
an approximately 56-mile 500-kV transmission line that we will construct in southeastern Virginia. These transmission upgrades are designed to improve the reliability of service to our customers and the region. The siting and construction of these transmission lines will be subject to applicable state and federal permits and approvals.
SEASONALITY
Energy’s business varies seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for electricity to meet cooling and heating needs.
Generation
Generation includes our portfolio of electric generation facilities, power purchase agreements and our energy supply operations. Our electric generation operations serve customers in Virginia and northeastern North Carolina. Our generation facilities are located in Virginia, West Virginia and North Carolina. Our energy supply operations are responsible for managing energy and capacity needs for our utility system resources.
COMPETITION
For our electric generation operations, retail choice has been available for our Virginia jurisdictional electric customers since January 1, 2003; however, to date, competition in Virginia has not developed to any significant extent. See Regulation-State Regulations. Currently, North Carolina does not offer retail choice to electric customers.
REGULATION
The operations of our Generation segment are subject to regulation by the Virginia Commission, the North Carolina Commission, FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA), the Department of Energy (DOE), the Army Corps of Engineers and other federal, state and local authorities.
PROPERTIES
For a listing of our current generation facilities, see Item 2. Properties.
Based on available generation capacity and current estimates of growth in customer demand, we will need additional generation in the future. We currently have plans to restart our Hopewell plant in 2007, a 63-megawatt (Mw) (at net summer capability) coal burning plant located in Hopewell, Virginia which has been out of service since 2002, and we are evaluating a 290-Mw (at net summer capability) expansion of our Ladysmith site in Ladysmith, Virginia. We are also leading a consortium of companies that are considering building a 500 to 600-Mw coal-fired plant in southwest Virginia. We will continue to evaluate the development of new plants to meet customer demand for additional generation needs in the future.
SOURCES OF ENERGY SUPPLY
Generation uses a variety of fuels to power our electric generation, as described below. See Segment Results of Operations-Generation in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation (MD&A) for a summary of our generation output by energy source.
Nuclear Fuel-Generation primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel
supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.
Fossil Fuel-Generation primarily utilizes coal, oil and natural gas in its fossil fuel plants. Generation’s coal supply is obtained through long-term contracts and short-term spot agreements.
Generation’s natural gas and oil supply is obtained from various sources including: purchases from major and independent producers in the Mid-Continent and Gulf Coast regions; purchases from local producers in the Appalachian area; purchases from gas marketers; and withdrawals from underground storage fields owned by Dominion or third parties. Generation manages a portfolio of natural gas transportation contracts (capacity) that allows flexibility in delivering natural gas to our gas turbine fleet, while minimizing costs.
SEASONALITY
Sales of electricity for the Generation segment vary seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for electricity to meet cooling and heating needs.
NUCLEAR DECOMMISSIONING
Generation has four licensed, operating nuclear reactors at its Surry and North Anna plants in Virginia that serve our customers. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power plant once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers and placed into trusts have been invested to fund the expected future costs of decommissioning the Surry and North Anna units.
The total estimated cost to decommission our four nuclear units is $1.8 billion in 2006 dollars and is primarily based upon site-specific studies completed in 2006. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. We expect to decommission the Surry and North Anna units during the period 2032 to 2059.
Corporate
We also have a Corporate segment. Corporate includes our corporate and other functions and specific items attributable to our operating segments that have been excluded from the profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments. Also included in the Corporate segment are the discontinued operations of Virginia Power Energy Marketing, Inc. (VPEM), previously a subsidiary, that was transferred to Dominion in December 2005. See Notes 1, 8 and 25 to our Consolidated Financial Statements.
REGULATION
We are subject to regulation by the Virginia Commission, the North Carolina Commission, the Securities and Exchange Commission (SEC), FERC, the EPA, the DOE, the NRC, the Army Corps of Engineers and other federal, state and local authorities.
State Regulations
We are subject to regulation by the Virginia Commission and the North Carolina Commission. We hold certificates of public convenience and necessity which authorize us to maintain and operate our electric facilities now in operation and to sell electricity to customers. However, we may not construct or incur financial commitments for construction of any substantial generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies. In addition, the Virginia Commission and the North Carolina Commission regulate our transactions with affiliates, transfers of certain facilities and issuance of securities.
Rates
Historically, our rates have been based on the cost of providing traditional bundled electric service (i.e., the combination of transmission, distribution and generation services). As a result of the Virginia Electric Utility Restructuring Act enacted in 1999 (1999 Virginia Restructuring Act), in Virginia, rates have been transitioning to unbundled cost-based rates for transmission and distribution services, and to market pricing for generation services, including retail choice for our customers. In North Carolina, rates are still based on the cost of providing traditional bundled electric service; however, our base rates are currently subject to a rate moratorium as described below.
The following is a discussion of our current rate structure; however, such structure is subject to change under proposed new restructuring legislation described under Status of Electric Restructuring in Virginia.
Virginia-We provide retail electric service in Virginia at unbundled rates. Our base rates are capped at 1999 levels until the sooner of (1) the end of a transition period (now December 31, 2010) or (2) a Virginia Commission order finding that a competitive market for generation exists in the Commonwealth. In 2004, the Virginia fuel factor statute was amended to lock in our fuel factor provisions until the earlier of July 1, 2007 or the termination of capped rates, with no adjustment for previously incurred over-recovery or under-recovery of fuel costs, thus eliminating deferred fuel accounting for the Virginia jurisdiction. However, in May 2006, Virginia law was amended to modify the way our Virginia jurisdictional fuel factor is set during the three and one-half year period beginning July 1, 2007. The bill became law effective July 1, 2006 and:
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Allows annual fuel rate adjustments for three twelve-month periods beginning July 1, 2007 and one six-month period beginning July 1, 2010 (unless capped rates are terminated earlier under the 1999 Virginia Restructuring Act);
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Allows an adjustment at the end of each of the twelve-month periods to account for differences between projections and actual recovery of fuel costs during the prior twelve months (thus allowing deferred fuel accounting for these periods); and
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Authorizes the Virginia Commission to defer up to 40% of any fuel factor increase approved for the first twelve-month period, with recovery of the deferred amount over the two and one-half year period beginning July 1, 2008 (under prior law, such a deferral was not possible).
Fuel prices have increased considerably since our Virginia fuel factor provisions were frozen in 2004, which has resulted in our fuel expenses being significantly in excess of our rate recovery. We expect that fuel expenses will continue to exceed rate recovery until our fuel factor is adjusted in July 2007. While the 2006 amendments do not allow us to collect any unrecovered fuel expenses that were incurred prior to July 1, 2007, once our fuel factor is adjusted, the risk of under-recovery of prudently incurred fuel costs until July 1, 2010 is greatly diminished.
North Carolina-In connection with the North Carolina Commission’s approval of Dominion’s acquisition of Consolidated Natural Gas Company (CNG) in 2000, we agreed not to request an increase in North Carolina retail electric base rates before 2006, except for certain events that would have a significant financial impact on our operations. However, in 2004, the North Carolina Commission commenced an investigation into our North Carolina base rates and subsequently ordered us to file a general rate case to show cause why our North Carolina jurisdictional base rates should not be reduced. The rate case was filed in September 2004, and in March 2005, the North Carolina Commission approved a settlement that included a prospective $12 million reduction in current base rates and a five-year base rate moratorium, effective as of April 2005. Fuel rates are still subject to change under the annual fuel cost adjustment proceedings.
Status of Electric Restructuring in Virginia
1999 VIRGINIA RESTRUCTURING ACT
The 1999 Virginia Restructuring Act established a plan to restructure the electric utility industry in Virginia. In general, this legislation provided for a transition from bundled cost-based rates for regulated electric service to unbundled cost-based rates for transmission and distribution services and to market pricing for generation services, including retail choice for our customers. The 1999 Virginia Restructuring Act addressed capped base rates, RTO participation, retail choice, stranded costs recovery and functional separation of an electric utility’s generation from its transmission and distribution operations.
Retail choice was made available to all of our Virginia regulated electric customers, commencing on January 1, 2003. We have separated our generation, distribution and transmission functions through the creation of divisions. State regulatory requirements ensure that our generation division and other divisions operate independently and prevent cross-subsidies between our generation division and other divisions. Additionally, in 2005, we became a member of PJM, an RTO, and have integrated our electric transmission facilities into the PJM wholesale electricity markets. Under the 1999 Virginia Restructuring Act, our base rates have been capped until December 31, 2010, unless modified earlier as previously discussed in Rates.
2004 amendments to the 1999 Virginia Restructuring Act addressed a minimum stay exemption program, a wires charge exemption program and the development of a coal-fired generating plant in southwest Virginia.
2007 VIRGINIA RESTRUCTURING ACT AMENDMENTS
In February 2007, both houses of the Virginia General Assembly passed identical bills that would significantly change electricity restructuring in Virginia. The bills would end capped rates two years early, on December 31, 2008. After capped rates end, retail choice would be eliminated for all but individual retail customers with a demand of more than 5-Mw and a limited number of non-residential retail customers whose aggregated load would exceed 5-Mw. Also after the end of capped rates, the Virginia Commis -
sion would set the base rates of investor-owned electric utilities under a modified cost-of-service model. Among other features, the currently proposed model would provide for the Virginia Commission to:
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Initiate a base rate case for each utility during the first six months of 2009, as a result of which the Virginia Commission:
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establishes a return on equity (ROE) no lower than that reported by a group of utilities within the southeastern United States (U.S.), with certain limitations on earnings and rate adjustments;
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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;
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may reduce rates or, alternatively, order a credit to customers if the utility is found to have earnings more than 50 basis points above the established ROE; and
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may authorize performance incentives if appropriate.
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After the initial rate case, review base rates biennially, as a result of which the Virginia Commission:
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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;
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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;
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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
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may authorize performance incentives if appropriate.
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Authorize stand-alone rate adjustments for recovery of certain costs, including new generation projects, major generating unit modifications, environmental compliance projects, FERC-approved costs for transmission service, energy efficiency and conservation programs, and renewable energy programs; and
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Authorize an enhanced ROE as a financial incentive for construction of major baseload generation projects and for renewable energy portfolio standard programs.
The bills would also continue statutory provisions directing us to file annual fuel cost recovery cases with the Virginia Commission beginning in 2007 and continuing thereafter. However, our fuel factor increase as of July 1, 2007 would be limited to an amount that results in residential customers not receiving an increase of more than 4% of total rates as of that date, and the remainder would be deferred and collected over three years, as follows:
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in calendar year 2008, the deferral portion collected is limited to an amount that results in residential customers not receiving an increase of more than 4% of total rates as of January 1, 2008;
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in calendar year 2009, the deferral portion collected is limited to an amount that results in residential customers not receiving an increase of more than 4% of total rates as of January 1, 2009; and
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the remainder of the deferral balance, if any, would be collected in the fuel factor in calendar year 2010.
The Governor has until March 26, 2007 to sign, propose amendments to, or veto the bills. With the Governor’s signature, the bills would become law effective July 1, 2007. At this time, we cannot predict the outcome of these legislative proposals.
Retail Access Pilot Programs
Three retail access pilot programs were approved by the Virginia Commission in 2003, and continue to be available to customers. There are currently six competitive suppliers and six aggregators registered with us and licensed to supply electricity to customers in Virginia. However, the current relationship between capped rates and market prices makes switching suppliers unlikely.
Federal Regulations
FEDERAL ENERGY REGULATORY COMMISSION
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. We sell electricity in the wholesale market under our market-based sales tariffs authorized by FERC. In addition, we have FERC approval of a tariff to sell wholesale power at capped rates based on our embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside our service territory. Any such sales would be voluntary. Various proceedings that may have a significant effect on electric transmission service rates within the PJM region are ongoing at FERC. The outcome of these cases cannot be determined with any certainty at this point in time.
We are also subject to FERC’s Standards of Conduct that govern conduct between interstate gas and electricity transmission providers and their marketing function or their energy related affiliates. The rule defines the scope of the affiliates covered by the standards and is designed to prevent transmission providers from giving their marketing functions or affiliates undue preferences.
EPACT included provisions to create an Electric Reliability Organization (ERO). The ERO is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. In 2006, FERC certified the North American Electric Reliability Corporation (NERC) as the ERO beginning on January 1, 2007. In late 2006, FERC also issued an initial order approving many reliability standards, also to go into effect on January 1, 2007. FERC has proposed that beginning on June 1, 2007, entities that violate standards will be subject to fines of between $1 thousand and $1 million per day, depending upon the nature and severity of the violation.
We have planned and operated our facilities in compliance with earlier NERC voluntary standards for many years and are fully aware of the new requirements. We participate on various NERC committees, track development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. While we expect that there will be some additional cost involved in maintaining compliance as standards evolve, we do not expect a need for major expenditures beyond the normal course of business.
Environmental Regulations
Each of our operating segments faces substantial regulation and compliance costs with respect to environmental matters. For discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance, see Environmental Matters in Future Issues and Other Matters in MD&A. Additional information can also be found in Note 21 to our Consolidated Financial Statements.
The Clean Air Act (CAA) is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of our facilities are subject to the CAA’s permitting and other requirements. For example, the EPA has established the Clean Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR). These rules, when implemented, will require significant reductions in sulfur dioxide (SO2), nitrogen oxide (NOX) and mercury emissions from electric generating facilities. States are currently developing implementation plans, which will determine the levels and timing of required emission reductions in each of the states within which we own and operate affected generating facilities.
In 1997, the U.S. signed an International Protocol (Protocol) to limit man-made greenhouse emissions under the United Nations Framework Convention on Climate Change. However, the Protocol will not become binding unless approved by the U.S. Senate. Currently, the Bush Administration has indicated that it will not pursue ratification of the Protocol and has set a voluntary goal of reducing the nation’s greenhouse gas emission intensity by 18% during the period 2002 through 2012. We expect continuing legislative efforts in the U.S. Congress seeking to target the reductions of greenhouse gas emissions.
The Clean Water Act (CWA) is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. We must comply with all aspects of the CWA programs at our operating facilities. Provisions also include requirements that the location, design, construction, and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact. Additional programs under the CWA address the impact of thermal discharges to surface waters.
From time to time, we may be identified as a potentially responsible party (PRP) to a Superfund site. See Note 21 to our Consolidated Financial Statements for a description of our exposure relating to our identification as a PRP. We do not believe that any currently identified sites will result in significant liabilities.
We have applied for or obtained the necessary environmental permits for the operation of our regulated facilities. Many of these permits are subject to re-issuance and continuing review.
Nuclear Regulatory Commission
All aspects of the operation and maintenance of our nuclear power stations, which are part of our Generation segment, are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.
From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts
such requirements in the future, that action could result in substantial increases in the cost of operating and maintaining our nuclear generating units.
The NRC also requires us to decontaminate our nuclear facilities once operations cease. This process is referred to as decommissioning, and we are required by the NRC to be financially prepared. For information on the decommissioning trusts that have been established for this purpose, see Generation- Nuclear Decommissioning and Note 9 to our Consolidated Financial Statements.
ITEM 1A.
ITEM 1A. RISK FACTORS
Our business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond our control. We have identified a number of these factors below. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.
Our operations are weather sensitive. Our results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and affect the price of energy commodities. In addition, severe weather, including hurricanes, winter storms and droughts, can be destructive, causing outages and property damage that require us to incur additional expenses.
We are subject to complex governmental regulation that could adversely affect our operations. Our operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. We must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for our existing operations and that our business is conducted in accordance with applicable laws. However, new laws or regulations, or the revision or reinterpretation of existing laws or regulations, may require us to incur additional expenses.
Costs of environmental compliance, liabilities and litigation could exceed our estimates, which could adversely affect our results of operations. Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment expenses and monitoring obligations. In addition, we may be a responsible party for environmental clean-up at a site identified by a regulatory body. Management cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up and compliance costs, and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.
We are exposed to cost-recovery shortfalls because of capped base rates and amendments to the fuel factor statute in effect in Virginia. Under the 1999 Virginia Restructuring Act, as amended, our base rates remain capped through December 31, 2010 unless sooner modified or terminated. Although this Act allows for the recovery of certain generation-related costs during the capped rates period, we remain exposed to numerous risks of cost-recovery shortfalls. These risks include exposure to stranded costs, future environmental compliance requirements, certain tax law changes, costs related to hurricanes or other weather events,
inflation, the cost of obtaining replacement power during unplanned plant outages and increased capital costs.
In addition, our current Virginia fuel factor provisions are locked-in until July 1, 2007, with no deferred fuel accounting. As a result, until July 1, 2007 we are exposed to fuel price and other risks. These risks include exposure to increased costs of fuel, including purchased power costs, differences between our projected and actual power generation mix and generating unit performance (which affects the types and amounts of fuel we use) and differences between fuel price assumptions and actual fuel prices. Annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs, will be instituted for three twelve-month periods beginning July 1, 2007. The Virginia Commission is authorized to defer up to 40% of any fuel factor increase approved for the first twelve-month period, with recovery of the deferred amount over the two and one-half year period beginning July 1, 2008. There will also be an adjustment for one six-month period beginning July 1, 2010. Beginning July 1, 2007, our risk of under-recovering prudently incurred expenses until July 1, 2010 is greatly diminished. Because there will be no adjustment to account for differences between projections and actual recovery of fuel costs at the end of the six-month period beginning July 1, 2010, we will be exposed to fuel price and other risks during that period. Further, after December 31, 2010 (or upon the earlier termination of capped rates), fuel cost recovery provisions will cease and we will be exposed to the fuel price and other related risks as described above.
The foregoing risks are subject to change upon the adoption, if any, of the proposed 2007 legislative amendments. The proposed legislation would end capped rates on December 31, 2008. The proposed legislation also calls for annual fuel cost recovery proceedings beginning July 1, 2007 and continuing thereafter. The first annual increase as of July 1, 2007 would be limited to an amount that results in residential customers not receiving an increase of more than 4% of total rates as of that date, and the remainder would be deferred and collected in the years 2008 through 2010, as described under Status of Electric Restructuring in Virginia in MD&A. The Governor of Virginia has until March 26, 2007 to sign, propose amendments to, or veto the proposed legislation. We cannot predict the outcome of the legislation at this time.
There are risks associated with the operation of nuclear facilities. We operate nuclear facilities that are subject to risks, including the threat of terrorist attack and ability to dispose of spent nuclear fuel, the disposal of which is subject to complex federal and state regulatory constraints. These risks also include the cost of and our ability to maintain adequate reserves for decommissioning, costs of replacement power, costs of plant maintenance and exposure to potential liabilities arising out of the operation of these facilities. We maintain decommissioning trusts and external insurance coverage to mitigate the financial exposure to these risks. However, it is possible that costs arising from claims could exceed the amount of any insurance coverage.
The use of derivative instruments could result in financial losses and liquidity constraints. We use derivative instruments, including futures, forwards, financial transmission rights, options and swaps, to manage our commodity and financial market risks. We could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively-quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes
in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
Derivatives designated under hedge accounting to the extent not fully offset by the hedged transaction can result in ineffectiveness losses. These losses primarily result from differences in the location and specifications of the derivative hedging instrument and the hedged item and could adversely affect our results of operations.
Our operations in regards to these transactions are subject to multiple market risks including market liquidity, counterparty credit strength and price volatility. These market risks are beyond our control and could adversely affect our results of operations and future growth.
For additional information concerning derivatives and commodity-based contracts, see Market Risk Sensitive Instruments and Risk Management in Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 2 and 7 to our Consolidated Financial Statements.
An inability to access financial markets could affect the execution of our business plan. We rely on access to short-term money markets, longer-term capital markets and banks as significant sources of liquidity for capital requirements not satisfied by the cash flows from our operations. Management believes that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of our control may increase our cost of borrowing or restrict our ability to access one or more financial markets. Such disruptions could include an economic downturn, the bankruptcy of an unrelated energy company or changes to our credit ratings. Restrictions on our ability to access financial markets may affect our ability to execute our business plan as scheduled.
Changing rating agency requirements could negatively affect our growth and business strategy. As of February 1, 2007, our senior unsecured debt is rated BBB, positive outlook, by Standard & Poor’s Ratings Services (Standard & Poor’s); Baa1, stable outlook, by Moody’s Investors Service (Moody’s); and BBB+, stable outlook, by Fitch Ratings Ltd. (Fitch). In order to maintain our current credit ratings in light of existing or future requirements, we may find it necessary to take steps or change our business plans in ways that may adversely affect our growth and earnings. A reduction in our credit ratings by Standard & Poor’s, Moody’s or Fitch could increase our borrowing costs and adversely affect operating results.
Potential changes in accounting practices may adversely affect our financial results. We cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or our operations specifically. New accounting standards could be issued that could change the way we record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect our reported earnings or could increase reported liabilities.
Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on our operations. Our business strategy is dependent on our ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect our business and future operating results.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
We own our principal properties in fee (except as indicated below), subject to defects and encumbrances that do not interfere materially with their use. Substantially all of our property is subject to the lien of the mortgage securing our First and Refunding Mortgage Bonds; however, only $215 million of these bonds were outstanding at December 31, 2006 and the bonds will mature on July 1, 2007.
We share our principal office in Richmond, Virginia, which is owned by our parent company, Dominion. In addition, our Delivery, Energy and Generation segments share certain leased buildings and equipment. See Item 1. Business for additional information about each segment’s principal properties.
Our Generation segment provides electricity for use on a wholesale and a retail level. Our Generation segment can supply electricity demand either from our generation facilities in Virginia, North Carolina and West Virginia or through purchased power contracts when needed. The following table lists our Generation segment’s generating units and capability, as of December 31, 2006:
POWER GENERATION
Note: (CT) denotes combustion turbine, (CC) denotes combined cycle and (Mw) denotes megawatt.
(a) Excludes 11.6% undivided interest owned by Old Dominion Electric Cooperative (ODEC).
(b) Excludes 50% undivided interest owned by ODEC.
(c) Includes a generating unit that we operate under a leasing arrangement.
(d) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by us, or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, we are involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position, liquidity or results of operations.
See Regulation in Item 1. Business, Future Issues and Other Matters in MD&A and Note 21 to our Consolidated Financial Statements for additional information on various environmental, rate matters and other regulatory proceedings to which we are a party.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Dominion Resources, Inc. (Dominion) owns all of our common stock. Restrictions on our payment of dividends are discussed in Note 19 to our Consolidated Financial Statements. We paid quarterly cash dividends on our common stock as follows:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(1) Includes a $47 million after-tax charge in connection with the termination of a long-term power purchase agreement and an $8 million after-tax charge related to the sale of our interest in a long-term power tolling contract. Also in 2005, we adopted a new accounting standard that resulted in the recognition of the cumulative effect of a change in accounting principle. See Note 3 to our Consolidated Financial Statements.
(2) Includes a $112 million after-tax charge related to our interest in a long-term power tolling contract that was divested in 2005 and a $43 million after-tax charge resulting from the termination of long-term power purchase agreements.
