DOMINION RESOURCES INC /VA/
Item 1. Business
GENERAL
Dominion, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion’s strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. Dominion’s portfolio of assets includes approximately 28,142 MW of generating capacity, 6,300 miles of electric transmission lines, 56,800 miles of electric distribution lines, 11,000 miles of natural gas transmission, gathering and storage pipeline and 21,800 miles of gas distribution pipeline, exclusive of service lines of two inches in diameter or less. Dominion also operates the nation’s largest underground natural gas storage system, with approximately 947 bcf of storage capacity, and serves nearly 6 million utility and retail energy customers in 15 states.
Dominion is focused on expanding its investment in regulated electric generation, transmission and distribution and regulated natural gas transmission and distribution infrastructure within and around its existing footprint. As a result, regulated capital projects will continue to receive priority treatment in its spending plans. Dominion expects this will increase its earnings contribution from regulated operations, while reducing the sensitivity of its earnings to commodity prices.
Dominion continues to expand and improve its regulated electric and natural gas businesses, in accordance with its five-year investment program. A major impetus for this program is to meet the anticipated increase in electricity demand in its electric utility service territory as forecasted by PJM. Other drivers for the capital investment program include the need to construct infrastructure to handle the increase in natural gas production from the Marcellus and Utica Shale formations; and to upgrade its gas distribution and electric transmission and distribution network. Dominion has announced that it may make further substantial investments in other gas projects over the next five years.
Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations. Dominion’s operations are conducted through various subsidiaries, including Virginia Power.
Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina. In Virginia, Virginia Power conducts business under the name “Dominion Virginia Power.” In North Carolina, it conducts business under the name “Dominion North Carolina Power” and serves retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, Virginia Power sells electricity at wholesale prices to rural electric cooperatives, municipalities and into wholesale electricity markets. All of Virginia Power’s common stock is owned by Dominion.
Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.
EMPLOYEES
As of December 31, 2011, Dominion had approximately 15,800 full-time employees, of which approximately 5,900 employees are subject to collective bargaining agreements. As of December 31, 2011, Virginia Power had approximately 6,800 full-time employees, of which approximately 3,100 employees are subject to collective bargaining agreements.
PRINCIPAL EXECUTIVE OFFICES
Dominion and Virginia Power’s principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and their telephone number is (804) 819-2000.
WHERE YOU CAN FIND MORE INFORMATION ABOUT DOMINION AND VIRGINIA POWER
Dominion and Virginia Power file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov. You may also read and copy any document they file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.
Dominion and Virginia Power make their SEC filings available, free of charge, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, through Dominion’s internet website, www.dom.com, as soon as practicable after filing or furnishing the material to the SEC. You may also request a copy of these filings, at no cost, by writing or telephoning Dominion at: Corporate Secretary, Dominion, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Information contained on Dominion’s website is not incorporated by reference in this report.
ACQUISITIONS AND DISPOSITIONS
Following are significant divestitures by Dominion and Virginia Power during the last five years. There were no significant acquisitions by either registrant during this period.
SALE OF E&P PROPERTIES
In 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations, including its rights to associated Marcellus acreage, to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. See Note 4 to the Consolidated Financial Statements for additional information.
In 2007, Dominion completed the sale of its non-Appalachian natural gas and oil E&P operations and assets for approximately $13.9 billion.
The historical results of the non-Appalachian E&P operations are included in the Corporate and Other segment. The historical results of the Appalachian E&P operations are included in the Dominion Energy segment.
SALE OF PEOPLES
In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The historical results of these operations are included in the Corporate and Other segment and presented in discontinued operations. See Note 4 to the Consolidated Financial Statements for additional information.
ASSIGNMENT OF MARCELLUS ACREAGE
In 2008, Dominion completed a transaction with Antero Resources to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. Dominion received proceeds of approximately $347 million. Under the agreement, Dominion received a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. The overriding royalty interest was transferred to CONSOL as part of the sale of substantially all of Dominion’s Appalachian E&P operations in 2010.
SALE OF MERCHANT FACILITIES
In March 2007, Dominion sold three Peaker facilities for net cash proceeds of $254 million. The Peaker facilities included the 625 MW Armstrong facility in Shelocta, Pennsylvania; the 600 MW Troy facility in Luckey, Ohio; and the 313 MW Pleasants facility in St. Mary’s, West Virginia. The results of these operations were presented in discontinued operations.
SALE OF DRESDEN
In September 2007, Dominion completed the sale of Dresden to AEP Generating Company for $85 million.
SALE OF CERTAIN DCI OPERATIONS
In March 2008, Dominion reached an agreement to sell its remaining interest in the subordinated notes of a third-party CDO entity held as an investment by DCI and in April 2008 received proceeds of $54 million, including accrued interest. Dominion deconsolidated the CDO entity as of March 31, 2008.