(3) Includes $122 million of after-tax incremental restoration expenses associated with Hurricane Isabel, a $77 million after-tax charge resulting from the termination of long-term power purchase agreements and restructuring of certain electric sales contracts and a $21 million net after-tax loss for the adoption of the following accounting standards that resulted in the recognition of the cumulative effect of changes in accounting principles:
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Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations;
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Emerging Issues Task Force Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities;
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Statement 133 Implementation Issue No. C20, Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature; and
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Financial Accounting Standards Board Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (FIN 46R).
(4) Reflects the net impact of the discontinued operations of our indirect wholly-owned subsidiary, Virginia Power Energy Marketing, Inc., which was transferred to Dominion Resources, Inc. through a series of dividend distributions on December 31, 2005.
(5) Upon adoption of FIN 46R on December 31, 2003 with respect to a special purpose entity, we began reporting as long-term debt our junior subordinated notes held by a capital trust, rather than the trust preferred securities issued by the trust.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) discusses the results of operations and general financial condition of Virginia Electric and Power Company. MD&A should be read in conjunction with our Consolidated Financial Statements. The terms “Virginia Power,” “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one of Virginia Electric and Power Company’s consolidated subsidiaries or operating segments, or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries. We are a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion).
CONTENTS OF MD&A
Our MD&A consists of the following information:
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Forward-Looking Statements
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Introduction
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Accounting Matters
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Results of Operations
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Segment Results of Operations
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Liquidity and Capital Resources
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Future Issues and Other Matters
FORWARD-LOOKING STATEMENTS
This report contains statements concerning our expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “target” or other similar words.
We make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:
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Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;
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Extreme weather events, including hurricanes and winter storms, that can cause outages and property damage to our facilities;
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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;
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Cost of environmental compliance;
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Risks associated with the operation of nuclear facilities;
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Fluctuations in energy-related commodity prices and the effect these could have on our earnings, liquidity position and the underlying value of our assets;
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Capital market conditions, including price risk due to marketable securities held as investments in nuclear decommissioning trusts;
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Fluctuations in interest rates;
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Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;
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Changes in financial or regulatory accounting principles or policies imposed by governing bodies;
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Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;
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The risks of operating businesses in regulated industries that are subject to changing regulatory structures;
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Changes in rules for regional transmission organizations (RTOs) in which we participate, including changes in rate designs and new and evolving capacity models;
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Changes to our ability to recover investments made under traditional regulation through rates; and
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Political and economic conditions, including the threat of domestic terrorism, inflation and deflation.
Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.
Our forward-looking statements are based on our beliefs and assumptions using information available at the time the statements are made. We caution the reader not to place undue reliance on our forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. We undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.
INTRODUCTION
Virginia Electric and Power Company, a Virginia public service company, is a wholly-owned subsidiary of Dominion. We are a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. We serve approximately 2.3 million retail customer accounts, including governmental agencies, and wholesale customers such as rural electric cooperatives and municipalities.
Our businesses are managed through three primary operating segments: Delivery, Energy and Generation. The contributions to net income by our primary operating segments are determined based on a measure of profit that we believe represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by management in assessing segment performance or allocating resources among the segments. Those specific items are reported in the Corporate segment.
Delivery includes our regulated electric distribution and customer service businesses. Our electric distribution operations serve residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina.
Revenue provided by our electric distribution operations is based primarily on rates established by state regulatory authorities and state law. The profitability of this business is dependent on our ability, through the rates we are permitted to charge, to recover costs and earn a reasonable return on our capital investments. Variability in earnings relates largely to changes in volumes, which are primarily weather sensitive, and changes in the cost of routine maintenance and repairs (including labor and benefits).
Energy includes our regulated electric transmission system serving Virginia and northeastern North Carolina. In 2005, we
became a member of PJM Interconnection, LLC (PJM), an RTO, and integrated our electric transmission facilities into the PJM wholesale electricity markets.
Revenue provided by our regulated electric transmission operations is based primarily on rates established by the Federal Energy Regulatory Commission (FERC). The profitability of this business is dependent on our ability, through the rates we are permitted to charge, to recover costs and earn a reasonable return on our capital investments. Variability in earnings results from changes in rates and the demand for services, which is primarily weather dependent.
Generation includes our portfolio of electric generating facilities, power purchase agreements and our energy supply operations. Our generation mix is diversified and includes coal, nuclear, gas, oil, hydro and purchased power. Our electric generation operations serve customers in Virginia and northeastern North Carolina. Our generation facilities are located in Virginia, West Virginia and North Carolina. Our energy supply operations are responsible for managing energy and capacity needs for our utility system resources.
Generation’s earnings primarily result from the generation and sale of electricity. Due to 2004 deregulation legislation, revenues for serving Virginia jurisdictional retail load are based on capped rates through 2010 and fuel costs for the utility fleet, including power purchases, are subject to fixed rate recovery provisions until July 1, 2007, at which time fuel rates will be adjusted annually as discussed in Status of Electric Restructuring in Virginia in Future Issues and Other Matters.
Changes in our utility operating costs, particularly with respect to fuel and purchased power, relative to costs used to establish capped rates, will impact our earnings. Variability in earnings also results from changes in demand, which is primarily weather dependent, the cost of labor and benefits and the timing, duration and costs of outages.
Corporate includes our corporate and other functions, and specific items attributable to our primary operating segments that have been excluded from the profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments, including the net impact of Virginia Power Energy Marketing, Inc. (VPEM) prior to its transfer to Dominion.
On December 31, 2005, we completed the transfer of our indirect wholly-owned subsidiary, VPEM, to Dominion through a series of dividend distributions in exchange for a capital contribution. VPEM provides fuel and risk management services to us by acting as an agent for one of our other indirect wholly-owned subsidiaries. VPEM also engages in energy trading activities and provides price risk management services to other Dominion affiliates through the use of derivative contracts. While we owned VPEM, certain of these derivative contracts were required to be reported at fair value in our Consolidated Balance Sheets, with changes in fair value reflected in earnings. These price risk management activities for Dominion affiliates generated derivative gains and losses that in turn affected our Consolidated Financial Statements.
As a result of the transfer, VPEM’s results of operations are no longer included in our Consolidated Financial Statements, and our Consolidated Statements of Income for periods prior to the transfer have been adjusted to reflect VPEM as a discontinued operation.
ACCOUNTING MATTERS
Critical Accounting Policies and Estimates
We have identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to our financial condition or results of operations under different conditions or using different assumptions. We have discussed the development, selection and disclosure of each of these policies with our Board of Directors that also serves as our Audit Committee.
ASSET RETIREMENT OBLIGATIONS
We recognize liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These asset retirement obligations (AROs) are recognized at fair value as incurred, and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, we estimate the fair value of our AROs using present value techniques, in which we make various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. AROs currently reported in our Consolidated Balance Sheets were measured during a period of historically low interest rates. The impact on measurements of new AROs, or remeasurements of existing AROs, using different rates in the future, may be significant. When we revise any assumptions used to calculate the fair value of existing AROs, we adjust the carrying amount of both the ARO liability and the related long-lived asset. We accrete the ARO liability to reflect the passage of time. In 2006, 2005 and 2004, we recognized $40 million, $44 million and $42 million, respectively, of accretion and expect to incur $36 million in 2007.
A significant portion of our AROs relate to the future decommissioning of our nuclear facilities. At December 31, 2006, nuclear decommissioning AROs, which are reported in the Generation segment, totaled $603 million, representing approximately 94% of our total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with our nuclear decommissioning obligations.
We obtain from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for our nuclear plants. We obtained updated cost studies for both of our nuclear plants in 2006 which reflected increases in base year costs. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. In addition, our cost estimates include cost escalation rates that are applied to the base year costs. The selection of these cost escalation rates is dependent on subjective factors which we consider to be a critical assumption.
We determine cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities, for each of our nuclear facilities. In 2006, we lowered the cost escalation rate assumptions used in the ARO calculation by 0.85% due to projected reductions in both general and decommissioning specific inflation rates, resulting in a $201 million decrease in our nuclear decommissioning AROs.
ACCOUNTING FOR REGULATED OPERATIONS
The accounting for our regulated electric operations differs from the accounting for nonregulated operations in that we are required to reflect the effect of rate regulation in our Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, we defer these costs as regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates and when revenue is collected from customers for expenditures that are not yet incurred. Regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the recovery period authorized by the regulator.
We evaluate whether or not recovery of our regulatory assets through future rates is probable and make various assumptions in our analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. We currently believe the recovery of our regulatory assets is probable. See Notes 2 and 12 to our Consolidated Financial Statements.
REVENUE RECOGNITION - UNBILLED REVENUE
We recognize and record revenues when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters which is performed on a systematic basis throughout the month. At the end of each month, the amounts of electric energy delivered to customers but not yet billed is estimated and recorded as unbilled revenue. This estimate is reversed in the following month and actual revenue is recorded based on meter readings. Our customer receivables included $233 million and $263 million of accrued unbilled revenue at December 31, 2006 and 2005 respectively.
The calculation of unbilled revenues is complex and includes numerous estimates and assumptions including historical usage, applicable customer rates, weather factors and total daily electric generation supplied adjusted for line losses. Changes in generation patterns, customer usage patterns, meter accuracy and other factors which are the basis for the estimates of unbilled revenues could have a significant effect on the calculation and therefore on our results of operations and financial condition.
INCOME TAXES
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret them differently. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows and adjustments to tax-related assets and liabilities could be material.
Through December 31, 2006, we have established liabilities for tax-related contingencies in accordance with Statement of Financial Accounting Standards (SFAS) No. 5, Accounting for Contingencies, and reviewed them in light of changing facts and circumstances. However, as discussed in Note 4 to our Consolidated Financial Statements, effective January 1, 2007, we adopted Financial Accounting Standards Board Interpretation
No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes. Taking into consideration the uncertainty and judgment involved in the determination and filing of income taxes, FIN 48 establishes standards for recognition and measurement, in financial statements, of positions taken, or expected to be taken, by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.
Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. We evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets.
ACCOUNTING STANDARDS
During 2006 and 2005, we were required to adopt several new accounting standards, which are discussed in Note 3 to our Consolidated Financial Statements. See Note 4 to our Consolidated Financial Statements for a discussion of recently issued accounting standards that will be adopted in the future.
RESULTS OF OPERATIONS
Presented below is a summary of our consolidated results:
Overview
2006 VS. 2005
Net income increased to $478 million. Favorable drivers include the absence of $471 million of after-tax losses incurred in 2005 by the discontinued operations of VPEM and the absence of a 2005 charge resulting from the termination of a long-term power purchase agreement. Our results were also positively impacted by decreased consumption of fossil fuel due to milder weather and an increase in gains realized from the sale of emissions allowances. Unfavorable drivers include a decrease in regulated electric sales resulting from milder weather and other factors; a reduced benefit from financial transmission rights (FTRs) in excess of congestion costs and major storm damage and service restoration costs associated with tropical storm Ernesto in September 2006.
2005 VS. 2004
Net income decreased to $10 million. Unfavorable drivers include $471 million of after-tax losses incurred by the discontinued operations of VPEM and a charge resulting from the termination of a long-term power purchase agreement. Our results were also negatively affected by the impact of higher commodity prices on fuel and purchased power expenses.
Analysis of Consolidated Operations
Presented below are selected amounts related to our results of operations:
An analysis of our results of operations for 2006 compared to 2005 and 2005 compared to 2004 follows:
2006 VS. 2005
Operating Revenue decreased 2% to $5.6 billion, reflecting the combined effects of:
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A $218 million decrease associated with milder weather. As compared to the prior year, we experienced a 9% decline in cooling degree days and a 16% decline in heating degree days; and
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A $53 million decrease in sales to wholesale customers primarily resulting from milder weather; partially offset by
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An $81 million increase due to new customer connections primarily in our residential and commercial customer classes;
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A $56 million increase attributable to rate variations resulting from changes in customer usage patterns and sales mix and other factors;
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An $18 million increase in ancillary service revenue from PJM;
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A $13 million increase due to the collection of a new Virginia sales and use tax surcharge from customers; and
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A $9 million increase primarily due to the impact of a comparatively higher fuel rate in certain customer jurisdictions which was offset by a comparable increase in Electric fuel and energy purchases expense.
Operating Expenses and Other Items
Electric fuel and energy purchases expense decreased 7% to $2.4 billion, primarily due to lower commodity prices, including purchased power, and decreased consumption of fossil fuel, reflecting the effects of milder weather on demand, partially offset by an increase in purchased power volumes.
Purchased electric capacity expense decreased 5% to $453 million, primarily due to scheduled capacity reductions for certain long-term power purchase contracts, as well as the termination of a long-term power purchase agreement in connection with the purchase of the related generating facility in February 2005.
Other energy-related commodity purchases expense increased 65% to $56 million, primarily reflecting an increase in nonutility coal purchased for resale.
Other operations and maintenance expense increased 9% to $1.0 billion, primarily reflecting:
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A $41 million increase due to a reduced benefit from FTRs granted by PJM used to offset congestion costs associated with PJM spot market activity, which are included in Electric fuel and energy purchases expense;
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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;
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A $15 million increase resulting from higher salaries, wages, and pension and medical benefits;
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A $12 million increase in outage costs primarily due to an increase in the number of scheduled outages at certain of our electric generating facilities;
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A $9 million increase due to the amortization of a regulatory asset associated with amounts subject to collection under a Virginia sales and use tax surcharge, net of credits resulting from additions to the regulatory asset during the period;
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A $7 million increase related to services provided by Dominion Resources Services, Inc.;
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A $7 million charge resulting from the write-off of certain assets no longer in use at one of our electric generating facilities; and
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A $4 million increase in PJM ancillary service charges; partially offset by
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A $20 million increase in gains from the sale of emissions allowances; and
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A net benefit from the absence of the following items recognized in 2005:
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A $77 million charge resulting from the termination of a long-term power purchase agreement; partially offset by
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A $25 million net benefit resulting from the establishment of certain regulatory assets in connection with the settlement of a North Carolina rate case.
Interest and related charges decreased 8% to $296 million, primarily reflecting the absence of prepayment penalties resulting from the early redemption of debt in 2005, partially offset by additional borrowings and higher interest rates on variable rate debt.
Loss from discontinued operations reflects the absence of losses incurred by the discontinued operations of VPEM prior to its disposition in December 2005.
2005 VS. 2004
Operating Revenue increased 6% to $5.7 billion, primarily reflecting:
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A $153 million increase in sales to wholesale customers;
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A $99 million increase due to the impact of a comparatively higher fuel rate in certain customer jurisdictions which was more than offset by an increase in Electric fuel and energy purchases expense;
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A $77 million increase primarily due to the impact of comparably favorable weather on customer usage. As compared to the prior year, we experienced an 8% increase in cooling degree days and a 3% increase in heating degree days; and
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A $59 million increase associated with new customer connections primarily in our residential and commercial customer classes; partially offset by
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A $25 million decrease attributable to rate variations resulting from changes in customer usage patterns and sales mix and other factors; and
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A $22 million decrease in other revenue, primarily attributable to a decrease in off-system sales.
Operating Expenses and Other Items
Electric fuel and energy purchases expense increased 46% to $2.6 billion, primarily resulting from higher commodity prices including purchased power and congestion costs associated with PJM.
Purchased electric capacity expense decreased 13% to $477 million, resulting from the termination of several long-term power purchase agreements in connection with the purchase of the related generating facilities in 2004 and 2005.
Other operations and maintenance expense decreased 24% to $945 million, primarily reflecting:
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A $186 million benefit related to FTRs;
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A $54 million gain resulting from the sale of emissions allowances; and
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A net benefit from the absence of the following items recognized in 2004:
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A $184 million charge related to the sale of our interest in a long-term power tolling contract;
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A $71 million charge resulting from the termination of certain long-term power purchase agreements; partially offset by
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An $18 million benefit from the reduction of accrued expenses associated with Hurricane Isabel restoration activities.
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These benefits were partially offset by the following charges in 2005:
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A $77 million charge resulting from the termination of a long-term power purchase agreement;
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A $36 million increase in salaries, wages, and benefits expense, resulting from higher incentive-based compensation, wages and pension benefits; and
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A $17 million increase in operating expenses related to nonutility generating facilities acquired subsequent to September 2004.
Depreciation and amortization expense increased 6% to $527 million, due to incremental expense resulting from property additions.
Other income increased 43% to $70 million primarily reflecting a $9 million increase in net realized gains (including investment income) associated with nuclear decommissioning trust fund investments, a $3 million increase in rental income and a $2 million increase in interest income.
Interest and related charges increased 29% to $322 million, primarily reflecting the impact of prepayment penalties resulting from the early redemption of debt, additional borrowings and higher interest rates on variable rate debt.
Loss from discontinued operations increased as a result of unfavorable price changes on unsettled commodity derivative contracts primarily used to execute price risk management activities undertaken on behalf of our affiliates.
Outlook
We believe our operating businesses will provide stable growth in net income in 2007. The following are growth factors that will impact these expected results:
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A decrease in unrecovered Virginia fuel expenses as a result of annual adjustments to our fuel factor beginning July 1, 2007;
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A potential increase in regulated electric sales, as compared to 2006, assuming our utility service territory experiences a return to normal weather in 2007; and
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Continued growth in utility customers.
The growth factors in 2007 are expected to be partially offset by:
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A decrease in gains from sales of emissions allowances;
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Increased salaries, wages and benefits expense; and
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Increased interest expense.
An important development impacting the future of our Company is the passage of legislation in Virginia that would re-regulate certain elements of our business, as discussed in Status of Electric Restructuring in Virginia under Future Issues and Other Matters. Since competitive markets have not developed in Virginia, we are supporting legislation passed by the Virginia General Assembly in early 2007 that would create a hybrid regulatory model designed to modify the traditional regulatory method to better suit it to the financial realities of undertaking major new generation and infrastructure projects. We believe this model would continue to provide our customers with comparatively low rates and ensure our ability to build new generation and other infrastructure needed to keep pace with growing demand for electricity in Virginia. The Governor has until March 26, 2007 to sign, propose amendments to, or veto the proposed legislation. With the Governor’s signature, the legislation would become law effective July 1, 2007. At this time, we cannot predict the outcome of the legislation.
SEGMENT RESULTS OF OPERATIONS
Presented below is a summary of contributions by our operating segments to net income:
Delivery
Presented below are operating statistics related to our Delivery operations:
mwhrs = megawatt hours
(1) Includes electricity delivered through the retail choice program for our Virginia jurisdictional electric customers.
(2) Cooling degree days (CDDs) are units measuring the extent to which the average daily temperature is greater than 65 degrees. CDDs are calculated as the difference between the average temperature for each day and 65 degrees.
(3) Heating degree days (HDDs) are units measuring the extent to which the average temperature is less than 65 degrees. HDDs are calculated as the difference between the average temperature and 65 degrees.
(4) Thirteen-month average, in thousands.
Presented below, on an after-tax basis, are the key factors impacting Delivery’s net income contribution:
2006 VS. 2005
(1) Attributable to rate variations from changes in customer usage patterns and sales mix and other factors.
2005 VS. 2004
(1) A change in the seasonal allocation of electric utility base rate revenue among the primary operating segments effective January 1, 2005.
Energy
Presented below, on an after-tax basis, are the key factors impacting Energy’s net income contribution:
2006 VS. 2005
(1) Reflects the absence of a charge incurred in 2005 for the write-off of certain previously deferred start-up and integration costs associated with joining an RTO.
2005 VS. 2004
Generation
Presented below are operating statistics related to our Generation operations:
The Generation segment provides electricity primarily from nuclear, coal, oil, purchased power and natural gas. Presented below is a summary of the system’s output by energy source:
(1) Excludes Old Dominion Electric Cooperative’s (ODEC) 11.6% ownership interest in the North Anna Power Station.
(2) Excludes ODEC’s 50% ownership interest in the Clover Power Station. The average cost of coal for 2006 Virginia in-system generation was $27.35 per mwhr.
(3) Includes natural gas used in combustion turbines that are fueled by gas.
(4) Excludes off-system sales.
Presented below, on an after-tax basis, are the key factors impacting Generation’s net income contribution:
2006 VS. 2005
(1) Primarily attributable to rate variations from changes in customer usage patterns and sales mix and other factors.
(2) Primarily reflects a reduced benefit from FTRs in excess of congestion costs.
2005 VS. 2004
(1) Reflects higher commodity prices including purchased power.
(2) The increase in energy supply margin reflects a benefit related to FTRs.
Corporate
Presented below are the Corporate segment’s after-tax results.
Specific Items Attributable to Operating Segments
Corporate includes specific items attributable to our primary operating segments that have been excluded from the profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments. See Note 25 to our Consolidated Financial Statements for a discussion of these items.
LIQUIDITY AND CAPITAL RESOURCES
We depend on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities and additional long-term financing.
At December 31, 2006, we had $1.0 billion of unused capacity under our joint credit facility. See discussion under Joint Credit Facilities and Short-Term Debt.
A summary of our cash flows for 2006, 2005 and 2004 is presented below:
Operating Cash Flows
In 2006, net cash provided by operating activities decreased by $416 million as compared to 2005, primarily reflecting the absence of cash provided by VPEM prior to its disposition in December 2005. We believe that our operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and provide dividends to Dominion. However, our operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows which are discussed in Item 1A. Risk Factors.
CREDIT RISK
Our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Presented below is a summary of our gross exposure as of December 31, 2006 for these activities. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. We held no collateral for these transactions at December 31, 2006.
(1) Designations as investment grade are based on minimum credit ratings assigned by Moody’s Investors Service (Moody’s) and Standard & Poor’s Ratings Services (Standard & Poor’s). The five largest counterparty exposures, combined, for this category represented approximately 6% of the total gross credit exposure.
(2) The five largest counterparty exposures, combined, for this category represented approximately 94% of the total gross credit exposure.
Investing Cash Flows
Significant investing activities in 2006 included:
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$925 million for environmental upgrades, routine capital improvements of generation facilities and construction and improvements of electric transmission and distribution assets;
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$550 million for purchases of securities held as investments in our nuclear decommissioning trusts; and
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$122 million for nuclear fuel expenditures; partially offset by
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$533 million of proceeds from sales of securities held as investments in our nuclear decommissioning trusts; and
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$75 million of proceeds from the sale of emissions allowances.
Financing Cash Flows and Liquidity
We rely on banks and capital markets as significant sources of funding for capital requirements not satisfied by the cash provided by our operations. As discussed in Credit Ratings, our ability to borrow funds or issue securities and the return demanded by investors are affected by our credit ratings. In addition, the raising of external capital is subject to certain regulatory approvals, including authorization by the Virginia State Corporation Commission (Virginia Commission).
In December 2005, the Securities and Exchange Commission (SEC) adopted rules that modify the registration, communications and offering processes under the Securities Act of 1933. The rules streamline the shelf registration process to provide registrants with more timely access to capital. Under the new rules, we meet the definition of a well-known seasoned issuer. This allows us to use an automatic shelf registration statement to register any offering of securities, other than those for business combination transactions.