In August 2007, Dominion completed the sale of Gichner, LLC, all of the issued and outstanding shares of the capital stock of Gichner, Inc. (an affiliate of Gichner, LLC) and Dallastown Realty for approximately $30 million.
OPERATING SEGMENTS
Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of the operations and sale of Peoples, which is discussed in Note 4 to the Consolidated Financial Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that
are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by Dominion and Virginia Power and their respective legal subsidiaries.
A description of the operations included in the Companies’ primary operating segments is as follows:
Primary Operating
Segment
Description of Operations
Dominion
Virginia
Power
DVP
Regulated electric distribution
X
X
Regulated electric transmission
X
X
Nonregulated retail energy marketing (electric and gas)
X
Dominion Generation
Regulated electric fleet
X
X
Merchant electric fleet
X
Dominion Energy
Gas transmission and storage
X
Gas distribution and storage
X
LNG import and storage
X
Producer services
X
For additional financial information on operating segments, including revenues from external customers, see Note 26 to the Consolidated Financial Statements. For additional information on operating revenue related to Dominion’s and Virginia Power’s principal products and services, see Notes 2 and 5 to the Consolidated Financial Statements, which information is incorporated herein by reference.
DVP
The DVP Operating Segment of Virginia Power includes Virginia Power’s regulated electric transmission and distribution (including customer service) operations, which serve approximately 2.4 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.
Virginia Power has announced its five-year investment plan, which includes spending approximately $4 billion from 2012 through 2016 to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability. The proposed electric delivery infrastructure projects are intended to address both continued population growth and increases in electricity consumption by the typical consumer. In addition, data centers continue to contribute to anticipated demand growth, with an expected load of approximately 715 MW by the end of 2013.
Revenue provided by electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures. Operationally, electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. As a result, electric service reliability and customer service have improved. The three-year average SAIDI has improved from 127 minutes at the end of 2006 to 111 minutes at the end of 2011. Likewise, ASA has also shown significant improvement. The three-year average ASA has improved from 60
seconds at the end of 2006 to 40 seconds at the end of 2011. Customer service options continue to be enhanced and expanded through the use of technology. Customers now have the ability to use the Internet for routine billing and payment transactions, connecting and disconnecting service, reporting outages and obtaining outage updates. Additionally, customers can follow progress to restore electric service following major outages by accessing Facebook or Twitter. As electric distribution moves forward, safety, electric service reliability and customer service will remain key focal areas.
Revenue provided by Virginia Power’s electric transmission operations is based primarily on rates approved by FERC. The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings primarily results from changes in rates and the timing of property additions, retirements and depreciation.
Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to NERC by EPACT, Virginia Power’s electric transmission operations are committed to meeting NERC standards, modernizing its infrastructure and maintaining superior system reliability. Virginia Power’s electric transmission operations will continue to focus on safety, operational performance, NERC compliance and execution of PJM’s RTEP.
The DVP Operating Segment of Dominion includes all of Virginia Power’s regulated electric transmission and distribution operations as discussed above, as well as Dominion’s nonregulated retail energy marketing operations.
Dominion’s retail energy marketing operations compete in nonregulated energy markets. The retail business requires limited capital investment and currently employs approximately 190 people. The retail customer base includes 2.2 million customers and is diversified across three product lines-natural gas, electricity and home warranty services. Dominion has a heavy concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice. Dominion pursues customers in electricity markets where utilities have divested of generation assets and where customers are permitted and have opted to purchase from the market. Major growth drivers are net customer additions, new market penetration, product development and expanded sales channels and supply optimization.
COMPETITION
DVP Operating Segment-Dominion and Virginia Power
Within Virginia Power’s service territory in Virginia and North Carolina, there is no competition for electric distribution service. Additionally, since its electric transmission facilities are integrated into PJM, electric transmission services are administered by PJM and are not subject to competition in relation to transmission service provided to customers within the PJM region. Virginia Power is seeing continued growth in new customers in its transmission and distribution operations.
DVP Operating Segment-Dominion
Dominion’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated
energy markets for natural gas and electricity. Customers in these markets have the right to select a retail marketer and typically do so based upon price savings or price stability; however, incumbent utilities have the advantage of long-standing relationships with their customers and greater name recognition in their markets.
REGULATION
Virginia Power’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia Commission and the North Carolina Commission. Virginia Power’s electric transmission rates, tariffs and terms of service are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. See State Regulations and Federal Regulations in Regulation and Note 14 to the Consolidated Financial Statements for additional information, including a discussion of the 2011 Biennial Review Order.
PROPERTIES
Virginia Power has approximately 6,300 miles of electric transmission lines of 69 kV or more located in the states of North Carolina, Virginia and West Virginia. Portions of Virginia Power’s 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 Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.