Significant financing activities in 2006 included:
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$624 million for the repayment of long-term debt;
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$349 million of common dividend payments; and
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$287 million for the net repayment of short-term debt; partially offset by
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$1 billion from the issuance of long-term debt; and
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$129 million from the net issuance of affiliated current borrowings.
JOINT CREDIT FACILITIES AND SHORT-TERM DEBT
We use short-term debt, primarily commercial paper, to fund working capital requirements and as a bridge to long-term debt financing. The level of our borrowings may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. Short-term financing is supported by a $3.0 billion five-year joint revolving credit facility dated February 2006 with Dominion and Consolidated Natural Gas Company (CNG), a wholly-owned subsidiary of Dominion, which is scheduled to terminate in February 2011. This credit facility is being used for working capital, as support for the combined commercial paper programs of Dominion, CNG and us and other general corporate purposes. This credit facility can also be used to support up to $1.5 billion of letters of credit.
Our financial policy precludes issuing commercial paper in excess of our supporting lines of credit. At December 31, 2006, total commercial paper outstanding supported by the joint credit facility was $1.76 billion and the total amount of letter of credit issuances was $236 million, leaving approximately $1.0 billion available for issuance.
LONG-TERM DEBT
During 2006, we issued the following long-term debt:
During 2006, we repaid $624 million of long-term debt securities.
COMMON SHAREHOLDER’S EQUITY
In 2005, we recorded contributed capital of $633 million related to the transfer of our investment in VPEM to Dominion and $200 million in connection with the conversion of short-term borrowings. In 2004, we recorded $11 million of other paid-in capital in connection with the reduction in amounts payable to Dominion.
In 2004, we issued 20,115 shares of our common stock to Dominion for cash consideration of $500 million. We used the proceeds, in part, to pay down our $345 million affiliated short-term demand note from Dominion.
BORROWINGS FROM PARENT
We have borrowed funds from Dominion under both short-term and long-term borrowing arrangements. Our nonregulated subsidiaries had outstanding Dominion money pool borrowings totaling $140 million and $12 million at December 31, 2006 and 2005, respectively. At December 31, 2006 and 2005, our borrowings under a long-term note totaled $220 million. We incurred interest charges related to our borrowings of $10 million and $9 million at December 31, 2006 and 2005, respectively.
Credit Ratings
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. We believe that our current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to us may affect our ability to access these funding sources or cause an increase in the return required by investors.
Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing our credit ratings. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. Our credit ratings are most affected by our financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies, “event risk” if applicable, and the credit ratings of our parent company, Dominion.
Our credit ratings as of February 1, 2007 follow:
As of February 1, 2007, Fitch Ratings Ltd. (Fitch) and Moody’s maintain a stable outlook, and Standard & Poor’s maintains a positive outlook for their ratings of our company.
Generally, a downgrade in our credit rating would not restrict our ability to raise short-term or long-term financing as long as our credit rating remains “investment grade,” but it would increase the cost of borrowing. We work closely with Fitch, Moody’s and Standard & Poor’s, with the objective of maintaining our current credit ratings. In order to maintain our current ratings, we may find it necessary to modify our business plans and such changes may adversely affect our growth.
Debt Covenants
As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, we must enter into enabling agreements. These agreements contain covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to our capital stock to Dominion, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and, in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to us. Some of the typical covenants include:
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The timely payment of principal and interest;
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Information requirements, including submitting financial reports filed with the SEC to lenders;
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Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation, restrictions on disposition of all or substantially all of our assets;
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Compliance with collateral minimums or requirements related to mortgage bonds; and
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Limitations on liens.
We are required to pay minimal annual commitment fees to maintain the joint credit facility. In addition, the joint credit agreement contains various terms and conditions that could affect our ability to borrow funds under this facility. They include a maximum debt to total capital ratio and cross-default provisions.
The ratio of our debt to total capital, as defined by the agreement, should not exceed 65% at the end of any fiscal quarter. As of December 31, 2006, our calculated debt to total capital ratio was 47%. Under the agreement’s cross-default provisions, if we or any of our material subsidiaries fail to make payment on various debt obligations in excess of $35 million, we may be required by the lenders to accelerate our repayment of any outstanding borrowings under the credit facility and the lenders could terminate their commitment to lend funds to us. However, any defaults on indebtedness by Dominion, CNG or any material subsidiaries of those affiliates would not affect the lenders’ commitment to us under the joint credit agreement.
We monitor the covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2006, there were no events of default under our covenants.
Dividend Restrictions
The Virginia Commission may prohibit any public service company from declaring or paying a dividend to an affiliate, if found to be detrimental to the public interest. At December 31, 2006, the Virginia Commission had not restricted our payment of dividends.
Certain agreements associated with our joint credit facility with Dominion and CNG contain restrictions on the ratio of our
debt to total capitalization. These limitations did not restrict our ability to pay dividends to Dominion at December 31, 2006.
See Note 16 to our Consolidated Financial Statements for a description of potential restrictions on our dividend payments in connection with the deferral of distribution payments on trust preferred securities.
Cash Flows from Discontinued Operations
The impact of VPEM’s operations on our Consolidated Statements of Cash Flows is presented below. The transfer of VPEM to Dominion has not had a negative impact on our liquidity.
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
CONTRACTUAL OBLIGATIONS
We are party to numerous contracts and arrangements obligating us to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services. Presented below is a table summarizing cash payments that may result from contracts to which we are a party as of December 31, 2006. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in our Consolidated Balance Sheets, other than current maturities of long-term debt, interest payable and interest rate swaps. The majority of current liabilities will be paid in cash in 2007.
(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.
(2) Does not reflect our ability to defer payments related to our trust preferred securities.
(3) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.
(4) Primarily includes interest rate swap agreements. Excludes regulatory liabilities, AROs and employee benefit plan contributions that are not contractually fixed as to timing and amount. See Notes 12, 13 and 20 to our Consolidated Financial Statements. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year.
PLANNED CAPITAL EXPENDITURES
Our planned capital expenditures are expected to total approximately $1.2 billion annually in both 2007 and 2008. We expect to fund our capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Our annual capital expenditures for plant and equipment for 2007, including environmental upgrades and construction improvements, are expected to total approximately as follows:
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Generation and nuclear fuel: $654 million;
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Transmission: $168 million; and
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Distribution: $390 million.
Based on available generation capacity and current estimates of growth in customer demand, we will need additional generation in the future. We currently have plans to restart our Hopewell plant in 2007, a 63-megawatt (Mw) (at net summer capability) coal burning plant located in Hopewell, Virginia which has been out of service since 2002, and we are evaluating a 290-Mw (at net summer capability) expansion of our Ladysmith site in Ladysmith, Virginia. We are also leading a consortium of companies that are considering building a 500 to 600-Mw coal-fired plant in southwest Virginia. We will continue to evaluate the development of new plants to meet customer demand for additional generation needs in the future. Through 2009, we will continue to meet any additional capacity requirements through market purchases.
FUTURE ISSUES AND OTHER MATTERS
Status of Electric Restructuring in Virginia
1999 VIRGINIA RESTRUCTURING ACT
The Virginia Electric Utility Restructuring Act was enacted in 1999 (1999 Virginia Restructuring Act) and established a plan to restructure the electric utility industry in Virginia. In general, this legislation provided for a transition from bundled cost-based rates for regulated electric service to unbundled cost-based rates for transmission and distribution services and to market pricing for generation services, including retail choice for customers. The 1999 Virginia Restructuring Act addressed capped base rates, RTO participation, retail choice, stranded costs recovery and functional separation of an electric utility’s generation from its transmission and distribution operations.
Retail choice was made available to all of our Virginia regulated electric customers since January 1, 2003. We have separated our generation, distribution and transmission functions through the creation of divisions. State regulatory requirements ensure that our generation division and other divisions operate independently and prevent cross-subsidies between our generation division and other divisions. Additionally, in 2005, we became a member of PJM, an RTO, and have integrated our electric transmission facilities into the PJM wholesale electricity markets. Under the 1999 Virginia Restructuring Act, our base rates have been capped until December 31, 2010, unless modified earlier.
2004 amendments to the 1999 Virginia Restructuring Act addressed a minimum stay exemption program, a wires charge exemption program and the development of a coal-fired generating plant in southwest Virginia.
VIRGINIA FUEL EXPENSES
In May 2006, Virginia law was amended to modify the way our Virginia jurisdictional fuel factor is set during the three and one-half year period beginning July 1, 2007. The bill became law effective July 1, 2006 and:
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Allows annual fuel rate adjustments for three twelve-month periods beginning July 1, 2007 and one six-month period
beginning July 1, 2010 (unless capped rates are terminated earlier under the 1999 Virginia Restructuring Act);
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Allows an adjustment at the end of each of the twelve-month periods to account for differences between projections and actual recovery of fuel costs during the prior twelve months; and
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Authorizes the Virginia Commission to defer up to 40% of any fuel factor increase approved for the first twelve-month period, with recovery of the deferred amount over the two and one-half year period beginning July 1, 2008 (under prior law, such a deferral was not possible).
Fuel prices have increased considerably since our Virginia fuel factor provisions were frozen in 2004, which has resulted in our fuel expenses being significantly in excess of our rate recovery. We expect that fuel expenses will continue to exceed rate recovery until our fuel factor is adjusted in July 2007. While the 2006 amendments do not allow us to collect any unrecovered fuel expenses that were incurred prior to July 1, 2007, once our fuel factor is adjusted, the risk of under-recovery of prudently incurred fuel costs until July 1, 2010 is greatly diminished.
STRANDED COSTS
Stranded costs are generation-related costs incurred or commitments made by utilities under cost-based regulation that may not be reasonably expected to be recovered in a competitive market. At December 31, 2006, our exposure to potential stranded costs included long-term power purchase contracts that could ultimately be determined to be above market prices; generating plants that could possibly become uneconomical in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits. We believe capped electric retail rates will provide an opportunity to recover our potential stranded costs, depending on market prices of electricity and other factors. Recovery of our potential stranded costs remains subject to numerous risks, even in the capped-rate environment. These risks include, among others, exposure to long-term power purchase commitment losses, future environmental compliance requirements, changes in certain tax laws, nuclear decommissioning costs, increased fuel costs, inflation, increased capital costs and recovery of certain other items.
The generation-related cash flows provided by the 1999 Virginia Restructuring Act are intended to compensate us for continuing to provide generation services and to allow us to incur costs to restructure such operations during the transition period. As a result, during the transition period, our earnings may increase to the extent that we can reduce operating costs for our utility generation-related operations. Conversely, the same risks affecting the recovery of our stranded costs may also adversely impact our margins during the transition period. Accordingly, we could realize the negative economic impact of any such adverse event. Using cash flows from operations during the transition period, we may further alter our cost structure or choose to make additional investments in our business.
2007 VIRGINIA RESTRUCTURING ACT AMENDMENTS
In February 2007, both houses of the Virginia General Assembly passed identical bills that would significantly change electricity restructuring in Virginia. The bills would end capped rates two years early, on December 31, 2008. After capped rates end, retail choice would be eliminated for all but individual retail customers with a demand of more than 5-Mw and a limited number of non-residential retail customers whose aggregated load would exceed 5-Mw. Also after the end of capped rates, the Virginia Commis -
sion would set the base rates of investor-owned electric utilities under a modified cost-of-service model. Among other features, the currently proposed model would provide for the Virginia Commission to:
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Initiate a base rate case for each utility during the first six months of 2009, as a result of which the Virginia Commission:
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establishes a return on equity (ROE) no lower than that reported by a group of utilities within the southeastern United States (U.S.), with certain limitations on earnings and rate adjustments;
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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;
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may reduce rates or, alternatively, order a credit to customers if the utility is found to have earnings more than 50 basis points above the established ROE; and
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may authorize performance incentives if appropriate.
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After the initial rate case, review base rates biennially, as a result of which the Virginia Commission:
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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;
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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;
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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
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may authorize performance incentives if appropriate.
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Authorize stand-alone rate adjustments for recovery of certain costs, including new generation projects, major generating unit modifications, environmental compliance projects, FERC-approved costs for transmission service, energy efficiency and conservation programs, and renewable energy programs; and
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Authorize an enhanced ROE as a financial incentive for construction of major baseload generation projects and for renewable energy portfolio standard programs.
The bills would also continue statutory provisions directing us to file annual fuel cost recovery cases with the Virginia Commission beginning in 2007 and continuing thereafter. However, our fuel factor increase as of July 1, 2007 would be limited to an amount that results in residential customers not receiving an increase of more than 4% of total rates as of that date, and the remainder would be deferred and collected over three years, as follows:
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in calendar year 2008, the deferral portion collected is limited to an amount that results in residential customers not receiv
ing an increase of more than 4% of total rates as of January 1, 2008;
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in calendar year 2009, the deferral portion collected is limited to an amount that results in residential customers not receiving an increase of more than 4% of total rates as of January 1, 2009; and
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the remainder of the deferral balance, if any, would be collected in the fuel factor in calendar year 2010.
The Govenor has until March 26, 2007 to sign, propose amendments to, or veto the bills. With the Govenor’s signature, the bills would become law effective July 1, 2007. At this time, we cannot predict the outcome of these legislative proposals.
Transmission Expansion Plan
Each year, as part of PJM’s Regional Transmission Expansion Plan (RTEP) process, reliability projects are authorized. In June 2006, PJM, through the RTEP process, authorized construction of numerous electric transmission upgrades through 2011. We are involved in two of the major construction projects. The first project is an approximately 270-mile 500-kilovolt (kV) transmission line from southwestern Pennsylvania to Virginia, of which we will construct approximately 70 miles in Virginia and a subsidiary of Allegheny Energy, Inc. will construct the remainder. The second project is an approximately 56-mile 500-kV transmission line that we will construct in southeastern Virginia. These transmission upgrades are designed to improve the reliability of service to our customers and the region. The siting and construction of these transmission lines will be subject to applicable state and federal permits and approvals.
Environmental Matters
We are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. To the extent that environmental costs are incurred in connection with operations regulated by the Virginia Commission, during the period ending December 31, 2010, in excess of the level currently included in the Virginia jurisdictional electric retail rates, our results of operations will decrease. After that date, recovery through regulated rates may be sought for only those environmental costs related to regulated electric transmission and distribution operations and recovery, if any, through the generation component of rates will be dependent upon the market price of electricity. However, the foregoing risks are subject to change upon the adoption, if any, of the proposed 2007 Virginia Restructuring Act Amendments.
ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES
We incurred approximately $102 million, $134 million and $115 million of expenses (including depreciation) during 2006, 2005 and 2004, respectively, in connection with environmental protection and monitoring activities and expect these expenses to be approximately $133 million and $134 million in 2007 and 2008. In addition, capital expenditures related to environmental controls were $170 million, $42 million and $84 million for 2006, 2005 and 2004, respectively. These expenditures are expected to be approximately $197 million and $142 million for 2007 and 2008.
CLEAN AIR ACT COMPLIANCE
In March 2005, the Environmental Protection Agency (EPA) Administrator signed both the Clean Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR). These rules, when implemented, will require significant reductions in sulfur dioxide (SO2), nitrogen oxide (NOX) and mercury emissions from electric generating facilities. The SO2 and NOX emission reduction requirements are imposed in two phases with initial reduction levels targeted for 2009 (NOX) and 2010 (SO2), and a second phase of reductions targeted for 2015 (SO2 and NOX). The mercury emission reduction requirements are also in two phases, with initial reduction levels targeted for 2010 and a second phase of reductions targeted for 2018. The new rules allow for the use of cap-and-trade programs. States are currently developing implementation plans, which will determine the levels and timing of required emission reductions in each of the states within which we own and operate affected generating facilities. Several of these states have issued proposed regulations for the implementation of CAIR and CAMR, but only West Virginia has adopted final rules. In April 2006, legislation titled, Air Emissions Control, which addresses many of the requirements of CAIR and CAMR was adopted in Virginia and is more strict than the federal requirements. This legislation, however, does not serve as Virginia’s final plan for the implementation of CAIR and CAMR. These regulatory and legislative actions will require additional reductions in emissions from our fossil fuel-fired generating facilities and are already addressed in our current compliance planning. In June 2005, the EPA finalized amendments to the Regional Haze Rule, also known as the Clean Air Visibility Rule (CAVR). States have not yet finalized regulations to implement CAVR. Although we anticipate that the emission reductions achieved through compliance with CAIR and CAMR will address CAVR, at this time we cannot predict with certainty any additional financial impacts of the regional haze regulations on our operations. Implementation of projects to comply with these SO2, NOX and mercury limitations, and other state emission control programs are ongoing and will be influenced by changes in the regulatory environment, availability of emission allowances and emission control technology. In response to these requirements, we estimate that we will make capital expenditures at our affected generating facilities of approximately $451 million during the period 2007 through 2011.
In March 2004, the State of North Carolina filed a petition with the EPA under Section 126 of the CAA seeking additional NOx and SO2 reductions from electrical generating units in thir
teen states, claiming emissions from those units are contributing to air quality problems in North Carolina. We have electrical generating units in two of the thirteen states. In March 2006, the EPA issued a final rulemaking through which it denied the North Carolina petition on the basis that the implementation of the CAIR adequately addresses the air quality issues identified by North Carolina. Therefore, we do not anticipate additional expenditures in relation to this matter.
CLEAN WATER ACT COMPLIANCE
In July 2004, the EPA published regulations that govern existing utilities that employ a cooling water intake structure, and that have flow levels exceeding a minimum threshold. The EPA’s rule presents several compliance options. We have been evaluating information from certain of our existing power stations and had expected to spend approximately $4 million over the next two years conducting studies and technical evaluations. However, in January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision on an appeal of the regulations, remanding the rule to the EPA. We cannot predict the outcome of the EPA regulatory process or determine with any certainty what specific controls may be required.
FUTURE ENVIRONMENTAL REGULATIONS
From time to time, the U.S. Congress considers various legislative proposals that would require generating facilities to comply with more stringent air emissions standards. Emission reduction requirements under consideration would be phased in under periods of up to ten to fifteen years. If these new proposals are adopted, additional significant expenditures may be required.
In 1997, the U.S. signed an International Protocol (Protocol) to limit man-made greenhouse emissions under the United Nations Framework Convention on Climate Change. However, the Protocol will not become binding unless approved by the U.S. Senate. The Bush Administration has indicated that it will not pursue ratification of the Protocol and has set a voluntary goal of reducing the nation’s greenhouse gas emission intensity by 18% during the period 2002 through 2012. We expect continuing legislative efforts in the U.S. Congress seeking to target the reductions of greenhouse gas emissions. The cost of compliance with the Protocol or other greenhouse gas reduction programs could be significant. Given the highly uncertain outcome and timing of future action, if any, by the U.S. federal government on this issue, we cannot predict the financial impact of future climate change actions on our operations at this time.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors for discussion of various risks and uncertainties that may affect our future.
MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT
Our financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, foreign currency exchange rates, interest rates and equity security prices as described below. Commodity price risk is due to our exposure to market shifts for prices received and paid for natural gas, electricity and other commodities. We are exposed to foreign currency exchange rate risks related to our purchases of fuel and fuel services denominated in foreign currencies. Interest rate risk is generally related to our outstanding debt. In addition, we are exposed to equity price risk through various portfolios of equity securities.
The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% unfavorable change in commodity prices, foreign currency exchange rates and interest rates.
Commodity Price Risk
To manage price risk, we primarily hold commodity-based financial derivative instruments for nontrading purposes associated with the purchase of electricity and natural gas. The derivatives used to manage our commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps and options that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the fair value of commodity-based financial derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on actively quoted market prices.
A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $3 million in the fair value of our non-trading commodity-based financial derivatives as of December 31, 2006. At December 31, 2005, we did not have significant exposure to commodity price risk associated with financial derivative instruments.
The impact of a change in energy commodity prices on our non-trading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. For example, our expenses for power purchases when combined with the settlement of commodity derivative instruments used for
hedging purposes, will generally result in a range of prices for those purchases contemplated by the risk management strategy.
Foreign Currency Exchange Risk
We manage our foreign exchange risk exposure associated with anticipated future purchases of nuclear fuel processing services denominated in foreign currencies by utilizing currency forward contracts. As a result of holding these contracts as hedges, our exposure to foreign currency risk is minimal. A hypothetical 10% unfavorable change in relevant foreign exchange rates would have resulted in a decrease of approximately $3 million and $6 million in the fair value of currency forward contracts held by us at December 31, 2006 and 2005, respectively.
Interest Rate Risk
We manage our interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. We also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at December 31, 2006 and 2005, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of approximately $6 million, respectively.
Investment Price Risk
We are subject to investment price risk due to marketable securities held as investments in decommissioning trust funds. These marketable securities are managed by third-party investment managers and are reported in our Consolidated Balance Sheets at fair value. We recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $36 million and $32 million in 2006 and 2005, respectively. We recorded, in AOCI, gross unrealized gains on these investments of $86 million in 2006 and net unrealized gains of $10 million in 2005.
Dominion sponsors employee pension and other postretirement benefit plans, in which our employees participate, that hold investments in trusts to fund benefit payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in our recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash that we will provide to Dominion, representing our share of employee benefit plan contributions.
Risk Management Policies
We have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the risk management policies of all subsidiaries, including the Company. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on Dominion’s credit policies and our December 31, 2006 provision for credit losses, management believes that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
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ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index
Page No.
Report of Management’s Responsibilities
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the years ended December 31, 2006, 2005 and 2004
Consolidated Balance Sheets at December 31, 2006 and 2005
Consolidated Statements of Common Shareholder’s Equity and Comprehensive Income at December 31, 2006, 2005 and 2004 and for the years then ended
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004
Notes to Consolidated Financial Statements
REPORT OF MANAGEMENT’S RESPONSIBILITIES
Because we are not an accelerated filer as defined in Exchange Act Rule 12b-2, we are not required to comply with Securities and Exchange Commission rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 until December 31, 2007.
Our management is responsible for all information and representations contained in our Consolidated Financial Statements and other sections of our annual report on Form 10-K. Our Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with accounting principles generally accepted in the United States of America. Other financial information in the Form 10-K is consistent with that in our Consolidated Financial Statements.
Management maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that our assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal control and, therefore, cannot provide absolute assurance that the objectives of the established internal controls will be met. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. Management believes that during 2006 the system of internal control was adequate to accomplish the intended objectives.
The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, who have been engaged by Dominion’s Audit Committee, which is comprised entirely of independent directors. Deloitte & Touche LLP’s audit was conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States).
The Board of Directors also serves as our Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss our auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.
Management recognizes its responsibility for fostering a strong ethical climate so that our affairs are conducted according to the highest standards of personal corporate conduct. This responsibility is characterized and reflected in our code of ethics, which addresses potential conflicts of interest, compliance with all domestic and foreign laws, the confidentiality of proprietary information and full disclosure of public information.