Each year, as part of PJM’s RTEP process, reliability projects are authorized. In 2011, Virginia Power completed construction of two of the major construction projects authorized in 2006, Meadow Brook-to-Loudoun and Carson-to-Suffolk, which are each designed to improve the reliability of service to customers and the region.
As part of subsequent annual PJM RTEP processes, PJM authorized additional electric transmission upgrade projects including Hayes-to-Yorktown in December 2008 and Mt. Storm-to-Doubs and Dooms-to-Bremo in December 2010. See Note 14 to the Consolidated Financial Statements for additional information on these and other electric transmission projects.
In addition, Virginia Power’s electric distribution network includes approximately 56,800 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that 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
DVP Operating Segment-Dominion and Virginia Power
DVP’s supply of electricity to serve Virginia Power customers is produced or procured by Dominion Generation. See Dominion Generation for additional information.
DVP Operating Segment-Dominion
The supply of electricity to serve Dominion’s retail energy marketing customers is procured through market wholesalers and RTO or ISO transactions. DVP’s supply of gas to serve its customers is procured through market wholesalers or by Dominion Energy. See Dominion Energy for additional information.
SEASONALITY
DVP Operating Segment-Dominion and Virginia Power
DVP’s earnings vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree-days for DVP’s electric utility related operations does not produce the same increase in revenue as an increase in cooling degree-days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
DVP Operating Segment-Dominion
The earnings of Dominion’s retail energy marketing operations also vary seasonally. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, while the demand for gas peaks during the winter months to meet heating needs.
Dominion Generation
The Dominion Generation Operating Segment of Virginia Power includes the generation operations of the Virginia Power regulated electric utility and its related energy supply operations. Virginia Power’s utility generation operations primarily serve the supply requirements for the DVP segment’s utility customers.
Earnings for the Generation operating segment of Virginia Power primarily result from the sale of electricity generated by its utility fleet. Revenue is based primarily on rates established by state regulatory authorities and state law. Approximately 80% of revenue comes from serving Virginia jurisdictional customers. Rates for the Virginia jurisdiction are set using a modified cost-of-service rate model. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. Variability in earnings for Virginia Power’s generation operations results from changes in rates, the demand for services, which is primarily weather dependent, and labor and benefit costs, as well as the timing, duration and costs of scheduled and unscheduled outages. See Electric Regulation in Virginia under Regulation and Note 14 to the Consolidated Financial Statements for additional information, including a discussion of the 2011 Biennial Review Order.
The Dominion Generation Operating Segment of Dominion includes Virginia Power’s generation facilities and its related energy supply operations described above as well as the generation operations of Dominion’s merchant fleet and energy marketing and price risk management activities for these assets. The Generation operating segment of Dominion derives its earnings primarily from the sale of electricity generated by Virginia Power’s utility and Dominion’s merchant generation assets, as well as
associated capacity and ancillary services from Dominion’s merchant generation assets.
Variability in earnings provided by Dominion’s merchant fleet relates to changes in market-based prices received for electricity and capacity. Market-based prices for electricity are largely dependent on commodity prices, primarily natural gas, and the demand for electricity, which is primarily dependent upon weather. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion manages electric and capacity price volatility of its merchant fleet by hedging a substantial portion of its expected near-term sales with derivative instruments and also entering into long-term power sales agreements. However, earnings have been adversely impacted due to a sustained decline in commodity prices. Variability also results from changes in the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages.
COMPETITION
Dominion Generation Operating Segment-Dominion and Virginia Power
Virginia Power’s generation operations are not subject to significant competition as only a limited number of its Virginia jurisdictional electric utility customers have retail choice. See Regulation-State Regulations-Electric for more information. Currently, North Carolina does not offer retail choice to electric customers.
Dominion Generation Operating Segment-Dominion
Unlike Dominion Generation’s regulated generation fleet, its merchant generation fleet is dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that allows for a rate of return on its capital investments. Competition for the merchant fleet is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact the merchant fleet’s ability to profit from the sale of electricity and related products and services.
Dominion Generation’s merchant generation fleet owns and operates several facilities in the Midwest that operate within functioning RTOs. A significant portion of the output from these facilities is sold under long-term contracts, with expiration dates ranging from December 31, 2012 to August 31, 2017, and is therefore largely unaffected by price competition during the term of these contracts. Following expiration of these contracts, earnings could be adversely impacted if prevailing prices for energy, capacity and ancillary services are lower than the levels currently received under these contracts.
Dominion Generation’s other merchant assets also operate within functioning RTOs and primarily compete on the basis of price. Competitors include other generating assets bidding to operate within the RTOs. These RTOs have clearly identified market rules that ensure the competitive wholesale market is
functioning properly. Dominion Generation’s merchant units have a variety of short- and medium-term contracts, and also compete in the spot market with other generators to sell a variety of products including energy, capacity and ancillary services. It is difficult to compare various types of generation given the wide range of fuels, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, Dominion applies its expertise in operations, dispatch and risk management to maximize the degree to which its merchant fleet is competitive compared to similar assets within the region.