February 28, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Virginia Electric and Power Company
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income, common shareholder’s equity and comprehensive income, and of cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting to adopt a new accounting standard for conditional asset retirement obligations in 2005.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 28, 2007
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of our Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of our Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY AND COMPREHENSIVE INCOME
The accompanying notes are an integral part of our Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of our Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS
Virginia Electric and Power Company (the Company), a Virginia public service company, is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). We are a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. We serve approximately 2.3 million retail customer accounts, including governmental agencies and wholesale customers such as rural electric cooperatives and municipalities. In 2005, we became a member of PJM Interconnection, LLC (PJM), a regional transmission organization (RTO), and integrated our electric transmission facilities into the PJM wholesale electricity markets.
As discussed in Note 8, on December 31, 2005, we completed a transfer of our indirect wholly-owned subsidiary, Virginia Power Energy Marketing, Inc. (VPEM), to Dominion through a series of dividend distributions, in exchange for a capital contribution. VPEM provides fuel and risk management services to us and other Dominion affiliates and engages in energy trading activities. Through VPEM, we had trading relationships beyond the geographic limits of our retail service territory and bought and sold natural gas, electricity and other energy-related commodities. As a result of the transfer, VPEM’s results of operations are no longer included in our Consolidated Financial Statements, and our Consolidated Statements of Income for periods prior to the transfer have been adjusted to reflect VPEM as a discontinued operation. In addition, the discontinued operations of VPEM are included in our Corporate segment results.
We manage our daily operations through three primary operating segments: Delivery, Energy and Generation. In addition, we report our corporate and other functions as a segment. Corporate also includes specific items attributable to our operating segments that are excluded from the profit measures evaluated by management in assessing segment performance or allocating resources among the segments. Our assets remain wholly owned by us and our legal subsidiaries.
The terms “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one of Virginia Electric and Power Company’s consolidated subsidiaries or operating segments or the entirety of Virginia Electric and Power Company, including our Virginia and North Carolina operations and our consolidated subsidiaries.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
General
We make certain estimates and assumptions in preparing our Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America (GAAP). These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.
Our Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of the Company and our majority-owned subsidiaries, and those variable interest entities (VIEs) where we have been determined to be the primary beneficiary.
Certain amounts in our 2005 and 2004 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2006 presentation.
Operating Revenue
Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Our customer receivables at December 31, 2006 and 2005 included $233 million and $263 million, respectively, of accrued unbilled revenue based on estimated amounts of electric energy delivered but not yet billed to our utility customers. We estimate unbilled utility revenue based on historical usage, applicable customer rates, weather factors and total daily electric generation supplied after adjusting for estimated losses of energy during transmission.
The primary types of sales and service activities reported as operating revenue include:
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Regulated electric sales consist primarily of state-regulated retail electric sales, federally-regulated wholesale electric sales and electric transmission services subject to cost-of-service rate regulation; and
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Other revenue consists primarily of excess generation sold at market-based rates, miscellaneous service revenue from electric distribution operations and other miscellaneous revenue.
Electric Fuel and Purchased Energy-Deferred Costs
Where permitted by regulatory authorities, the differences between actual electric fuel and purchased energy expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.
Effective January 1, 2004, the fuel factor provisions for our Virginia retail customers were locked in until July 1, 2007. Effective July 1, 2007, the fuel factor will be adjusted as discussed under Virginia Fuel Expenses in Note 21. Approximately 7.5% of the cost of fuel used in electric generation and energy purchases used to serve utility customers is subject to deferral accounting. Deferred costs associated with the Virginia jurisdictional portion of expenditures incurred through 2003 continue to be reported as a regulatory asset, which is expected to be recovered by July 1, 2007.
Income Taxes
We file a consolidated federal income tax return and participate in an intercompany tax allocation agreement with Dominion and its subsidiaries. Our current income taxes are based on our taxable income or loss, determined on a separate company basis. However, prior to the repeal, effective in 2006, of the Public Utility Holding Company Act of 1935 (the 1935 Act), cash payments to Dominion were limited.
Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes, requires an asset and liability approach to accounting for income taxes. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Where permitted by regulatory authorities, the treatment of temporary differences may differ from the requirements of SFAS No. 109. Accordingly, a regulatory asset is recognized if it is
probable that future revenues will be provided for the payment of deferred tax liabilities. We establish a valuation allowance when it is more likely than not that all, or a portion, of a deferred tax asset will not be realized. Deferred investment tax credits are amortized over the service lives of the properties giving rise to the credits.
At December 31, 2006, our Consolidated Balance Sheet included $105 million of prepaid federal income taxes (recorded in prepayments), $10 million of federal income taxes receivable from Dominion (recorded in deferred charges and other assets) and $26 million of state income taxes payable to Dominion (recorded in accrued interest, payroll and taxes). At December 31, 2005, our Consolidated Balance Sheet included $10 million of prepaid state income taxes (recorded in prepayments), $55 million of prepaid federal income taxes (recorded in deferred charges and other assets), $113 million of federal income taxes payable to Dominion (recorded in accrued interest, payroll and taxes) and $11 million of federal income taxes payable to Dominion (recorded in deferred credits and other liabilities).
Cash and Cash Equivalents
Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 2006 and 2005, accounts payable included $33 million and $39 million, respectively, of checks outstanding but not yet presented for payment. For purposes of our Consolidated Statements of Cash Flows, we consider cash and cash equivalents to include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.
Derivative Instruments
We use derivative instruments such as futures, swaps, forwards, options and financial transmission rights (FTRs) to manage the commodity and financial market risks of our business operations.
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, requires all derivatives, except those for which an exception applies, to be reported in our Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting-normal purchases and normal sales-may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.
We hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent we do not hold offsetting positions for such derivatives, we believe these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices, interest rates and foreign exchange rates.
Statement of Income Presentation:
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Financially-Settled Derivatives-Not Held for Trading Purposes and Not Designated as Hedging Instruments: All unrealized changes in fair value and settlements are presented in other operations and maintenance expense on a net basis.
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Physically-Settled Derivatives-Not Held for Trading Purposes and Not Designated as Hedging Instruments: All unrealized changes in fair value and settlements for physical derivative sales contracts are presented in revenues, while all unrealized changes in fair value and settlements for physical derivative purchase contracts are presented in expenses.
We recognize revenue or expense from all non-derivative energy-related contracts on a gross basis at the time of contract performance, settlement or termination.
DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS
We designate certain derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, we formally document the relationship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using the hedging instrument. We assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, we may elect to exclude certain gains or losses on hedging instruments from the measurement of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. We discontinue hedge accounting prospectively for derivatives that cease to be highly effective hedges.
Cash Flow Hedges-A portion of our hedge strategies represent cash flow hedges of the variable price risk associated with the purchase of natural gas and electricity. We also use foreign currency forward contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge our exposure to variable interest rates on long-term debt. For transactions in which we are hedging the variability of cash flows, changes in the fair value of the derivative are reported in accumulated other comprehensive income (loss) (AOCI), to the extent they are effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. For cash flow hedge transactions, we discontinue hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. We reclassify any derivative gains or losses reported in AOCI to earnings when the forecasted item is included in earnings, if it should occur, or earlier, if it becomes probable that the forecasted transaction will not occur.
Fair Value Hedges-Prior to the transfer of VPEM, we also used fair value hedges to mitigate the fixed price exposure inherent in certain natural gas inventory. We continue to use designated interest rate swaps as fair value hedges to manage our interest rate exposure on certain fixed-rate long-term debt. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value.
Statement of Income Presentation-Gains and losses on derivatives designated as hedges, when recognized, are included in
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED
operating revenue, operating expenses or interest and related charges in our Consolidated Statements of Income. Specific line item classification is determined based on the nature of the risk underlying individual hedge strategies. The portion of gains or losses on hedging instruments determined to be ineffective and the portion of gains or losses on hedging instruments excluded from the measurement of the hedging relationship’s effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, are included in other operations and maintenance expense.
As discussed in Note 8, on December 31, 2005 we completed the transfer of VPEM to Dominion. VPEM manages a portfolio of commodity contracts held for trading and nontrading purposes. As a result of the transfer of VPEM to Dominion, these derivatives are no longer included in our Consolidated Financial Statements, and our Consolidated Statements of Income for periods prior to the transfer have been adjusted to reflect VPEM as a discontinued operation.
VALUATION METHODS
Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, we seek indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, we must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis.
For options and contracts with option-like characteristics where pricing information is not available from external sources, we generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. We use other option models under special circumstances, including a Spread Approximation Model, when contracts include different commodities or commodity locations and a Swing Option Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, we estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.
Nuclear Decommissioning Trust Funds
We account for and classify all investments in marketable debt and equity securities held by our nuclear decommissioning trusts as available-for-sale securities. Available-for-sale securities are reported at fair value with realized gains and losses and any other- than-temporary declines in fair value included in other income and unrealized gains and losses reported as a component of AOCI, net of tax.
We analyze all securities classified as available-for-sale to determine whether a decline in fair value should be considered other than temporary. Prior to 2006, we used several criteria to evaluate other-than-temporary declines, including the length of time over which the market value has been lower than its cost, the percentage of the decline as compared to its cost and the expected
fair value of the security. If a decline in fair value was determined to be other than temporary, the security was written down to its fair value at the end of the reporting period.
In 2006, we changed our method of assessing other-than-temporary declines such that the intent and ability to hold individual securities for a period of time sufficient to allow for the anticipated recovery in their market value must be demonstrated prior to the consideration of the other criteria mentioned above. Since regulatory authorities limit our ability to oversee the day-to-day management of our nuclear decommissioning trust fund investments, we do not have the ability to hold individual securities in the trusts. Accordingly, we consider all securities held by our nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired.
Property, Plant and Equipment
Property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as it is incurred. In 2006, 2005 and 2004, we capitalized interest costs of $10 million, $6 million and $7 million, respectively. In 2006, 2005 and 2004, for electric distribution and electric transmission property subject to cost-of-service utility rate regulation, we capitalized an allowance for funds used during construction of $11 million, $2 million and $2 million, respectively.
For electric distribution and electric transmission property subject to cost-of-service rate regulation, the depreciable cost of such property, less salvage value, is charged to accumulated depreciation at retirement. Cost of removal collections from utility customers and expenditures not representing asset retirement obligations (AROs) are recorded as regulatory liabilities or regulatory assets.
For generation-related and nonutility property, cost of removal not associated with AROs is charged to expense as incurred. We record gains and losses upon retirement of generation-related and nonutility property based upon the difference between proceeds received, if any, and the property’s net book value at the retirement date.
Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. Our depreciation rates on utility property, plant and equipment are as follows:
Our nonutility property, plant and equipment is depreciated using the straight-line method over 25 years.
Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. We report the amortization of nuclear fuel in electric fuel and energy purchases expense in our Consolidated Statements of Income and in depreciation and amortization in our Consolidated Statements of Cash Flows.
Emissions Allowances
Emissions allowances are issued by the Environmental Protection Agency (EPA) and permit the holder of the allowance to emit certain gaseous by-products of fossil fuel combustion, including sulfur dioxide (SO2) and nitrogen oxide (NOx). Allowances may be transacted with third parties or consumed as these emissions are generated. Allowances allocated to or acquired by our generation operations are held primarily for consumption and are classified as intangible assets in our Consolidated Balance Sheets. Carrying amounts are based on our cost to acquire the allowances. Allowances issued directly to us by the EPA are carried at zero cost.
Emissions allowances are amortized in the periods they are consumed, with the amortization reflected in depreciation and amortization expense in our Consolidated Statements of Income. We report purchases and sales of these allowances as investing activities in our Consolidated Statements of Cash Flows and gains or losses resulting from sales in other operations and maintenance expense in our Consolidated Statements of Income.
Impairment of Long-Lived and Intangible Assets
We perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.
Regulatory Assets and Liabilities
For utility operations subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, we defer these costs as regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates and when revenue is collected from customers for expenditures that are not yet incurred. Regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the recovery period authorized by the regulator.
Asset Retirement Obligations
We recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities. These amounts are capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, we estimate fair value using discounted cash flow analyses. We report the accretion of the AROs due to the passage of time in other operations and maintenance expense in our Consolidated Statements of Income.
Amortization of Debt Issuance Costs
We defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation have also been deferred and are amortized over the lives of the new issues.
NOTE 3. NEWLY ADOPTED ACCOUNTING STANDARDS
SAB 108
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB 108 provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether the current year’s financial statements are materially misstated. Our adoption of SAB 108 on December 31, 2006 had no impact on our Consolidated Financial Statements.
FIN 47
We adopted Financial Accounting Standards Board (FASB) Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47) on December 31, 2005. FIN 47 clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is incurred-generally upon acquisition, construction, or development and/or through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. Our adoption of FIN 47 resulted in the recognition of an after-tax charge of $4 million, representing the cumulative effect of the change in accounting principle.
Presented below is our pro forma net income for 2005 and 2004 as if we had applied the provisions of FIN 47 as of January 1, 2004:
If we had applied the provisions of FIN 47 as of January 1, 2004, our asset retirement obligations would have increased by $8 million as of January 1, 2004 and December 31, 2004.
NOTE 4. RECENTLY ISSUED ACCOUNTING STANDARDS
FIN 48
In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). Taking into consideration the uncertainty and judgement involved in the determination and filing of income taxes, FIN 48 establishes standards for recognition and measurement, in the financial statements, of positions taken, or expected to be taken, by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED
a more-likely-than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.
Beginning in 2007, FIN 48 requires disclosures about positions taken by an entity in its tax returns that are not recognized in its financial statements, descriptions of open tax years by major jurisdiction and reasonably possible significant changes in the amount of unrecognized tax benefits that could occur in the next twelve months.
With the adoption of FIN 48, we estimate that the cumulative effect of the change in accounting principle will not have a material impact on the beginning balance of our retained earnings as of January 1, 2007.
SFAS NO. 157
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The provisions of SFAS No. 157 will become effective for us beginning January 1, 2008. Generally, the provisions of this statement are to be applied prospectively. Certain situations, however, require retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application is required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses under Emerging Issues Task Force (EITF) Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, and SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. We are currently evaluating the impact that SFAS No. 157 will have on our results of operations and financial condition.
SFAS NO. 159
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each eligible item. The provisions of SFAS No. 159 will become effective for us beginning January 1, 2008. Early adoption is permitted provided that an election is also made to apply the provisions of SFAS No. 157. We are currently evaluating the impact that SFAS No. 159 may have on our results of operations and financial condition.
NOTE 5. OPERATING REVENUE
Our operating revenue consists of the following:
NOTE 6. INCOME TAXES
Details of income tax expense for continuing operations were as follows:
The statutory United States (U.S.) federal income tax rate reconciles to our effective income tax rates as follows:
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Our net deferred income taxes consist of the following:
At December 31, 2006, we had federal and state minimum tax credits of $58 million that do not expire and other federal and state income tax credits of $2 million that will expire if unutilized by 2025.
We are routinely audited by federal and state tax authorities. We establish liabilities for tax-related contingencies and review them in light of changing facts and circumstances. Although the results of these audits are uncertain, we believe that the ultimate outcome will not have a material adverse effect on our financial position. At December 31, 2006 and 2005, our Consolidated Balance Sheets included no material income tax-related contingent liabilities.
American Jobs Creation Act of 2004 (the Act)
The Act has several provisions for energy companies, including a deduction related to taxable income derived from qualified production activities. Our electric generation activities qualify as production activities under the Act. The Act limits the deduction to the lesser of taxable income derived from qualified production activities or the consolidated federal taxable income of Dominion and its subsidiaries. Our qualified production activities deduction for 2006 is minimal.
NOTE 7. HEDGE ACCOUNTING ACTIVITIES
We are exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products purchased, as well as currency exchange and interest rate risks of our business operations. We use derivative instruments to manage our exposure to these risks and designate derivative instruments as fair value or cash flow hedges for accounting purposes as allowed by SFAS No. 133.
For the year ended December 31, 2006, there were no gains or losses on hedging instruments that were determined to be ineffective. For the year ended December 31, 2005, we recognized in net income $11 million of gains as hedge ineffectiveness and $4 million of gains attributable to differences between spot prices and forward prices that are excluded from the measurement of effectiveness, in connection with fair value hedges of natural gas inventory. The 2005 activity was related to the discontinued operations of VPEM.
The following table presents selected information related to cash flow hedges included in AOCI in our Consolidated Balance Sheet at December 31, 2006:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated purchases) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign exchange rates.
NOTE 8. DISCONTINUED OPERATIONS-VPEM TRANSFER
On December 31, 2005, we completed the transfer of VPEM to Dominion through a series of dividend distributions. This resulted in a transfer of our negative investment in VPEM to Dominion in exchange for a capital contribution of $633 million. No gain or loss was recognized on the transfer.
VPEM provides fuel and risk management services to us by acting as an agent for one of our indirect wholly-owned subsidiaries. VPEM also engages in energy trading activities and provides price risk management services to other Dominion affiliates through the use of derivative contracts. While we owned VPEM, certain of these derivative contracts were reported at fair value in our Consolidated Balance Sheets, with changes in fair value reflected in earnings. These price risk management activities performed on behalf of Dominion affiliates generated derivative gains and losses that affected our Consolidated Financial Statements.
As a result of the transfer, VPEM’s results of operations are no longer included in our Consolidated Financial Statements, and our Consolidated Statements of Income for periods prior to the transfer have been adjusted to reflect VPEM as a discontinued operation, on a net basis. For 2005 and 2004, our discontinued operations included operating revenue of $807 million and $373 million, respectively, and a loss before income taxes of $746 million and $259 million, respectively. VPEM’s 2005 and 2004 results included the following affiliated transactions:
NOTE 9. NUCLEAR DECOMMISSIONING TRUST FUNDS
We hold marketable debt and equity securities in nuclear decommissioning trust funds to fund future decommissioning costs for our nuclear plants. Our decommissioning trust funds, as of December 31, 2006 and 2005, are summarized below:
(1) In 2005, approximately $2 million of unrealized losses relate primarily to equity securities in a loss position for greater than one year.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED
The fair values of debt securities within the nuclear decommissioning trust funds at December 31, 2006 by contractual maturity are as follows:
Gross realized gains on the sale of available-for-sale securities totaled $49 million, $19 million and $27 million in 2006, 2005 and 2004, respectively, and gross realized losses totaled $33 million, $8 million and $24 million in 2006, 2005 and 2004, respectively. In determining realized gains and losses, the cost of these securities was determined on a specific identification basis.
NOTE 10. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment and their respective balances are:
Jointly-Owned Utility Plants
Our proportionate share of jointly-owned utility plants at December 31, 2006 is as follows:
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. We report our share of operating costs in the appropriate operating expense (electric fuel and energy purchases, other operations and maintenance, depreciation and amortization and other taxes, etc.) in our Consolidated Statements of Income.
NOTE 11. INTANGIBLE ASSETS
All of our intangible assets are subject to amortization over their estimated useful lives. Amortization expense for intangible assets was $37 million, $38 million and $27 million for 2006, 2005 and 2004, respectively. In 2006, we acquired $58 million of emissions allowances with an estimated weighted-average amortization period of 3.8 years. The components of our intangible assets are as follows:
Annual amortization expense for intangible assets is estimated to be $48 million for 2007, $30 million for 2008, $23 million for 2009, $28 million for 2010 and $12 million for 2011.
NOTE 12. REGULATORY ASSETS AND LIABILITIES
Our regulatory assets and liabilities include the following:
(1) In connection with the settlement of the 2003 Virginia fuel rate proceeding, we agreed to recover previously incurred costs through June 30, 2007 without a return on a portion of the unrecovered balance. Remaining costs to be recovered totaled $56 million at December 31, 2006.
(2) The Federal Energy Regulatory Commission (FERC) has conditionally authorized our deferral of start-up costs incurred in connection with joining an RTO and on-going administration fees paid to PJM. We have deferred $58 million in start-up costs and administration fees and $8 million of associated carrying costs. We expect recovery from Virginia jurisdictional retail customers to commence at the end of the Virginia retail rate cap period, subject to regulatory approval.
(3) Income taxes recoverable through future rates resulting from the recognition of additional deferred income taxes, not recognized under ratemaking practices.
(4) The North Carolina Utilities Commission (North Carolina Commission) has authorized the deferral of previously incurred costs associated with the termination of certain long-term power purchase agreements with nonutility generators. The related costs are being amortized over the original term of each agreement.
(5) The cost of decommissioning the Department of Energy’s (DOE) uranium enrichment facilities represents the unamortized portion of our required contributions to a fund for decommissioning and decontaminating the DOE’s uranium enrichment facilities. The contributions began in June 1992 and will continue over a 15-year period with escalation for inflation. These costs are currently being recovered in fuel rates through June 30, 2007.
(6) Rates charged to customers by our regulated business include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.
At December 31, 2006, approximately $143 million of our regulatory assets represented past expenditures on which we do not earn a return. These expenditures consist primarily of RTO start-up costs and administration fees, the cost of terminating certain power purchase agreements and a portion of deferred fuel costs.
NOTE 13. ASSET RETIREMENT OBLIGATIONS
Our AROs are primarily associated with the decommissioning of our nuclear generation facilities. We also have AROs related to certain electric transmission and distribution assets located on property that we do not own and hydroelectric generation facilities. We currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets. Thus, AROs for these assets will not be reflected in our Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. Generally, this will occur
when the expected retirement or abandonment dates are determined by our operational planning. The changes to our AROs during 2006 were as follows:
(1) Primarily reflects a reduction in cost escalation rate assumptions that were applied to updated decommissioning cost studies, which reflected increases in base year costs, received for each of our nuclear facilities during the third quarter of 2006.
We have established trusts dedicated to funding the future decommissioning of our nuclear plants. At December 31, 2006 and 2005, the aggregate fair value of these trusts, consisting primarily of debt and equity securities, totaled $1.3 billion and $1.2 billion, respectively.
NOTE 14. VARIABLE INTEREST ENTITIES
FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (FIN 46R) addresses the consolidation of VIEs. An entity is considered a VIE under FIN 46R if it does not have sufficient equity to finance its activities without assistance from variable interest holders or if its equity investors lack any of the following characteristics of a controlling financial interest:
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control through voting rights,
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the obligation to absorb expected losses, or
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the right to receive expected residual returns.
FIN 46R requires the primary beneficiary of a VIE to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that receives the majority of a VIE’s expected losses, expected residual returns, or both.
Certain variable pricing terms in some of our long-term power and capacity contracts cause them to be considered potential variable interests in the counterparties. Two potential VIEs, with which we have existing power purchase agreements (signed prior to December 31, 2003), have not provided sufficient information for us to perform our FIN 46R evaluation.
As of December 31, 2006, no further information has been received from the two remaining potential VIEs. We will continue our efforts to obtain information and will complete an evaluation of our relationship with each of these potential VIEs if sufficient information is ultimately obtained. We have remaining purchase commitments with these two potential VIE supplier entities of $1.3 billion at December 31, 2006. We are not subject to any risk of loss from these VIEs, other than the remaining purchase commitments. We paid $98 million, $106 million and $111 million for electric generation capacity and $75 million, $102 million and $59 million for electric energy from these entities for the years ended December 31, 2006, 2005 and 2004, respectively.
In February 2006, we restructured three long-term power purchase contracts with two VIEs, of which we are not the primary beneficiary. The restructured contracts expire between 2015
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED
and 2017. Total debt held by the entities is approximately $299 million. We have remaining purchase commitments with these two VIE supplier entities of $1 billion at December 31, 2006. We are not subject to any risk of loss from these VIEs, other than the remaining purchase commitments. We paid $116 million, $116 million and $114 million for electric generation capacity and $55 million, $57 million and $47 million for electric energy from these entities for the years ended December 31, 2006, 2005 and 2004, respectively.
During 2005, we entered into four long-term contracts with unrelated limited liability companies (LLCs) to purchase synthetic fuel produced from coal. Certain variable pricing terms in the contracts protect the equity holders from variability in the cost of their coal purchases, and therefore, the LLCs were determined to be VIEs. After completing our FIN 46R analysis, we concluded that although our interests in the contracts, as a result of their pricing terms, represent variable interests in the LLCs, we are not the primary beneficiary. We paid $341 million and $205 million to the LLCs for coal and synthetic fuel produced from coal for the years ended December 31, 2006 and 2005, respectively. We are not subject to any risk of loss from the contractual arrangements, as our only obligation to the VIEs is to purchase the synthetic fuel that the VIEs produce according to the terms of the applicable purchase contracts.
Our Consolidated Balance Sheets as of December 31, 2006 and 2005 reflect net property, plant and equipment of $337 million and $348 million, respectively and $370 million of debt, related to the consolidation, in accordance with FIN 46R, of a variable interest lessor entity through which we have financed and leased a power generation project. The debt is non-recourse to us and is secured by the entity’s property, plant and equipment. The lease under which we operate the power generation facility terminates in August 2007. We intend to take legal title to the facility through repayment of the lessor’s related debt at the end of the lease term.
NOTE 15. SHORT-TERM DEBT AND CREDIT AGREEMENTS
We use short-term debt, primarily commercial paper, to fund working capital requirements and as a bridge to long-term debt financing. The level of our borrowings may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. Short-term financing is supported by a $3.0 billion five-year joint revolving credit facility dated February 2006 with Dominion and Consolidated Natural Gas Company (CNG), a wholly-owned subsidiary of Dominion, which is scheduled to terminate in February 2011. This credit facility is being used for working capital, as support for the combined commercial paper programs of Dominion, CNG and us and other general corporate purposes. This credit facility can also be used to support up to $1.5 billion of letters of credit.
At December 31, 2006, total outstanding commercial paper supported by the joint credit facility was $1.76 billion, of which our borrowings were $618 million, with a weighted average interest rate of 5.41%. At December 31, 2005, total outstanding commercial paper supported by the previous joint credit facility was $1.4 billion, of which our borrowings were $905 million, with a weighted average interest rate of 4.46%.
At December 31, 2006, total outstanding letters of credit supported by the joint credit facility was $236 million, of which less than $1 million were issued on our behalf. At December 31, 2005, total outstanding letters of credit supported by the previous joint credit facility was $892 million, of which less than $1 million were issued on our behalf.
At December 31, 2006, capacity available under the joint credit facility was $1.0 billion.
NOTE 16. LONG-TERM DEBT
(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2006.
(2) Substantially all of our property is subject to the lien of the mortgage, securing our mortgage bonds.
(3) Represents debt associated with a special purpose lessor entity that is consolidated in accordance with FIN 46R. The debt is nonrecourse to us and is secured by the entity’s property, plant and equipment, which totaled $337 million and $348 million at December 31, 2006 and 2005, respectively.
(4)
On December 15, 2008, the securities are subject to redemption at par plus accrued interest, unless holders of related options exercise rights to purchase and remarket the notes.
(5) These financings relate to certain pollution control equipment at our generating facilities. The variable rate tax-exempt financings are supported by a stand-alone $3 billion five-year credit facility that terminates in February 2011. In February 2007, we exercised our call option and redeemed $62 million of our tax-exempt financings with a weighted average rate of 7.52%, with proceeds raised through the issuance of commercial paper.
(6) Represents the valuation of certain fair value hedges associated with our fixed- rate debt.
Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2006 were as follows:
Our short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2006, there were no events of default under our covenants.
Junior Subordinated Notes Payable to Affiliated Trust
In 2002, we established a subsidiary capital trust, Virginia Power Capital Trust II (trust), a finance subsidiary of which we hold 100% of the voting interests. The trust sold 16 million 7.375% trust preferred securities for $400 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trust. In exchange for the $400 million realized from the sale of the trust preferred securities and $12 million of common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trust, we issued $412 million of 2002 7.375% junior subordinated notes (junior subordinated notes) due July 30, 2042. The junior subordinated notes constitute 100% of the trust’s assets. The trust must redeem its trust preferred securities when the junior subordinated notes are repaid or if redeemed prior to maturity.
Distribution payments on the trust preferred securities are considered to be fully and unconditionally guaranteed by the Company when all of the related agreements are taken into consideration. Each guarantee agreement only provides for the guarantee of distribution payments on the trust preferred securities to the extent that the trust has funds legally and immediately available to make distributions. The trust’s ability to pay amounts when they are due on the trust preferred securities is dependent solely upon our payment of amounts when they are due on the junior subordinated notes. If the payment on the junior subordinated notes is deferred, we may not make distributions related to our capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, we may not make any payments on, redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the junior subordinated notes.
NOTE 17. PREFERRED STOCK
We are authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference, and had 2.59 million preferred shares outstanding as of December 31, 2006 and 2005. Upon involuntary liquidation, dissolution or winding-up of the Company, each share would be entitled to receive $100 plus accrued dividends. Dividends are cumulative.
Holders of the outstanding preferred stock are not entitled to voting rights, except under certain provisions of the amended and restated articles of incorporation and related provisions of Virginia law restricting corporate action, or upon default in dividends, or in special statutory proceedings and as required by Vir-
ginia law (such as mergers, consolidations, sales of assets, dissolution and changes in voting rights or priorities of preferred stock).
Presented below are the series of preferred stock not subject to mandatory redemption that were outstanding as of December 31, 2006:
(1) Through 7/31/2007; $102.12 commencing 8/1/2007; amounts decline in steps thereafter to $100.00 by 8/1/2013.
(2) Through 8/31/2007; $102.10 commencing 9/1/2007; amounts decline in steps thereafter to $100.00 by 9/1/2013.
(3) Dividend rate is 5.50% through 12/20/2007; after which, the rate will be determined according to periodic auctions for periods established by us at the time of the auction process. This series is not callable prior to 12/20/2007.
NOTE 18. SHAREHOLDER’S EQUITY
Common Stock
In 2004, as approved by the Virginia State Corporation Commission (Virginia Commission), Dominion made an equity investment in the Company through the purchase of our common stock. We issued 20,115 shares of our common stock to Dominion for cash consideration of $500 million.
Other Paid-In Capital
In 2005, we recorded contributed capital of $633 million related to the transfer of our investment in VPEM to Dominion and $200 million in connection with the conversion of short-term borrowings. In 2004, we recorded $11 million of other paid-in capital in connection with the reduction in amounts payable to Dominion.
Accumulated Other Comprehensive Income
Presented in the table below is a summary of AOCI by component:
NOTE 19. DIVIDEND RESTRICTIONS
The Virginia Commission may prohibit any public service company from declaring or paying a dividend to an affiliate, if found to be detrimental to the public interest. At December 31, 2006, the Virginia Commission had not restricted our payment of dividends.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED
Certain agreements associated with our joint credit facility with Dominion and CNG contain restrictions on the ratio of our debt to total capitalization. These limitations did not restrict our ability to pay dividends to Dominion at December 31, 2006.
See Note 16 for a description of potential restrictions on our dividend payments in connection with the deferral of distribution payments on trust preferred securities.
NOTE 20. EMPLOYEE BENEFIT PLANS
We participate in a defined benefit pension plan sponsored by Dominion. Benefits payable under the plan are based primarily on years of service, age and the employee’s compensation. As a participating employer, we are subject to Dominion’s funding policy, which is to generally contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income Security Act of 1974. Our net periodic pension cost was $63 million, $56 million and $40 million in 2006, 2005 and 2004, respectively. We did not contribute to the pension plan in 2006, 2005 or 2004.
We participate in plans that provide certain retiree health care and life insurance benefits to multiple Dominion subsidiaries. Annual employee premiums are based on several factors such as age, retirement date and years of service. Our net periodic benefit cost related to these plans was $37 million, $42 million and $44 million in 2006, 2005 and 2004, respectively.
Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits in excess of benefits actually paid during the year must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, we fund postretirement benefit costs through Voluntary Employees’ Beneficiary Associations. Our contributions to retiree health care and life insurance plans were $24 million, $32 million and $34 million in 2006, 2005 and 2004, respectively. We expect to contribute $13 million to retiree health care and life insurance plans in 2007.
We also participate in Dominion-sponsored employee savings plans that cover substantially all employees. Employer matching contributions of $11 million each were incurred in 2006, 2005 and 2004.
NOTE 21. COMMITMENTS AND CONTINGENCIES
As the result of issues generated in the ordinary course of business, we are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings will not have a material effect on our financial position, liquidity or results of operations.
Long-Term Purchase Agreements
At December 31, 2006, we had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:
(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2006, the present value of our total commitment for capacity payments is $2.6 billion. Capacity payments totaled $437 million, $472 million and $570 million, and energy payments totaled $291 million, $378 million and $293 million for 2006, 2005, and 2004, respectively.
Lease Commitments
We lease various facilities, vehicles and equipment primarily under operating leases. The lease agreements expire on various dates and certain of the leases are renewable and contain options to purchase the leased property. Payments under certain leases are escalated based on an index such as the Consumer Price Index (CPI). Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2006 are as follows:
Thereafter
Total
(millions)
$28
$25
$19
$16
$13
$27
$128
Rental expense totaled $34 million, $32 million and $40 million for 2006, 2005 and 2004, respectively, the majority of which is reflected in other operations and maintenance expense.
Environmental Matters
We are subject to costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
To the extent that environmental costs are incurred in connection with operations regulated by the Virginia Commission during the period ending December 31, 2010, in excess of the level currently included in Virginia jurisdictional rates, our results of operations will decrease. After that date, we may seek recovery through rates of only those environmental costs related to our transmission and distribution operations. However, the foregoing risks are subject to change upon the adoption, if any, of the proposed 2007 Virginia Restructuring Act Amendments as discussed later under 2007 Virginia Restructuring Act Amendments.
SUPERFUND SITES
From time to time, we may be identified as a potentially responsible party (PRP) to a Superfund site. The EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, we may be responsible for the costs of remedial investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. We do not believe that any currently identified sites will result in significant liabilities.
In 1987, we and a number of other entities were identified by the EPA as PRPs at two Superfund sites located in Kentucky and Pennsylvania. In 2003, the EPA issued its Certificate of Completion of remediation for the Kentucky site. Future costs for the Kentucky site will be limited to minor operations and maintenance expenditures. Regarding the Pennsylvania site, in March 2006, a federal district court approved three consent decrees between the U.S. and the PRPs, under which we and certain other PRPs, all of which are utilities, will perform the site remediation. The remediation costs are expected to be in the range of $11 million to $18 million, the majority of which are to be paid by the non-utility site owners. After evaluating the impact of these actions, we have reduced our current reserve from $2 million to less than $1 million to meet our potential obligations at these two sites. We generally seek to recover our costs associated with environmental remediation from third-party insurers. At December 31, 2006, no pending or possible insurance claims were recognized as an asset or offset against obligations.
Nuclear Operations
NUCLEAR DECOMMISSIONING-MINIMUM FINANCIAL ASSURANCE
The Nuclear Regulatory Commission (NRC) requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Our 2006 NRC minimum financial assurance amount, aggregated for our nuclear units, was $1.3 billion and has been satisfied by a combination of the funds being collected and deposited in the trusts and the real annual rate of return growth of the funds allowed by the NRC.
NUCLEAR INSURANCE
The Price-Anderson Act provides the public up to $10.8 billion of protection per nuclear incident via obligations required of owners of nuclear power plants. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. We have purchased $300 million of coverage from commercial insurance pools with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., we could be assessed up to $100.6 million for each of our four licensed reactors, not to exceed $15 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The Price-Anderson Act was first enacted in 1957 and was renewed again in 2005.
Our current level of property insurance coverage ($2.55 billion each for North Anna and Surry, individually) exceeds the NRC’s minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Our nuclear property insurance is provided by the Nuclear Electric Insurance Limited (NEIL), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $50 million. Based on the severity of the incident, the board of directors of our nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. We have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.
We purchase insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, we are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period’s maximum assessment is $19 million.
Old Dominion Electric Cooperative (ODEC), a part owner of North Anna Power Station, is responsible to us for its share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.
SPENT NUCLEAR FUEL
Under provisions of the Nuclear Waste Policy Act of 1982, we have entered into a contract with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by our contract with the DOE. In January 2004, we, with Dominion, filed a lawsuit in the U.S. Court of Federal Claims against the DOE in connection with its failure to commence accepting spent nuclear fuel. Trial is scheduled for March 2008. We will continue to manage our spent fuel until it is accepted by the DOE.
Litigation
We are co-owners with ODEC of the Clover electric generating facility. In 1989, we entered into a coal transportation agreement with Norfolk Southern Railway Company (Norfolk Southern) for the delivery of coal to the facility. The agreement provided for a base rate price adjustment based upon a published index. Norfolk Southern claimed in October 2003 that an incorrect reference index was used to adjust the base transportation rate. In November 2003, we and ODEC filed suit against Norfolk Southern seeking to clarify the price escalation provisions of the transportation agreement. The trial court has ruled in Norfolk Southern’s favor by concluding that the agreement specifies the higher rate adjustment factor which Norfolk Southern claims should have been applied in the past to adjust the base rate and which will be applied in the future. On September 1, 2006, the court entered an order directing us and ODEC to correct invoices
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED
from December 1, 2003 to the present by calculating rates under the higher rate adjustment factor as if it had been applied from the inception of the agreement, to tender the difference to Norfolk Southern with interest at the rate provided by the agreement and to calculate future invoices using the higher rate adjustment factor as if it had been applied from the inception of the agreement. The cumulative amount of the adjustment as of the time the court entered its order was approximately $50 million plus interest, of which our share would be one half. We and ODEC have filed a notice of appeal to the Virginia Supreme Court and have posted security to suspend execution of the judgment during the appeal. We believe the court’s interpretation of the transportation agreement and its ruling on other issues in the case are legally incorrect. No liability has been recorded in our Consolidated Financial Statements related to this matter.
Guarantees and Surety Bonds
As of December 31, 2006, we had issued $6 million of guarantees primarily to support commodity transactions of subsidiaries. We had also purchased $68 million of surety bonds for various purposes, including the posting of security to suspend execution of the judgment during the appeal of the Norfolk Southern matter, as discussed in Litigation, and providing workers’ compensation coverage. Under the terms of surety bonds, we are obligated to indemnify the respective surety bond company for any amounts paid.
Indemnifications
As part of commercial contract negotiations in the normal course of business, we may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. We are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate us have not yet occurred or, if any such event has occurred, we have not been notified of its occurrence. However, at December 31, 2006, we believe future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on our results of operations, cash flows or financial position.
Stranded Costs
Stranded costs are generation-related costs incurred or commitments made by utilities under cost-based regulation that may not be reasonably expected to be recovered in a competitive market. At December 31, 2006, our exposure to potential stranded costs included long-term power purchase contracts that could ultimately be determined to be above market prices; generating plants that could possibly become uneconomical in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits. We believe capped electric retail rates will provide an opportunity to recover our potential stranded costs, depending on market prices of electricity and other factors. Recovery of our potential stranded costs remains subject to numerous risks even in the capped-rate
environment. These risks include, among others, exposure to long-term power purchase commitment losses, future environmental compliance requirements, changes in certain tax laws, nuclear decommissioning costs, increased fuel costs, inflation, increased capital costs and recovery of certain other items.
The Virginia Electric Utility Restructuring Act was enacted in 1999 (1999 Virginia Restructuring Act) and established a plan to restructure the electric utility industry in Virginia. Under the 1999 Virginia Restructuring Act, the generation portion of our Virginia jurisdictional operations is no longer subject to cost-based regulation. The legislation’s deregulation of generation was an event that required us to discontinue the application of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to the Virginia jurisdictional portion of our generation operations in 1999. The 1999 Virginia Restructuring Act permits wires charges to be collected by utilities until July 1, 2007. Our wires charges are set at zero in 2007 for all rate classes, and as such, Virginia customers will not pay the fee if they switch from us to a competitive service provider.
Virginia Fuel Expenses
In May 2006, Virginia law was amended to modify the way our Virginia jurisdictional fuel factor is set during the three and one-half year period beginning July 1, 2007. The bill became law effective July 1, 2006 and:
n
Allows annual fuel rate adjustments for three twelve-month periods beginning July 1, 2007 and one six-month period beginning July 1, 2010 (unless capped rates are terminated earlier under the 1999 Virginia Restructuring Act);
n
Allows an adjustment at the end of each of the twelve-month periods to account for differences between projections and actual recovery of fuel costs during the prior twelve months; and
n
Authorizes the Virginia Commission to defer up to 40% of any fuel factor increase approved for the first twelve-month period, with recovery of the deferred amount over the two and one-half year period beginning July 1, 2008 (under prior law, such a deferral was not possible).
Fuel prices have increased considerably since our Virginia fuel factor provisions were frozen in 2004, which has resulted in our fuel expenses being significantly in excess of our rate recovery. We expect that fuel expenses will continue to exceed rate recovery until our fuel factor is adjusted in July 2007. While the 2006 amendments do not allow us to collect any unrecovered fuel expenses that were incurred prior to July 1, 2007, once our fuel factor is adjusted, the risk of under-recovery of prudently incurred fuel costs until July 1, 2010 is greatly diminished.
2007 Virginia Restructuring Act Amendments
In February 2007, both houses of the Virginia General Assembly passed identical bills that would significantly change electricity restructuring in Virginia. The bills would end capped rates two years early, on December 31, 2008. After capped rates end, retail choice would be eliminated for all but individual retail customers with a demand of more than 5-Mw and a limited number of non-residential retail customers whose aggregated load would exceed 5-Mw. Also after the end of capped rates, the Virginia Commis -
sion would set the base rates of investor-owned electric utilities under a modified cost-of-service model. Among other features, the currently proposed model would provide for the Virginia Commission to:
n
Initiate a base rate case for each utility during the first six months of 2009, as a result of which the Virginia Commission:
n
establishes a return on equity (ROE) no lower than that reported by a group of utilities within the southeastern U.S., with certain limitations on earnings and rate adjustments;
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 reduce rates or, alternatively, order a credit to customers if the utility is found to have earnings more than 50 basis points above the established ROE; and
n
may authorize performance incentives if appropriate.
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 CPI 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 CPI;
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.
n
Authorize stand-alone rate adjustments for recovery of certain costs, including new generation projects, major generating unit modifications, environmental compliance projects, FERC-approved costs for transmission service, energy efficiency and conservation programs, and renewable energy programs; and
n
Authorize an enhanced ROE as a financial incentive for construction of major baseload generation projects and for renewable energy portfolio standard programs.
The bills would also continue statutory provisions directing us to file annual fuel cost recovery cases with the Virginia Commission beginning in 2007 and continuing thereafter. However, our fuel factor increase as of July 1, 2007 would be limited to an amount that results in residential customers not receiving an increase of more than 4% of total rates as of that date, and the remainder would be deferred and collected over three years, as follows:
n
in calendar year 2008, the deferral portion collected is limited to an amount that results in residential customers not receiv
ing an increase of more than 4% of total rates as of January 1, 2008;
n
in calendar year 2009, the deferral portion collected is limited to an amount that results in residential customers not receiving an increase of more than 4% of total rates as of January 1, 2009; and
n
the remainder of the deferral balance, if any, would be collected in the fuel factor in calendar year 2010.
The Governor has until March 26, 2007 to sign, propose amendments to, or veto the bills. With the Governor’s signature, the bills would become law effective July 1, 2007. At this time, we cannot predict the outcome of these legislative proposals.
NOTE 22. FAIR VALUE OF FINANCIAL INSTRUMENTS
Substantially all of our financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Fair values have been determined using available market information and valuation methodologies considered appropriate by management. The financial instruments’ carrying amounts and fair values are as follows:
(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.
(2) Includes securities due within one year.
NOTE 23. CREDIT RISK
We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our December 31, 2006 provision for credit losses, that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
We sell electricity and provide distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of our customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers.
Our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED
calculated prior to the application of collateral. At December 31, 2006, our gross credit exposure totaled $51 million. Of this amount, 93% related to a single counterparty; however, the entire balance is with investment grade entities. We held no collateral for these transactions at December 31, 2006.
NOTE 24. RELATED-PARTY TRANSACTIONS
We engage in related-party transactions primarily with affiliates (Dominion subsidiaries). Our accounts receivable and payable balances with affiliates are settled based on contractual terms on a monthly basis, depending on the nature of the underlying transactions. We are included in Dominion’s consolidated federal income tax return and participate in certain Dominion benefit plans.
Transactions with Affiliates
We transact with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. We also enter into certain commodity derivative contracts with affiliates. We use these contracts, which are principally comprised of commodity swaps and options, to manage commodity price risks associated with the purchases and sales of natural gas. We designate the majority of these contracts as cash flow hedges for accounting purposes.
Dominion Resources Services, Inc. (Dominion Services) provides accounting, legal and certain administrative and technical services to us. We provide certain services to affiliates, including charges for facilities and equipment usage.
At December 31, 2005 we transferred VPEM to Dominion in exchange for a $633 million contribution of capital. In doing so, we are no longer involved in facilitating Dominion’s enterprise risk management by entering into certain financial derivative commodity contracts with affiliates. During 2006, VPEM continued to provide fuel management services to us by acting as an agent for one of our other indirect wholly-owned subsidiaries. In December 2006, we entered into an agreement with VPEM which enables us to directly transact with VPEM for the purchase and sale of fuel and the transportation of fuel to our facilities. This agreement has been approved by the Virginia Commission and the North Carolina Commission and became effective January 2007.
The significant transactions with Dominion Services and other affiliates are detailed below:
At December 31, 2006, our Consolidated Balance Sheet includes derivative liabilities with affiliates of $2 million. There were no derivative liabilities with affiliates at December 31, 2005. Unrealized gains or losses, representing the effective portion of the changes in fair value of those derivative contracts that had been designated as cash flow hedges, are included in AOCI in our Consolidated Balance Sheets.
We lease an office building from Dominion under an agreement that expires in 2008. The lease agreement is accounted for
as a capital lease, with capitalized cost of the property under the lease, net of accumulated amortization, of approximately $3 million and $5 million at December 31, 2006 and 2005, respectively. The rental payments for this lease were $3 million each in 2006, 2005 and 2004.
We have borrowed funds from Dominion under both short-term and long-term borrowing arrangements. At December 31, 2006 and 2005, our nonregulated subsidiaries had outstanding borrowings, net of repayments, under the Dominion money pool of $140 million and $12 million, respectively. At December 31, 2006 and 2005, our borrowings from Dominion under a long- term note totaled $220 million. There were no short-term demand note borrowings at December 31, 2006 and 2005. We incurred interest charges related to our borrowings from Dominion of $10 million, $9 million and $6 million in 2006, 2005 and 2004, respectively.
In 2004, as approved by the Virginia Commission, Dominion made an equity investment in the Company through the purchase of our common stock. We issued 20,115 shares of our common stock to Dominion for cash consideration of $500 million. We used the proceeds in part to pay down our $345 million short-term demand note from Dominion. Also, in 2004, we recorded $11 million of other paid-in capital in connection with a reduction in amounts payable to Dominion.
Other Related-Party Transactions
Upon adoption of FIN 46R for our interests in special purpose entities on December 31, 2003, we ceased to consolidate the Virginia Power Capital Trust II, a finance subsidiary of the Company. The junior subordinated notes issued by us and held by the trust are reported as long-term debt. We reported $30 million, $30 million and $31 million of interest expense on the junior subordinated notes payable to affiliated trust in 2006, 2005 and 2004, respectively.
NOTE 25. OPERATING SEGMENTS
We are organized primarily on the basis of products and services sold in the United States. The majority of our revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among our Delivery, Energy and Generation segments. We manage our operations through the following segments:
Delivery includes our regulated electric distribution and customer service businesses. The Delivery segment is subject to cost-of-service rate regulation and accordingly, applies SFAS No. 71.
Energy includes our regulated electric transmission operations, which are subject to cost-of-service rate regulation and accordingly, applies SFAS No. 71.
Generation includes our portfolio of electric generating facilities, power purchase agreements and our energy supply operations.
Corporate includes our corporate and other functions. The contribution to net income by our primary operating segments is determined based on a measure of profit that management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments have been excluded from the profit measures evaluated by management, either in assessing segment performance or in allocating resources among
the segments, including the discontinued operations of VPEM prior to its transfer to Dominion.
In 2006, the Corporate segment includes $12 million of net expenses attributable to our Generation segment. The net expenses in 2006 related to the following:
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A $13 million ($8 million after-tax) impairment charge in the fourth quarter resulting from a change in our method of assessing other-than-temporary declines in the fair value of securities held as investments in our nuclear decommissioning trusts; and
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A $7 million ($4 million after-tax) charge resulting from the write-off of certain assets no longer in use at one of our electric generating facilities.
In 2005, the Corporate segment included $58 million of net expenses attributable to our operating segments. The net expenses in 2005 primarily related to the impact of the following:
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A $77 million ($47 million after-tax) charge resulting from the termination of a long-term power purchase agreement attributable to Generation;
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A $13 million ($8 million after-tax) charge related to the sale of our interest in a long-term power tolling contract attributable to Generation; and
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A $6 million ($4 million after-tax) charge for the cumulative effect of an accounting change, as a result of the adoption of FIN 47.
In 2004, the Corporate segment included $155 million of net expenses attributable to our operating segments. The net expenses in 2004 primarily related to the impact of the following:
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A $184 million ($112 million after-tax) charge related to our interest in a long-term power tolling contract that was divested in 2005, attributable to Generation;
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A $71 million ($43 million after-tax) charge resulting from the termination of three long-term power purchase agreements, attributable to Generation; and
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A $12 million ($7 million after-tax) charge related to an agreement to settle a class action lawsuit involving a dispute over our rights to lease fiber-optic cable along a portion of our electric transmission corridor, attributable to Energy; partially offset by
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An $18 million ($11 million after-tax) benefit from the reduction of expenses accrued in 2003 associated with Hurricane Isabel restoration activities, attributable to Delivery.
The following table presents segment information pertaining to our operations:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED
NOTE 26. QUARTERLY FINANCIAL DATA (UNAUDITED)
A summary of our quarterly results of operations for the years ended December 31, 2006 and 2005 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.
Our 2005 results include the impact of the following significant item:
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First quarter results include a $47 million net after-tax charge in connection with the termination of a long-term power purchase agreement.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Senior management, including our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures are effective. There were no changes in our internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
In accordance with FIN 46R, we have included in our Consolidated Financial Statements a VIE through which we have financed and leased a power generation project. Our Consolidated Balance Sheet as of December 31, 2006 reflects $337 million of net property, plant and equipment and deferred charges and $370 million of related debt attributable to the VIE. As this VIE is owned by unrelated parties, we do not have the authority to dictate or modify, and therefore cannot assess, the disclosure controls and procedures or internal control over financial reporting in place at this entity.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information concerning directors of Virginia Electric and Power Company (VP), each of whom is elected annually, is as follows:
Audit Committee Financial Experts
We are a wholly-owned subsidiary of DRI. As permitted by Securities and Exchange Commission (SEC) rules, our Board of Directors serves as our Company’s Audit Committee and is comprised entirely of executive officers of the Company. Our Board of Directors has determined that Thomas F. Farrell, II and Thomas N. Chewning are “audit committee financial experts” as defined by the SEC and, as executive officers of the Company, are not deemed independent.
Information concerning the executive officers of VP, each of whom is elected annually is as follows:
Code of Ethics
We have adopted a Code of Ethics that applies to our principal executive, financial and accounting officers as well as our employees. This Code of Ethics is available on the corporate governance section of Dominion’s website (www.dom.com). You may also request a copy of the Code of Ethics, free of charge, by writing or telephoning the Company at: Corporate Secretary, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Any waivers or changes to our Code of Ethics will be posted on the Dominion website.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
We are a wholly-owned subsidiary of Dominion. Our Board is comprised of Messrs. Farrell and Chewning, who are executive officers of the Company and are not independent. Because our Board believes that it is more appropriate for our compensation program to be managed under the direction of individuals who are independent, we do not have a compensation committee. Instead, our Board depends on the advice and recommendations of Dominion’s Compensation, Governance and Nominating Committee (CGN Committee), which is comprised of independent directors and has retained the consulting firm of Pearl Meyer & Partners (PMP) to advise them on compensation matters. Our Board approves all compensation paid to VP’s executive officers based on Dominion’s CGN Committee’s recommendations. Neither of our directors, who are officers of the Company and Dominion, receive any compensation for the services they provide as directors. Dominion’s CGN Committee effectively administers one compensation program for all of Dominion.
Executive Compensation Philosophy - The Objectives of Dominion’s Program
Dominion’s executive compensation program is designed to attract, motivate and retain a superior management team, while ensuring that annual and long-term incentive programs align management’s financial success with that of Dominion’s shareholders. Dominion’s management and Board of Directors, through the oversight of the CGN Committee, believe in putting a substantial portion of our senior executives’ compensation at risk based on performance goals established by the CGN Committee. While Dominion benchmarks and sets general compensation levels relative to its peer group of companies (detailed below) and market data in general, it administers the program to meet the needs and requirements of Dominion. This takes into consideration internal equity, experience, scope of responsibility and other concerns. Market data is used as a “reality check” in evaluating our compensation decisions for our senior executives.
Our Process
Each year, the executive compensation program is comprehensively assessed and analyzed. The review process includes, but is not limited to, the following steps:
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A peer group of companies is identified and Dominion is compared with these peer companies based on a number of different financial and stock performance metrics for a number of different measurement periods;
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The CGN Committee reviews the performance of the CEO and other senior officers, including the CEO’s assessment of
the performance of other key officers, and his views on succession and retention issues (our Company and Dominion have the same CEO and CFO);
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The current annual compensation of senior management, and long-term compensation grants made over the past few years are reviewed;
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The appropriate performance metrics and attributes of annual and long-term programs for the next year are considered and discussed;
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The entirety of our compensation program is considered, including periodic reviews of specific benefits and perquisites;
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Base pay, annual incentive pay, long-term pay and total compensation for individual officers are benchmarked against survey data using appropriate job matches and comparable asset and revenue size. The survey data is based on a number of purchased surveys from Mercer HR Consulting, Towers Perrin and other organizations, including industry specific surveys whenever possible. The industry specific surveys provide information on positions at companies of similar size or revenue scope, or general industry data on positions for which we may compete;
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For top officers, if peer group compensation is available for their position, Dominion uses a blend of survey and peer compensation for comparison, as there is competition not only in our own market, but nationally and across industries, for talent;
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The compensation practices of our peer companies are reviewed, including their practices with respect to equity and other grants, benefits and perquisites;
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The compensation of the management team from the standpoint of internal equity, complexity of the job, scope of responsibility and other factors is assessed; and
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Specific market-based conditions and other circumstances for certain executives and competitive business groups are considered.
Dominion’s management has the following involvement with the executive compensation process:
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Dominion’s Financial Planning group identifies companies for inclusion in the peer group based on our industry and the companies used by Dominion analysts and external analysts for comparison purposes. Both Dominion’s CFO and the CGN Committee’s independent compensation consultant, a managing director of PMP, review and comment on the proposed group before it is submitted to the CGN Committee for approval;
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Dominion’s CEO and CFO are both involved in establishing and recommending to the CGN Committee financial goals for the incentive programs based on management’s operational goals and strategic plans; and
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Dominion’s CEO reviews recommendations from Dominion’s director of executive compensation and PMP regarding salaries, annual and long-term incentive targets, and plan amendments and design before recommendations are made to the CGN Committee. While he reviews and makes recommendations for officers, Dominion’s CEO does not make any recommendations or review proposals with regard to his own compensation, with only the CGN Committee having the authority to approve compensation for the senior executives. Also, our independent compensation consultant meets with the CGN Committee, without management present, to review her recommendations. Dominion’s CEO and CFO are also involved in making recommendations about the timing and frequency of long-term programs, special arrangements to
address specific concerns and the elimination or modification of certain benefits.
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Our Board reviews information provided by and considers for approval compensation matters recommended by the CGN Committee.
The Peer Group and Peer Group Comparisons
Dominion’s peer group is generally consistent from year to year, with merger and acquisition activity being the primary reason for any changes. The 2006 peer group for compensation-setting purposes consisted of a diversified group of ten energy companies: American Electric Power Company, Inc.; Constellation Energy Group, Inc.; Duke Energy Corporation; Entergy Corporation; Exelon Corporation; First Energy Corporation; FPL Group, Inc.; Progress Energy, Inc.; Southern Company and TXU Corp.
The CGN Committee, PMP and Dominion’s executive compensation department use the peer company data to (i) compare Dominion’s stock and financial performance against these peers using a number of different metrics and time periods; (ii) analyze compensation practices within the industry; and (iii) benchmark other benefits such as Employment Continuity Agreements and the use of long-term equity vehicles.
Elements of Dominion’s Compensation Program
Our executive compensation program consists of three basic components:
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Base Salary
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Annual Incentives
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Long-Term Incentives
BASE SALARY
Base salary compensates officers, along with the rest of the workforce, for committing significant time to working on the Company’s behalf. In considering annual salary increases, the following factors are assessed: (i) the competitive labor market; (ii) changes in an officer’s scope of responsibility, including promotions; and (iii) individual performance, special skills, experience and other relevant considerations.
While the base salary component of the compensation program generally is targeted at or slightly above market median, the primary goal is compensating executives at a level that best achieves Dominion’s compensation philosophy and addresses internal equity issues. This results in actual pay for some positions that may be higher or lower than a stated target. Dominion has found that peer group and survey results for particular positions can vary greatly from year to year, and considers market trends for certain positions over a period of years rather than a one-year snapshot in setting compensation for those positions.
For 2006 base compensation, all officers received a base salary adjustment of at least 4%. Some officers received salary adjustments in excess of 4% for one of the following reasons: (i) increase or other change in job responsibility; (ii) specific market-based reasons; (iii) exceptional performance; (iv) unique retention or job competitiveness reasons; and/or (v) internal pay equity. Mr. Farrell received a 29% increase in base salary in 2006, when he assumed the duties of CEO of Dominion. Even with this increase, his base salary and targeted total cash compensation were below the median for his peers. The CGN Committee determined to bring his base salary to the market median over the course of a few years, based on his achievements and performance in office. The remaining named executive officers received the following 2006 base salary increases: Mr. Chewning - 13.6%; Mr. McGettrick - 26.5%; Mr. Johnson - 10%; and Mr. Christian - 12%. Mr. Chewning’s increase resulted
in his base pay being slightly above market median in recognition of his experience and superior job performance, and the complexity and scope of his responsibilities. Messrs. McGettrick and Johnson’s base salaries continued to lag behind the market median based on the increasing size of their business units, the effects of several years with no or below market increases in base salary. Messrs. McGettrick and Johnson’s increases were aimed at bringing their base salaries closer to market median. Messrs. McGettrick and Christian’s increases were also due to the competitive nature of their positions and to reward excellent performance.
ANNUAL AND LONG-TERM INCENTIVE PROGRAMS
Annual and long-term incentive programs continue to play a critical role in Dominion’s compensation practices and our philosophy of aligning the interests of officers with those of Dominion’s shareholders while rewarding performance. The annual incentive program is a cash-based program focused on short-term goal accomplishments. The long-term incentive program is weighted equally between a retention component (restricted stock) and a performance component (cash-based performance grant).
Performance-Based Compensation. The performance-based components of Dominion’s incentive program (annual incentive plan and the cash performance grants of our long-term program) motivate and encourage officers and employees to achieve operational excellence that will benefit Dominion’s shareholders. Dominion uses a blend of goals focused on Dominion’s financial achievements overall, specific business unit goals and individual goals. These components allow Dominion to encourage and reward officers and employees for achieving financial goals, as well as operating and stewardship goals such as safety and individual power plant performance.
Annual and long-term incentives are an industry standard and a best practice to motivate employees to achieve performance goals for a portion of their compensation. Performance-based compensation is a large part of executives’ compensation, with senior officers having the most compensation at risk based on performance. This correlates with the influence and responsibility each level of management has for delivering financial results.
For our CEO, Mr. Farrell, just over 50% of his targeted total compensation (annual and long term) is at risk and depends on the achievement of performance goals. For the other named executive officers, targeted compensation at risk ranged from 49% to 44%, and for a typical vice president, the percentage of targeted compensation at risk is approximately 38%. This compares to an average of approximately 11% of total pay at risk for non-officer employees. This structure ensures that if performance goals are not achieved, the officers have compensation that could be significantly lower than market median depending on the extent goals are missed. If performance goals are exceeded, officers will receive compensation that is close to or at the market 75th percentile, depending on the extent that goals are exceeded. Additionally, a substantial portion of each officer’s total compensation is tied to the performance of Dominion’s stock through their restricted stock grants, ranging from 18% of targeted total compensation for a typical vice president up to 37% for Mr. Farrell. For Mr. Farrell, this results in almost 90% of his total direct compensation having a performance component.
Dominion’s Board may seek to recover performance-based compensation paid to officers who are found to be personally responsible for fraud, negligence or intentional misconduct that causes a restatement of financial results filed with the SEC.
Annual Incentive Plan. The Annual Incentive Plan focuses on short-term goals, and for the CEO, comprised more than half of his annual cash compensation for 2006. With the introduction of cash-based performance grants in 2006 as outlined below, the CEO and
each eligible officer may receive a higher percentage of their total 2007 compensation (annual and long-term) earned in cash, based on goal accomplishment.
Under the Annual Incentive Plan, the CGN Committee establishes “target awards” for each executive. These target awards are expressed as a percentage of the individual executive’s base salary (for example, 50% x base salary). The target award is the amount of cash that will be paid, at year-end, if the plan is fully funded and the executive achieves 100% of the goals established at the beginning of the year. Under the Annual Incentive Plan, if goals are achieved or exceeded, the executive’s total cash compensation for the year is targeted to be at or slightly above market median. If the goals are not achieved, the executive’s total cash compensation may be significantly lower than market median, depending on the extent to which goals were not achieved. For 2006, Mr. Farrell’s annual incentive target was 110% of his base salary, consistent with our intent of having a substantial portion of his compensation at risk. For 2006, Mr. Chewning’s target was 90%, Messrs. McGettrick and Johnson’s target was 80%, and Mr. Christian’s target was 70%.
The 2006 Annual Incentive Plan was funded based on goals established and approved by the CGN Committee at the beginning of 2006. For the 2006 Annual Incentive Plan, the threshold consolidated earnings goal for any payout under the plan was reported operating earnings for Dominion of $5.05 per share, with full funding at reported operating earnings of $5.15 per share. Additionally, if Dominion’s reported operating earnings exceeded $5.15 per share, then for every one cent reported over $5.15 per share, 3% in additional funding would be applied to the 2006 Annual Incentive Plan, up to a maximum of 200% funding. This results in the Company and employees sharing equally in earnings above the $5.15 per share goal until the 200% maximum funding level is achieved.
To access the funded bonus pool, each executive must meet certain goals, including consolidated and business unit financial goals as well as operating, stewardship and Six Sigma targets. The consolidated earnings goal is designed to drive employee behavior and performance to ensure that shareholders receive an appropriate return on their investment in Dominion.
The business unit financial goals are set based on the levels necessary to achieve the consolidated earnings goal for Dominion. Also, individual business unit goals provide line-of-sight targets for officers and employees, and facilitate financial and business planning at the business unit level.
The operating and stewardship goals may not be financial, and can be customized for a business unit or individual. The accomplishment of these goals often supports the business unit financial goals. The most common operating and stewardship goals have objectives in the following areas: safety; reliability; expenditures and production; forced outages; and service level requirements.
Finally, Six Sigma goals support Dominion’s mission to continue to use Six Sigma to increase productivity, improve service reliability, reduce costs and enhance customer service while bringing the benefits of these improvements to the bottom line.
Each executive’s goals are weighted according to his or her responsibilities. Payout under the plan is determined by multiplying the employee’s target bonus by the percentage the plan is funded (e.g., 100%) by the percentage that the employee’s own personal goal package is achieved (e.g., 90%).
The goal weightings for bonuses under the 2006 Annual Incentive Plan for Dominion’s named executive officers (which includes Messrs. Farrell, Chewning, McGettrick and Johnson) and all other officers (which includes Mr. Christian) were as follows:
For Messrs. Farrell, Chewning, McGettrick and Johnson, bonuses were based solely on the consolidated earnings goal, with the CGN Committee having discretion to reduce final payouts to the extent appropriate, based on any goal accomplishment that was less than 100% for the corporate-wide Six Sigma goal, and for Messrs. McGettrick, Johnson and Christian, any goal accomplishment that was less than 100% for their business unit financial goals or their own personal operating/stewardship goals. The reductions could be as much as the percentages set forth in the table above for each category for other officers. Due to the broad scope of their duties, Messrs. Farrell and Chewning did not have operating and stewardship goals, as these goals tend to be business-unit specific.
Dominion compared actual financial performance for 2006 with the consolidated and business unit earnings goals. Dominion achieved operating earnings of $5.17 per share in 2006 before any additional funding under our plan. Taking into account the funding formula described above, the 2006 Annual Incentive Plan was funded at the 103% level, with additional 3% funding available to cover any upside from the Six Sigma stretch goals described above. Dominion reported $5.16 per share in operating earnings as a result of funding these additions, with shareholders and employees each receiving one cent each of the operating earnings over $5.15 per share.
The Six Sigma goal for 2006 was a corporate-wide positive financial impact of $100 million, with a stretch goal of $150 million, which would result in an increase of 4% in each employee’s payout score if the stretch goal were achieved. Dominion as a whole and each business unit exceeded their Six Sigma stretch goal, with corporate-wide savings of $224 million achieved in 2006. This resulted in all employees, except for Dominion’s named executive officers (which includes Messrs. Farrell, Chewning, McGettrick and Johnson), receiving an additional 4% to their pay-out score for determining 2006 payouts, with a total possible payout of 107% of their target bonus. Dominion’s named executive officers received 106% plan funding because their bonuses were based on consolidated earnings goals only, including the earnings kicker; however, their goal score was capped at 100%. Actual amounts earned under the 2006 Annual Incentive Plan by each of the Company’s named executive officers are set forth in the Summary Compensation Table under the heading “Non-Equity Incentive Plan Compensation”.
The Long-Term Incentive Program. For 2006, Dominion transitioned its long-term program from retention-based restricted stock, with alignment to its shareholders, to a long-term program that is both (i) aligned with the long-term interests of its shareholders through restricted stock grants and (ii) designed to put a substantial portion of the long-term compensation at risk based
on the achievement of performance measures with the introduction of cash performance grants. Grants are typically made on or before April 1 of each year, and Dominion does not time the grant dates based on the release of material information or expectations of stock price changes. Newly promoted officers receive pro-rated grants for the current year’s program based on the fair market value of the stock as of their date of employment or election to office.
Dominion has not issued stock options since 2002, although options remain outstanding from prior programs and are reported in the Outstanding Equity Awards at Fiscal Year End table on page 58, with options exercised in 2006 disclosed in the Option Exercises and Stock Vested table on page 59.
While the CGN Committee reviews prior grants to the CEO before approving new long-term grants, the determination of the appropriate grant for the CEO and other senior executives in any given year is based on the results of the process described above for the executive compensation program. Dominion does not “deduct” prior compensation paid to executives from the compensation being considered for the current year. Similarly, if a newer executive does not have prior grants outstanding due to his or her short tenure, Dominion does not increase the compensation paid to the executive due to a lack of outstanding grants from prior years.
Performance Grants. For 2006, Dominion transitioned to a long-term incentive program that is 50% performance-contingent, payable in cash rather than stock. These grants were made on April 1, 2006 and are “at-risk” based on the achievement of the two goals discussed below. The reasons for shifting a portion of the program to cash were (i) the significant ownership of Dominion stock by executives and the high rate of compliance with our share ownership requirements; (ii) to provide a more immediate award following achievement of goals and (iii) improve the tax efficiency of awards as no shares need to be sold to pay taxes, and any net cash award could be used to pay taxes on vesting restricted stock awards. Officers who have not achieved their ownership targets are expected to hold vested restricted stock, net of shares used to cover taxes.
The 2006 cash-based performance grants have a two-year term, with two equally weighted goals: i) Dominion’s total shareholder return (TSR) for the 21 month period ended December 31, 2007 relative to the TSR of a group of industry peers selected by the CGN Committee; and ii) return on invested capital (ROIC) for the two-year period ended December 31, 2007. For the performance grants which were awarded in April 2006, the 2006 peer group was adjusted and NiSource, Inc. and PPL Corporation added to the peer group, and Constellation Energy Group was excluded for this grant as it was a merger candidate at that time. The grants are 100% performance-based with payouts ranging from 0-200% of target. The goals for the 2006 grant, scoring for such goals and possible payouts for the named executive officers are set forth in the Grants of Plan-Based Awards table on page 57.
Restricted Stock Grants. Officers also received restricted stock grants on April 1, 2006. The grants have cliff vesting at the end of the three-year restricted period. Restricted stock grants serve as a retention tool as they are forfeited upon voluntary termination and align the interests of officers with the interests of our shareholders.
The CGN Committee approved the 2006 long-term grants based on a stated dollar value for the award based on its earlier compensation review. Restricted stock was issued for 50% of the total long-term grant value, with the number of shares issued
determined by using the fair value of Dominion’s common stock the day before the date of grant (average of high and low stock price). Officers receive dividends on the restricted shares. The full grant date fair value of each named executive officer’s 2006 restricted stock grant is disclosed in the Grants of Plan-Based Awards table on page 57.
Vesting Terms for the 2006 Restricted Stock Grants and Performance Grants. Both grants are forfeited in their entirety if the officer voluntarily terminates his or her employment or is terminated with cause before the vesting date. The grants have pro-rated vesting for termination without cause, retirement, death or disability, rewarding the officers or their estate only for the period of time they provided services to the company. For the performance grants, the pro-rated payout is based on actual goal performance at the end of the performance cycle.
In the event of a Change in Control* at Dominion, the restricted shares have pro-rated vesting up to the change in control date, rewarding officers only for prior service. If the officers subsequently are terminated, or constructively terminate their employment, under the terms of the grant, any remaining unvested shares will vest at that point. For the cash performance grants, as any goals would likely be materially changed as a result of any Change in Control at Dominion, payout of these grants will accelerate and will be equal to the greater of the target grant amount or the payout that would be made based on the assumptions used for goal performance in Dominion’s latest financial statements as of the day before the Change in Control occurred.
EMPLOYEE AND EXECUTIVE BENEFITS
Officers participate in many of the same employee benefit programs as other employees. The core benefit programs include two tax-qualified retirement plans, vacation program, medical coverage, dental coverage, vision coverage, life insurance, disability coverage, travel accident coverage, company-paid short-term disability and long-term disability coverage. There are other miscellaneous employee benefit programs, such as flexible spending accounts, health savings accounts, employee assistance programs, employee leave policies and other incidental programs available to employees generally. Tax-qualified retirement plans are a 401(k) plan and a defined benefit pension plan (Pension Plan). A matching contribution to each employee’s 401(k) plan account of 50 cents for each dollar is made on the first 6% of compensation (up to IRS limits) if less than 20 years of service, and 67 cents for each dollar contributed on the first 6% of compensation (up to IRS limits) if the employee has at least 20 years of service. The amount of the company matching contributions under the 401(k) for the named executive officers ranged from $1,980 to $4,400. Amounts forgone due to IRS limits were paid to executives in cash and ranged from $3,312 to $8,192. All of these matching contribution amounts are shown in the All Other Compensation footnote to the Summary Compensation Table following this section. The defined benefit pension plan pays benefits under a formula that is explained in Pension Benefits and the change in pension value for 2006 is included in the Summary Compensation table on page 56.
* A Change in Control occurs if (i) any person or group becomes a beneficial owner of 20% or more of the combined voting power of Dominion voting stock or (ii) as a direct or indirect result of, or in connection with, a cash tender or exchange offer, merger or other business combination, sale of assets, or contested election, the Directors constituting the Dominion Board before any such transactions cease to represent a majority of Dominion or its successor’s Board within two years after the last of such transactions.
Dominion also has two supplemental retirement plans for executives. The Benefit Restoration Plan makes up for certain limits related to Pension Plan benefits imposed by the Internal Revenue Code as more fully explained in Pension Benefits beginning on page 59. The Pension Plan and Benefit Restoration Plan pay benefits calculated on base salary. To accommodate changes in tax law, the Dominion Benefit Restoration Plan was frozen as of December 31, 2004 (Frozen BRP) and a New Benefit Restoration Plan was implemented effective January 1, 2005 (New BRP). There is no change in the total benefit provided as a result of this new plan.
The Executive Supplemental Retirement Plan provides an annual retirement benefit equal to 25% of a participant’s final cash compensation (base salary plus target annual bonus) for a period of ten years or life as more fully explained in Pension Benefits. To accommodate changes in the tax law, the Executive Supplemental Retirement Plan was frozen as of December 31, 2004 (Frozen ESRP) and a New Executive Supplemental Retirement Plan was implemented effective January 1, 2005 (New ESRP). There is no change in the benefit provided as a result of this new plan.
Dominion maintains the Benefit Restoration Plan and the Supplemental Retirement Plan to provide a competitive level of retirement benefits to our executives. The Pension Plan and its related Benefit Restoration Plan provide a benefit that is calculated on base salary, credited age, credited service and a social security off-set. Because a more substantial portion of our executives’ total compensation is paid as incentive compensation than for rank and file employees, the Pension Plan and Benefit Restoration Plan alone would not produce the same percentage of replacement income in retirement for executives as for rank and file employees. The Supplemental Retirement Plan is intended to partially make up for the limitation of these two plans due to their use of base salary only. The Supplemental Retirement Plan includes bonuses in its calculations, but does not include long- term incentive compensation. As a result, a significant portion of the potential compensation for our executives are excluded from calculation in any retirement plan benefit. The present value of accumulated benefits under these plans are disclosed in the Pension Benefits table on page 59.
Dominion also maintains a voluntary Executive Life Insurance Program for our executives. The plan provides for whole-life insurance policies to executives with a death benefit that is a multiple (one to three times) of each executive’s base salary. This insurance is in addition to the term insurance that is provided as an employee benefit. The executive is the owner of the policy and the company will make premium payments to the later of 10 years or age 64. Executives are taxed on the value of the insurance provided by the company. The premiums for these policies are included in the All Other Compensation footnote to the Summary Compensation Table.
Perquisites. Dominion provides perquisites for executives that are considered reasonable by the CGN Committee and in line with market practice. In addition to incidental perquisites associated with maintaining an office, the following limited number of perquisites are offered to executives:
(1) An allowance of up to $9,500 a year for financial, estate and tax planning as well as for health and physical well being
services. Dominion wants executives to be proactive with preventative healthcare and financial and estate planning and to ensure proper tax reporting of company-provided compensation.
(2) A company-leased vehicle, including the cost of insurance, gas and maintenance, up to an established lease-payment allowance (if the lease payment exceeds the allowance, the officer pays for excess amounts on the vehicle personally). Dominion offers this perquisite to be competitive with other comparable employers.
(3) Luncheon or other club memberships to provide a venue for business entertainment purposes. In 2007, Dominion is eliminating this perquisite.
(4) In limited circumstances, use of company aircraft for personal travel. Dominion’s Board has required Mr. Farrell to use the aircraft for personal travel for reasons of security. Other executives’ use of the aircraft is very limited, and usually related to (i) travel with the CEO or (ii) personal travel to accommodate business demands on the executives’ schedule. Executives are taxed on all personal use of aircraft under IRS guidelines. Other than Mr. Farrell, the personal use of aircraft is not allowed when there is a company need for the aircraft. Use of the corporate aircraft saves our executives substantial time and allows better access to the executives for company purposes. Over 96% of the use of Dominion’s company planes is for business purposes.
Tax Gross-Up. While these perquisites are generally taxable, the company provides a tax gross-up for the limited personal use of the company plane that does occur, spousal travel or expenses for business entertainment purposes and in a limited number of cases, clubs. As mentioned above, we will no longer pay for any clubs and therefore there will no longer be associated taxes or gross-ups on those clubs.
Other Agreements. In order to secure and retain the services and focus of key executives, Dominion has entered into agreements with each of our named executive officers to provide certain retirement benefits or other protections in certain circumstances, including Employment Continuity Agreements with each executive. The specific terms of these agreements are discussed in Pension Benefits and the tables under Potential Payments upon Termination or Change in Control.
Deductibility of Compensation
Under Section 162(m) of the Internal Revenue Code, Dominion may not deduct certain forms of compensation in excess of $1 million paid to its CEO or any of the four other most highly compensated executive officers. However, certain performance-based compensation is specifically exempt from the deduction limit.
It is Dominion’s intent to provide competitive executive compensation while maximizing its tax deduction to the extent reasonable. The CGN Committee considers the Section 162(m) implications when approving certain plans and payouts. However, the CGN Committee reserves the right to approve, and in some cases has approved, non-deductible compensation if they believe it is in Dominion’s best interest.
SUMMARY COMPENSATION TABLE(1)
(1) The executives included in this table may perform services for more than one subsidiary of Dominion. Compensation for the individuals listed in the table and related footnotes reflects only that portion which is allocated to the Company for the year presented.
(2) The amounts in this column reflect the compensation expense recognized in 2006 on all outstanding stock awards in accordance with SFAS 123R. The grant date fair value of restricted stock awards is equal to the market price of our stock on the date of grant. The grant date fair value of each named executive officer’s 2006 restricted stock grant is disclosed in the Grants of Plan-Based Awards table on page 57. See also the Outstanding Equity Awards at Fiscal Year-End table on page 58 for a listing of all outstanding equity awards as of December 31, 2006.
(3) The amounts in this column reflect the payout under Dominion’s 2006 Annual Incentive Plan. All of the named executive officers except for Messrs. McGettrick and Christian received the full potential payout of their target awards, reflecting 106% funding of the 2006 Annual Incentive Plan and 100% payout for accomplishment of their goals. Messrs. McGettrick and Christian’s payouts were reduced to an overall payout of 102% and 104%, respectively, of target due to less than 100% performance on safety and production cost goals. See Compensation Discussion and Analysis (CD&A) for additional information on the 2006 Annual Incentive Plan and the Grants of Plan Based Awards table for the range of each named executive officer’s potential award under the 2006 Annual Incentive Plan (with this column reflecting the actual payout for each named executive officer).
(4) All amounts in this column are for the aggregate change in the actuarial present value of the named executive officer’s accumulated benefit under our qualified pension plan and nonqualified executive retirement plans. There are no above-market earnings on non-qualified deferred compensation plans. These amounts are not directly in relation to final payout potential, and can vary significantly year over year based on (i) promotions and corresponding changes in salary, such as Mr. Farrell’s promotion to Dominion’s Chief Executive Officer as of January 1, 2006; (ii) other one-time adjustments to salary or incentive target for market or other reasons; (iii) actual age versus predicted age at retirement; and (iv) other market factors.
(5) All Other Compensation amounts for 2006 are as follows
(a) Unless noted, the amounts in this column for all officers are comprised of the following: personal use of a company vehicle; personal use (except for Messrs. McGettrick and Christian) of corporate aircraft; financial planning; health and wellness allowance; club fees (except for Mr. Christian); and home security system (Mr. Christian only). For Messrs. Farrell and Chewning, personal use of the corporate aircraft was $12,923 and $8,191 respectively. For personal flights, all direct operating costs are included in calculating aggregate incremental cost. Direct operating costs include the following: fuel, airport fees, catering, ground transportation and crew expenses (any food, lodging and other costs). The fixed costs of owning the aircraft and employing the crew are not taken into consideration, as more than 96% of the use of the corporate aircraft is for business purposes. For Mr. Farrell, club fees were $9,294 which includes a one-time transfer fee for a corporate membership for his use while serving as CEO.
While some of the club fees are for personal memberships which may be used for business purposes, a majority of the fees reflected are for corporate memberships. Although we consider corporate club fees as a perquisite, a majority of the use of corporate club memberships is for business purposes. The aggregate incremental cost for club fees is based on actual costs incurred. As of January 1, 2007, the Company is eliminating the club perquisite program for executives, and they will be personally responsible for all dues.
In addition to these formal perquisite programs, executives may also receive some perquisites from time to time that have no incremental cost to the company. These would include (i) use of the company’s travel department for making travel arrangements that may have a personal component to them; (ii) flights on the company plane when a seat is available for the spouse or other guest of an executive; (iii) an assigned parking spot; and (iv) occasional use of their administrative assistant or other company employees for assistance with charitable, community or personal matters.
(b) Paid under the terms of the Company’s 401(k) plan.
(c) Represents payment of “lost” savings plan match due to IRS limits. This lost match was paid in cash to the named executive officers outside of the 401(k) plan.
GRANTS OF PLAN-BASED AWARDS(1)
(1)
The executive officers included in this table may perform services for more than one subsidiary of Dominion. The amounts listed in the table reflect only that portion allocated to the Company.
(2)
On March 31, 2006, the CGN Committee approved the 2006 long-term compensation awards for our officers which consisted of a restricted stock grant and a performance grant. The 2006 restricted stock award was granted on April 1, 2006. Under Dominion’s 2005 Incentive Compensation Plan, fair market value is defined as the average of the high and low prices of Dominion stock as of the last day on which the stock is traded preceding the date of grant. The fair market value for the April 1, 2006 restricted stock grant was $69.53 per share and was determined by taking the average of the high and low prices of Dominion stock on March 31, 2006 (grant approval date).
(3)
These amounts represent potential payouts under the 2006 Annual Incentive Plan. Actual payouts earned are reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table on page 56. Under the annual incentive program, officers are eligible for an annual performance-based award. The CGN Committee establishes target awards for each executive based on his or her salary level and expressed as a percentage of the individual executive’s base salary. The target award is the amount of cash that will be paid if the plan is fully funded. For the 2006 Annual Incentive Plan, funding is based on the achievement of consolidated operating earnings goals with the maximum funding capped at 200%.
For officers that are among Dominion’s top most highly compensated group for 2006, which includes all of our named executive officers except for Mr. Christian, pay-out under the 2006 Annual Incentive Plan is based solely on the achievement of the corporate funding goal, with the CGN Committee having the discretion to lower actual pay-outs to ensure that such awards are consistent with those granted to other plan participants. The 2006 target percentages of base salary for our named executive officers are as follows: Thomas F. Farrell, II - 110%; Thomas N. Chewning - 90%; Mark F. McGettrick and Jay L. Johnson - 80%; and David A. Christian - 70%.
(4)
On March 31, 2006, the CGN Committee approved a long-term compensation award for our officers, which consists of two components of equal value: a restricted stock grant and a performance grant. The restricted stock fully vests at the end of three years with dividends paid during the restricted period at the same rate declared by Dominion for all shareholders. The restricted stock award also provides for pro-rata vesting if an officer dies, become disabled, retires, is terminated without cause or if there is a Change in Control.
The performance grant will be paid in cash in 2008 and can range from 0% to 200% of the target award. The amount earned by our officers will depend on the level of achievement of two equally weighted metrics: 1) Dominion’s total shareholder return (TSR) for the twenty-one month period ended December 31, 2007 relative to the TSR of a group of industry peers selected by the CGN Committee; and 2) Dominion’s return on invested capital (ROIC) for the two-year period ended December 31, 2007. The payout for TSR performance can range from 0% to 200% of the target award and will be interpolated between the following levels:
Payout for ROIC performance will range from 0% to 200% of the target award and will be interpolated between the ranges established by the CGN Committee. The performance grant also provides for some form of pro-rata payout in the event an officer retires, dies, becomes disabled, or is terminated without cause. In the event of a Change in Control, payout will accelerate and be equal to the greater of the target amount or the payout amount that would be made for Dominion’s goal performance based on Dominion’s financial statements as of the day before the Change in Control. See CD&A on page 54 for the definition of a Change in Control.
(5)
On December 19, 2006, the CGN Committee approved a restricted stock grant to Mr. Christian in order to secure and retain his services. The restricted stock fully vests at the end of three years with dividends paid during the restricted period at the same rate declared by Dominion for all shareholders. The restricted stock award also provides for pro-rata vesting if an officer dies, becomes disabled, or if there is a Change in Control. The fair market value for the December 20, 2006 restricted stock grant was $82.65 per share and was determined by taking the average of the high and low prices of Dominion stock on December 19, 2006 (grant approval date).
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END(1)
(1)
The executive officers included in this table may perform services for more than one subsidiary of Dominion. The amounts listed in the table reflect only that portion allocated to the Company.
(2)
All options presented in this table are fully vested and exercisable. There are no unexercisable options outstanding.
(3)
Based on closing stock price of $83.84 on December 29, 2006 which was the last day of the fiscal year on which Dominion stock was traded.
(4)
Shares vest on February 24, 2008.
(5)
50% of shares vest on May 11, 2007 based on achievement of certain performance criteria; the remaining shares vest on May 11, 2009.
(6)
Shares vest on April 1, 2009.
(7)
50% of shares vested on February 18, 2007 based on achievement of certain performance criteria; the remaining shares vest on February 18, 2009.
(8)
Shares vest on December 20, 2009.
OPTION EXERCISES AND STOCK VESTED
(1)
Mr. Chewning’s options were exercised pursuant to a Rule 10b5-1 trading plan. Mr. Chewning performs services for more than one subsidiary of Dominion and the amounts listed in the table reflect only that portion allocated to the Company.
PENSION BENEFITS(1,2)
No payments were made to any of the Named Executive Officers during Fiscal Year 2006 under any of the plans listed in this table.
(1)
The executive officers included in this table may perform services for more than one subsidiary of Dominion. The amounts listed in the table reflect only that portion allocated to the Company.
(2)
The years of credited service and the present value of accumulated benefits were determined by our plan actuaries, using the appropriate accrued service and pay and other assumptions similar to those used for accounting and disclosure purposes.
(3)
Years of service for the qualified plan is actual years accrued from date of participation. Pre-2005 service is accrued service up to December 31, 2004. Service for the New Benefit Restoration Plan and New Supplemental Retirement Plan is the pro-rata portion of the contractual service from date of participation.
Dominion Pension Plan
The Dominion Pension Plan (Pension Plan) is a tax-qualified defined benefit pension plan. All executives are participants in the Pension Plan.
The Pension Plan provides unreduced retirement benefits at termination of employment at or after age 65 or, with three years of service, at age 60. Reduced retirement is available after age 55 with three years of service. For retirement between ages 55 and 60, the benefit is reduced 0.25% per month for each month after age 58 and before age 60 and 0.50% per month for each month between ages 55 and 58. All named executive officers have more than three years of service.
The Pension Plan basic benefit is calculated using a formula based on (1) age at retirement; (2) final average earnings; (3) estimated Social Security benefits and (4) credited service. Final average earnings are the average of the participant’s 60 highest consecutive months of base pay during the last 120 months worked. Earnings are limited to the IRS maximum which was $220,000 for 2006. Bonuses are not included in base pay. Credited service is measured in months, up to a maximum of 30 years of credited service. The estimated Social Security benefit taken into account is the assumed Social Security benefit payable starting at age 65 or actual retirement date, if later, assuming that the participant has no further employment after leaving Dominion.
These factors are then applied in a formula. The formula has different percentages for credited service before 2001 and after 2000. The benefit is the sum of the amounts from these two formulas.
For Credited Service before 2001:
For Credited Service after 2000:
Credited Service is limited to a total of 30 years for all parts of the formula and Credited Service after 2000 is limited to 30 years minus Credited Service before 2001.
If a vested participant does not start receiving benefit payments at termination, the participant can start receiving benefit payments at any time after age 55. For terminated vested participants (terminate employment before age 55) the early retirement reduction factors for the portion of the benefits earned after 2000 are as follows: Age 64 - 9%; Age 63 - 16%; Age 62 - 23%; Age 61 - 30%; Age 60 - 35%; Age 59 - 40%; Age 58 - 44%; Age 57 - 48%; Age 56 - 52%; Age 55 - 55%.
Benefit payment options are a (1) single life annuity, (2) 50% joint and survivor annuity, (3) 100% joint and survivor annuity, and (4) Social Security leveling option with any of the other three benefit forms. The normal form of benefit is the single life annuity. All of the options are actuarial equivalent to the single life annuity. The Social Security leveling option pays a larger benefit equal to the estimated Social Security benefits until the participant is age 62 and then reduced payments after age 62.
The Pension Plan also includes a Special Retirement Account (SRA), which is in addition to the pension benefit. The SRA is credited with 2% of base pay each month as well as interest based on the 30-year Treasury bond rate. The SRA can be paid in a lump sum or paid as part of an annuity with the other benefits under the Pension Plan.
Dominion Benefit Restoration Plans
Dominion sponsors the New BRP and the Frozen BRP which are also discussed under Employee and Executive Benefits in CD & A. Neither plan is tax qualified.
The Frozen BRP provides benefits accrued before 2005 that are intended to be exempt from Section 409A of the Internal Revenue Code. The New BRP was adopted to accommodate the enactment of and is intended to comply with Section 409A of the Internal Revenue Code for benefits accrued after 2004. The overall restoration benefit was not changed by adoption of the New BRP.
The restoration benefit offers an additional incentive to attract and retain talented executives for Dominion by compensating them for the reduction in their benefits under Dominion’s Pension Plan resulting from the application of limitations on compensation and benefits imposed on tax-qualified pension plans by the Internal Revenue Code.
A Dominion employee is eligible to participate in the New BRP if he or she is a member of management or a highly compensated employee and has had his or her benefit under the Dominion Pension Plan reduced or limited by the Internal Revenue Code. Dominion designates an employee to participate in the New BRP. The Frozen BRP has been closed to new participants since December 31, 2004. A participant remains a participant in either plan until he or she ceases to be eligible for any reason other than retirement or until his or her status as a participant is revoked by Dominion.
Upon retirement, the New BRP provides a monthly restoration benefit equal to the monthly benefit the participant would have received under Dominion’s Pension Plan but for the limitations imposed by the Internal Revenue Code, reduced by the monthly benefit the participant actually receives under Dominion’s Pension Plan, reduced further by the monthly benefit the participant receives under the Frozen BRP. Upon retirement, the Frozen BRP provides a monthly restoration benefit equal to the monthly benefit the participant would have received under Dominion’s Pension Plan but for the limitations imposed by the Internal Revenue Code, reduced by the monthly benefit the participant actually receives under Dominion’s Pension Plan, in each case determined as though the participant had separated from service with Dominion no later than December 31, 2004.
As discussed above, the Internal Revenue Code limits the amount of compensation that may be taken into account under a qualified retirement plan to no more than a certain amount each year. For 2006, the limit was $220,000. The Internal Revenue Code also limits the total annual benefit that may be provided to a participant under a qualified defined benefit plan. For 2006, this limitation was the lesser of (i) $175,000 or (ii) the average of the participant’s compensation during the three consecutive years in which the participant had the highest aggregate compensation.
In each plan, retirement means the participant’s termination of employment with Dominion at a time when the participant is entitled to receive benefits under Dominion’s Pension Plan. A participant who terminates employment prior to retirement is generally not entitled to a restoration benefit. However, a participant who becomes totally and permanently disabled prior to retirement or who dies prior to reaching retirement eligibility is entitled to the restoration benefit.
Dominion may grant additional months of service and years of age to participants for purposes of these plans and the supplemental retirement plans described below. Extra age and service credit is granted for mid-career recruiting and retention purposes. Mr. Farrell will be credited with 25 years of service at age 55, and will be credited with 30 years of service at age 60. Mr. Chewning has been credited with 30 years of service. Mr. McGettrick will receive 5 years of additional credited age and service at age 50. Also, if Mr. McGettrick is terminated other than for cause, prior to age 50, he will be credited with the number of years credit needed to give him 55 years of credited age and the number of additional years of service credit needed to give him the same number of years of service that would have been earned had he remained employed by the company until age 55. Mr. Johnson will be credited with 20 years of service once he completes 10 years of actual service. Additional age and years of service may be credited in certain situations pursuant to the terms of individual retirement agreements and arrangements for the named executive officers and is described in Potential Payments Upon Termination or Change in Control.
A participant’s accrued restoration benefit is calculated based on the default annuity form under Dominion’s Pension Plan.
Under the New BRP, the restoration benefit is generally paid in the form of a single cash lump sum, unless the participant elects to receive a single life or 50% or 100% joint and survivor annuity. Under the Frozen BRP, the restoration benefit is usually paid in the form of a single cash lump sum, unless the participant elects to receive a single life or 50% or 100% joint and survivor annuity.
For purposes of these plans and the supplemental retirement plans described below, the present value of the accumulated benefit is calculated using actuarial and other factors as determined by the plan actuaries and approved by Dominion’s Administrative Benefit Committee. Actuarial assumptions used for December 31, 2006 calculations include: discount rate of 6.20%; Frozen BRP and Frozen ESRP lump sum rate of 4.85%; New BRP and New ESRP lump sum rate of 5.45%; Frozen BRP cost-of-living adjustment of 1.625% and the 1994 Group Annuity Mortality table for post retirement only.
Dominion Executive Supplemental Retirement Plans
Dominion sponsors the New ESRP and the Frozen ESRP which are also discussed under Employee and Executive Benefits in CD&A. Neither plan is tax qualified.
The Frozen ESRP provides benefits accrued before 2005 that are intended to be exempt from Section 409A of the Internal Revenue Code. The New ESRP was adopted specifically to accommodate the enactment of and is intended to comply with Section 409A of the Internal Revenue Code for benefits accrued after 2004. The overall supplemental retirement benefit was not changed by adoption of the New ESRP.
The supplemental retirement benefit offers an additional incentive to attract and retain talented executives for Dominion. In light of the competitive industry in which it does business, Dominion feels that the normal pension plan benefit (even as increased by the restoration benefit) is insufficient to fulfill this purpose on its own.
Any elected officer of the company is eligible to participate in the New ESRP. Dominion designates an officer to participate. The Frozen ESRP has been closed to new participants since December 31, 2004. A participant remains a participant in either plan until he or she ceases to be an elected officer or until participation is revoked by Dominion.
The New ESRP provides for an annual retirement benefit equal to 25% of a participant’s final cash compensation, based on his or her compensation and subject to age and years of service as of retirement, reduced by the annual retirement benefit provided under the Frozen ESRP. The Frozen ESRP provides for an annual retirement benefit equal to 25% of a participant’s final cash compensation, based on his or her compensation and subject to age and years of service as of December 31, 2004. The retirement benefit is only payable for ten years unless Dominion designates the participant to receive lifetime benefits as described below.
A participant’s final cash compensation includes, as of the relevant determination date, the participant’s annual rate of base salary then in effect plus the target amount payable under the company’s annual incentive plan for the year in which the determination is made. Final cash compensation does not include the value of equity awards, gains from the exercise of stock options, long-term cash incentive awards, perquisites or any other form of compensation.
A participant in either plan is entitled to the full retirement benefit if he or she separates from service with Dominion after
reaching age 55 and achieving 60 months of service. Months of service generally include any months of service with Dominion, except that, for new participants who join the New ESRP on or after December 1, 2006, months of service only include months of service with Dominion while a participant in the New ESRP. Current named executive officers who are entitled to a full ESRP retirement benefit are: Messrs. Chewning and Johnson.
A participant who separates from service with Dominion with at least 60 months of service but who has not yet reached age 55 is entitled to a reduced retirement benefit, calculated by multiplying the full retirement benefit described above by a fraction, the numerator of which equals the participant’s total number of months of service since becoming a participant, and the denominator of which equals the total number of months between the date the participant became a participant and age 55. Partial months are disregarded in this calculation. Messrs. Farrell, McGettrick and Christian are the only named executive officers who are not entitled to a full retirement benefit. See discussion above regarding additional months of service and years of age.
A participant who separates from service with Dominion with less than 60 months of service is generally not entitled to a retirement benefit. However, a participant who becomes totally and permanently disabled prior to separation from service is entitled to a full retirement benefit, regardless of age or months of service. In addition, the beneficiary of a participant who dies prior to reaching retirement eligibility is entitled to the participant’s full retirement benefit.
A participant’s accrued retirement benefit is initially calculated as an annual amount payable in monthly installments for a period of 120 months. However, the New ESRP allows Dominion to designate certain participants as eligible for a retirement benefit for their lifetimes. Messrs. Farrell and Chewning will receive this benefit for their lifetime. Messrs. McGettrick and Christian will receive this benefit for lifetime if employed with Dominion at age 60. Mr. Johnson will receive this benefit for his lifetime after he has completed 10 years of actual service with Dominion.
Under the New ESRP, the retirement benefit is generally paid in the form of a single cash lump sum unless a participant (other than a lifetime participant) elects monthly installment payments guaranteed for 120 months or a lifetime participant elects a single life annuity with 120 guaranteed monthly payments. Under the Frozen ESRP, the retirement benefit is usually paid in the form of a single cash lump sum unless the participant elects monthly installments guaranteed for 120 months, or unless a lifetime participant elects a single life annuity with 120 guaranteed monthly payments.
NONQUALIFIED DEFERRED COMPENSATION
Footnote:
(1)
The executive officers included in this table may perform services for more than one subsidiary of Dominion. The amounts listed in the table reflect only that portion allocated to the Company. Dominion does not currently offer any nonqualified deferred compensation plans to its officers or other employees. The Aggregate Balance at Last FYE column includes salary and bonus deferrals, lost company savings plan match and vested restricted stock which would have been reported in prior years’ Summary Compensation Tables.
The 2006 Nonqualified Deferred Compensation Table reflects, in aggregate, the plan balances for two former plans offered to Dominion officers and other highly compensated employees: The Dominion Resources, Inc. Executives’ Deferred Compensation Plan, which was amended and restated as of December 31, 2004 to “freeze” the plan as of that date (the Frozen Deferred Compensation Plan); and The Dominion Resources, Inc. Security Option Plan, which was amended and restated effective December 31, 2004 to “freeze” the plan as of that date (the Frozen DSOP). While the Frozen DSOP was not a deferred compensation plan, but an option plan, we are including information regarding the plan and any balances under the plan in this table to make full disclosure about possible future payments to officers under the employee benefit plans.
The Frozen Deferred Compensation Plan includes amounts previously deferred from one of the following categories of compensation: (i) salary; (ii) bonus; (iii) vesting restricted stock; and (iv) gains from stock option exercises. The plan also provided for lost company savings plan match contributions and transfers from several CNG deferred compensation plans. The Frozen Deferred Compensation Plan provides for 28 investment funds for the plan balances, including a Dominion Stock Fund. Participants may change investment elections on any business day. Any vesting restricted stock and gain from stock option exercises that were deferred are kept in the Dominion Stock Fund. Earnings are calculated based on the performance of the underlying investment fund. No preferential earnings are paid, and therefore no earnings from these plans are included in the Summary Compensation Table on page 56.
The named executive officers invested in the following funds which had rates of returns for 2006 as noted below. Except for the Fixed Income Fund, all of the funds have the same rate of returns as corresponding publicly available mutual funds.
The Fixed Income Fund is an option that provides a fixed return rate set prior to the beginning of the year. The investment management department of Dominion determines the rate based on its estimate of the rate of return on Dominion assets in the trust for the Frozen Deferred Compensation Plan.
Under the terms of the Frozen Deferred Compensation Plan, participants have the ability to change their distribution schedule for benefits under the plan with six months notice to the plan administrator. Participants may elect the following Benefit Commencement Dates:
n
In February after the calendar year in which they terminate employment due to retirement.
n
In February after the calendar year in which they terminate employment due to retirement, but not before February of a specific calendar year.
n
In February of a specific calendar year.
The default Benefit Commencement Date is February after the year in which the participant retires. Participants may elect multiple Benefit Commencement Dates; however, all new elections must be made at least six months before an existing Benefit Commencement Date. Withdrawals less than six months prior to an existing Benefit Commencement Date are subject to a 10% early withdrawal penalty. Account balances must be fully paid out no later than February 28, ten calendar years after a participant retires or becomes disabled. If a participant retires, he or she may continue to defer an account balance provided that the total balance is distributed by this deadline. In the event of termination of employment, for reasons other than death, disability or retirement, before an elected Benefit Commencement Date, benefit payments will be distributed in a lump sum as soon as administratively practicable. Hardship distributions, prior to an elected Benefit Commencement Date, are available under certain limited circumstances.
Participants may elect to have their benefit paid in a lump sum payment or equal annual installments over a period of whole years from 1 to 10 years. Once they begin receiving annual installment payments, they can make a one-time election to either 1) receive their remaining account balance in the form of a lump sum distribution or 2) change their remaining installment payment period. Any election must be approved by the company before it is effective. All distributions are made in cash with the exception of the Deferred Restricted Stock Account and the Deferred Stock Option Account which are distributed in the form of Dominion common stock.
The Frozen DSOP enabled employees to defer all or a portion of their salary and bonus and receive options on various mutual funds. Participants also received lost company matching contributions to the savings plan in the form of options under this plan. DSOP Options can be exercised at any time before their expiration date. On exercise, the participant receives the excess of the value, if any, of the underlying mutual funds over the strike price. The participant can currently choose among options on 26 mutual funds, and there is not a Dominion stock alternative nor a fixed income fund. Participants may change options among the mutual funds on any business day. Benefits grow/decline based on the total return of the mutual funds selected. Any options that expire do not have any value. Options expire under the following terms:
n
Options expire on the last day of the 120th month after retirement or disability.
n
Options expire on the last day of the 24th month after the participant’s death (while employed).
n
Options expire on the last day of the 12th month after the participant’s severance.
n
Options expire on the 90th day after termination with cause.
n
Options expire on the last day of the 120th month after severance following a Change in Control.
The executives in the Nonqualified Deferred Compensation Table held options on the following publicly available mutual funds which had the rates of returns for 2006 as noted below.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL
Termination Without Cause, Voluntary Termination, Retirement or Termination upon Death or Disability as of 12/31/2006 (Messrs. Chewning and Johnson)(1)
Under terms of Dominion’s qualified plan, Messrs. Chewning and Johnson are eligible for retirement as of December 31, 2006. In addition to the benefits outlined below, they would receive the benefits provided above in the Pension Benefits table, with the following reduction in benefit for early retirement versus the assumed retirement ages used in the Pension Benefit table for Mr. Johnson ($515,521). Also, Mr. Chewning would be eligible for retiree medical benefits under the company’s plan for all employees, whereas Mr. Johnson would not be eligible as he does not have ten years of service with the company. The following table assumes they retire in connection with any termination without cause, voluntary termination or termination upon death or disability.
Footnotes:
(1)
The executive officers included in this table may perform services for more than one subsidiary of Dominion. The amounts listed in the table reflect only that portion allocated to the Company.
(2)
Grants made prior to 2006 are fully vested upon retirement. Grants made in 2006 and after vest pro-rata upon retirement.
(3)
Pursuant to a letter agreement dated February 28, 2003, Mr. Chewning will be entitled to a special payment of one times salary in exchange for a two year non-compete requirement.
Termination Without Cause as of 12/31/2006 (Messrs. Farrell, McGettrick and Christian)(1)
Mr. McGettrick will be credited with the number of years needed to give him 55 years of credited age, and the number of additional years needed to give him the same number of years of service that he would have earned had he remained employed until age 55, if he is terminated other than for cause prior to age 50. At age 50 and above, if he is terminated without cause, he will receive 5 years of additional credited age and service. Mr. McGettrick is currently age 49. Therefore, the table below assumes Mr. McGettrick is credited with 55 years of age, and 28 years of service. This would entitle him to participate in retiree medical coverage and life insurance under the same terms and conditions as retired employees of Dominion, and will entitle him to be treated as a retired executive for purposes of Dominion’s Executive Life Insurance Program, stock and incentive grants. Mr. Farrell is not retirement eligible, but under the terms of his letter agreement with Dominion in connection with his election as CEO, his 2003 and 2004 restricted stock grants will vest in their entirety upon termination without cause, and he will be entitled to participate in retiree medical coverage without regard to his age or service to the same extent as retired employees of Dominion.
Footnotes:
(1)
The executive officers included in this table may perform services for more than one subsidiary of Dominion. The amounts listed in the table reflect on that portion allocated to the Company.
(2)
Messrs. Farrell, McGettrick and Christian are also entitled to a qualified pension plan benefit beginning at age 55. The estimated monthly life annuity benefit for Messrs. Farrell, McGettrick and Christian would be $571, $1,835 and $1,635, respectively.
(3)
Under Messrs. Farrell and McGettrick’s individual agreements, grants made prior to 2006 are fully vested upon termination without cause. Mr. Christian will forfeit any grants prior to 2006 upon termination without cause. Messrs. Farrell, McGettrick and Christian will receive pro-rata vesting on any grants awarded in 2006 and after upon termination without cause.
(4)
Amounts reflect annual premiums payable for the later of ten years or age 64.
(5)
This represents the present value of the retiree medical benefit that Messrs. Farrell and McGettrick would receive due to their letter agreements.
Voluntary Termination (Messrs. Farrell, McGettrick and Christian)
Mr. Farrell would receive a nonqualified retirement plan benefit of $3,111,462 with all restricted stock and performance grants forfeited. Messrs. McGettrick and Christian would receive a nonqualified retirement plan benefit of $678,922 and $619,806, respectively with all restricted stock and performance grants forfeited. Messrs. Farrell, McGettrick and Christian would be entitled to qualified pension plan benefits at age 55. The estimated monthly life annuity benefit for Messrs. Farrell, McGettrick and Christian would be $571, $1,835 and $1,635, respectively. Messrs. Farrell, McGetrrick and Christian would also be entitled to unused vacation benefits of $35,674, $32,435 and $25,312, respectively.
Termination Due to Death/Disability (Messrs. Farrell, McGettrick and Christian)
Messrs. Farrell, McGettrick and Christian would be treated as if they retired on date of death under the Benefit Restoration Plan. For the Executive Supplemental Retirement Plan, they would receive the benefit they would be entitled to as of the date of death or disability as though they were 55. They would be fully vested in restricted stock grants made prior to 2006 and would be pro-rata vested in grants made in 2006 and forward. Messrs. Farrell, McGettrick and Christian would receive benefits indicated in the Termination without Cause table shown above except that (i) Messrs. Farrell and Christian would receive $3,867,572 and $801,092, respectively under Nonqualified Retirement Plans. Instead of the amounts shown under Nonqualified Retirement Plan column in that table; and (ii) in the event of death, the Executive Life Insurance and Retiree Medical benefits would not be paid.
Termination with Cause
Messrs. Chewning and Johnson are eligible for retirement as of December 31, 2006; therefore, if allowed to retire under all of Dominion’s benefit plans in connection with a termination with cause, they would receive the benefits described above under Termination without Cause, Voluntary Termination, Retirement or Termination upon Death or Disability. However, the Board may lower this amount depending on the circumstances: (i) the claw-back policy allows for recovery of any performance-based compensation if it was based on financial results that were subject to any restatement due to the officer’s fraud or negligence; and (ii) the CGN Committee can remove the officer as a participant in the nonqualified retirement plans, reducing the final compensation due by the amounts reflected in Pension Benefits table.
For Messrs. Farrell, McGettrick and Christian upon termination with cause, they would receive payments of $3,111,462, $678,922 and $619,806, respectively under the terms of the nonqualified retirement plans, subject to the claw-back and removal from plan remedies discussed above. All shares of restricted stock and performance grants are forfeited upon a termination for cause. Messrs. Farrell, McGettrick and Christian would be entitled to qualified pension plan benefits at age 55. The estimated monthly life annuity benefit for Messrs. Farrell, McGettrick and Christian would be $571, $1,835 and $1,635, respectively. Messrs. Farrell, McGetrrick and Christian would also be entitled to unused vacation benefits of $35,674, $32,435 and $25,312, respectively.
Change in Control
Dominion has entered into an Employment Continuity Agreement with each of its officers, including the named executive officers. While Dominion has determined these agreements are consistent with the practices of its peer companies, the most important reason for these agreements is to protect the Company in the event of an anticipated or actual Change in Control at Dominion. In a time of transition, it is critical to company performance to retain and continue to motivate the company’s core management team. In a change of control situation, workloads typically increase dramatically, outside competitors are more likely to attempt to recruit top performers away from the company, and officers and other key employees may consider other opportunities when faced with uncertainties at their own company. Therefore, the Employment Continuity Agreements provide security and protection to officers in such circumstances for the long-term benefit of the Company.
The Employment Continuity Agreements provide benefits in the event of a Change in Control. Each agreement has a three-year term and is automatically extended annually for an additional year, unless cancelled by Dominion.
The agreements indemnify the executive for excise taxes and fees associated with the enforcement of the agreements. If an executive is terminated for cause, the agreements are not effective.
Dominion’s Continuity Agreements require two triggers for the payments of the benefits disclosed in the tables below:
n
There must be a Change in Control which is defined in CD&A on page 54 ; and
n
The executive must either: be terminated without cause, or terminate his or her employment with the surviving company after a “constructive termination”. Constructive termination means the executive’s salary, incentive compensation or job responsibility is reduced after a Change in Control, or the executive’s work location is relocated more than 50 miles without his or her consent (Constructive Termination).
The table below provides the payments that would be earned by each named executive officer if they were terminated, or constructively terminated, as of December 31, 2006 as a result of a Change in Control. For officers that are retirement eligible (Messrs. Chewning and Johnson), these benefits would be in addition to the retirement benefits discussed above. For executives that are not retirement eligible (Messrs. Farrell, McGettrick and Christian), these benefits are in addition to the benefits they would receive for a termination without cause disclosed above. All stock options held by our named executive officers are vested. In a Change in Control, outstanding options could be exercised or the CGN Committee may take actions with respect to unexercised options that it deems appropriate.
All cash payments disclosed in the table below are payable as a lump sum, unless noted otherwise. Certain lump-sum amounts will be paid six months after termination in order to be in compliance with the Internal Revenue Code.
Termination, including Constructive Termination, Due to Change in Control as of 12/31/2006 (1)
Footnotes:
(1)
The executive officers included in this table may perform services for more than one subsidiary of Dominion. The amounts listed in the table reflect only that portion allocated to the Company.
(2)
Amounts reflect annual premiums paid under the terms of the Employment Continuity Agreements. For Mr. Chewning, this benefit is disclosed as a retirement benefit in the table on page 63. For Messrs. Farrell, McGettrick, Johnson and Christian, life insurance premium payments would be made for five years if terminated as of December 31, 2006 in connection with a Change in Control.
(3)
Miscellaneous benefits include:
n
COBRA premiums for dental and vision coverage for 36 months.
n
The value of retiree medical coverage for which they are not eligible without a Change in Control.
n
Employee Term Life Insurance and Disability Insurance premium payments for 36 months from the date of the Change in Control.
n
Unused vacation that is not allowed to be sold under the vacation policy (up to one week), but could be sold under a Change in Control event.
COMPENSATION COMMITTEE REPORT
The Company is a wholly-owned subsidiary of Dominion. Our Board is comprised of Messrs. Farrell and Chewning, who are executive officers of the Company. Because our Board is not independent, we do not believe it is appropriate to have a separate compensation committee at our level. Instead, our Board depends on the advice and recommendations of Dominion’s Compensation, Governance and Nominating Committee (CGN Committee) which is comprised of independent directors and has retained the consulting firm of Pearl Meyer & Partners to advise them on compensation matters. Our Board approves all compensation paid to the Company’s executive officers based on the Dominion CGN Committee’s recommendations. In preparation for the filing of this Annual Report on Form 10-K, we reviewed and discussed management’s Compensation Discussion and Analysis and approved it for inclusion in this document.
Thomas F. Farrell, II
Thomas N. Chewning
February 28, 2007
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The table below sets forth as of February 9, 2007, the number of shares of Dominion common stock owned by directors and the executive officers named on the Summary Compensation Table.
(1) Amounts in this column represent share equivalents under a deferred compensation plan and do not have voting rights.
(2) Mr. Farrell disclaims ownership for 399 shares.
(3) All directors and executive officers as a group own less than one percent of the number of Dominion common shares outstanding as of February 9, 2007. No individual executive officer or director owns more than one percent of the shares outstanding.
(4) Mr. Chewning pledged 96,960 shares as collateral for a Wachovia Bank loan to a nonprofit organization. Based on the February 9, 2007 closing price of $87.46, if the loan for which these shares are pledged defaults, Wachovia Bank has the right to approximately 36,800 shares.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Related Party Transactions
In February 2007, our Board adopted the Related Party Guidelines also approved by Dominion’s Board of Directors. These guidelines were adopted in order to recognize the process to be used in identifying potential conflicts of interest arising out of financial transactions, arrangements and relations between the Company and any related persons. The term related person includes not only our directors and executive officers, but others related to them by certain family or business ties. The guidelines spell out in greater detail the practices outlined in our Code of Ethics and procedures already being followed.
We collect information about potential related party transactions (those in which a related party may have a material interest) in our annual questionnaires completed by directors and executive officers. Potential related party transactions are first reviewed by the Corporate Secretary and the General Counsel to consider the materiality of the transaction and then reported to Dominion’s CGN Committee. Dominion’s CGN Committee reviews and considers relevant facts and circumstances and determines whether to ratify, approve or deny the related party transactions identified. Since January 1, 2006 there have been no related party transactions involving the Company that were required either to be reported under the SEC related party rules or approved under the Company’s policies.
Director Independence
We are a wholly-owned subsidiary of Dominion. Our Board of Directors is comprised entirely of executive officers of the Company. The Board has determined that Thomas F. Farrell, II and Thomas N. Chewing, as executive officers of the Company, are not independent.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table presents fees paid to Deloitte & Touche LLP for the fiscal years ended December 31, 2006 and 2005.
Audit Fees are for the audit and review of our financial statements in accordance with generally accepted auditing standards, including comfort letters, statutory and regulatory audits, consents and services related to SEC matters.
Audit-Related Fees are for assurance and related services that are related to the audit or review of our financial statements, including employee benefit plan audits, due diligence services and financial accounting and reporting consultation.
Tax Fees reflect the settlement of outstanding arrangements related to tax planning assistance.
Our Board has adopted a pre-approval policy for Deloitte & Touche LLP services and fees. Attached to the policy is a schedule that details the services to be provided and an estimated range of fees to be charged for such services. In December 2006, Dominion’s Audit Committee approved the services and fees for 2007.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.
1. Financial Statements
See Index on page 24.
All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.
2. Exhibits
* Indicates management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VIRGINIA ELECTRIC AND POWER COMPANY
By:
/S/ THOMAS F. FARRELL, II
(Thomas F. Farrell, II,
Chairman of the Board of Directors
and Chief Executive Officer)
Date: February 28, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2007.
Signature
Title
/S/ THOMAS F. FARRELL, II
Thomas F. Farrell, II
Chairman of the Board of Directors and Chief Executive Officer
/S/ THOMAS N. CHEWNING
Thomas N. Chewning
Director, Executive Vice President and Chief Financial Officer
/S/ STEVEN A. ROGERS
Steven A. Rogers
Senior Vice President and Chief Accounting Officer