REGULATION
Virginia Power’s utility generation fleet and Dominion’s merchant generation fleet are subject to regulation by FERC, the NRC, the EPA, the DOE, the Army Corps of Engineers and other federal, state and local authorities. Virginia Power’s utility generation fleet is also subject to regulation by the Virginia Commission and the North Carolina Commission. See State Regulations and Federal Regulations in Regulation for more information.
PROPERTIES
For a listing of Dominion’s and Virginia Power’s existing generation facilities, see Item 2. Properties.
Dominion Generation Operating Segment-Dominion and Virginia Power
The generation capacity of Virginia Power’s electric utility fleet totals 18,985 MW. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro and renewables. Virginia Power’s generation facilities are located in Virginia, West Virginia and North Carolina and serve load in Virginia and northeastern North Carolina.
Based on available generation capacity and current estimates of growth in customer demand in its utility service area, Virginia Power will need additional generation capacity over the next decade. Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the anticipated growing demand in its core market in Virginia. Significant projects under construction or development include:

The Virginia City Hybrid Energy Center located in Wise County, Virginia, is expected to generate about 585 MW when completed. The baseload facility is estimated to cost $1.8 billion, excluding financing costs. Construction was approximately 95% complete at the end of 2011, and commercial operations are expected to commence in the summer of 2012.

Warren County is expected to generate more than 1,300 MW of electricity when operational. In February 2012, the Virginia Commission authorized the construction of this power station, which is estimated to cost approximately $1.1 billion, excluding financing costs. Commercial operations are scheduled to commence by late 2014. In connection with the air permit process for Warren County, Virginia Power reached an agreement to permanently retire North Branch, a 74 MW coal-fired plant located in West Virginia, once Warren County begins commercial operations.

Virginia Power plans to convert three coal-fired Virginia generating stations to biomass, a renewable energy source. The conversions of the power stations in Altavista, Hopewell and Southampton County would increase Dominion’s renewable generation by more than 150 MW and are expected to cost approximately $165 million, excluding financing costs. After approvals by the Virginia Department of Environmental Quality and the Virginia Commission, construction will begin; these conversions are expected to be complete by the end of 2013.

Subject to the receipt of certain regulatory approvals, Virginia Power plans to construct a combined-cycle natural gas-fired power station in Brunswick County, Virginia, that is expected to generate more than 1,300 MW. If the project is approved, commercial operations are expected to commence in 2016. Brunswick County has approved a conditional use permit to allow for construction of the plant. This facility would more than offset the expected reduction in capacity caused by the anticipated retirement of coal-fired units at Chesapeake and Yorktown during 2015 and 2016 primarily due to the cost of compliance with MATS. The facility would be similar to the power station being built in Warren County, Virginia, which is estimated to cost approximately $1.1 billion, excluding financing costs.
In May 2011, Virginia Power completed construction of Bear Garden, at a total cost of approximately $620 million, excluding financing costs, and the 590 MW combined-cycle, natural gas-fired power station commenced commercial operations.
In addition to the projects above, Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. See Note 14 to the Consolidated Financial Statements for more information on this project.
Dominion Generation Operating Segment-Dominion
The generation capacity of Dominion’s merchant fleet totals 9,157 MW. The generation mix is diversified and includes nuclear, coal, gas, oil and renewables. Merchant generation facilities are located in Connecticut, Illinois, Indiana, Massachusetts, Pennsylvania, Rhode Island, West Virginia and Wisconsin with a majority of that capacity concentrated in New England. Dominion is the largest generator in ISO-NE and, mirroring the region’s load demand, has principally baseload units with the remainder split between intermediate and peaking.
In the first quarter of 2011, Dominion decided to pursue the sale of Kewaunee. Any sale of Kewaunee would be subject to the approval of Dominion’s Board of Directors, as well as applicable state and federal approvals.
During the second quarter of 2011, Dominion announced its intention to retire State Line by mid-2014 and to retire two of the four units at Salem Harbor by the end of 2011 and the remaining two Salem Harbor units on June 1, 2014. These decisions were prompted by the economic outlook for both facilities, in combination with the expectation that State Line would be impacted by potential environmental regulations that would likely require significant capital expenditures. During the third quarter of 2011, Dominion announced an accelerated schedule for State Line, with the facility to be retired in the first quarter of 2012, given a continued decline in power prices and the expected cost to comply with environmental regulations.
Salem Harbor units 1 and 2 were retired as planned on December 31, 2011.
SOURCES OF ENERGY SUPPLY
Dominion Generation Operating Segment-Dominion and Virginia Power
Dominion Generation uses a variety of fuels to power its electric generation and purchases power for utility system load requirements and to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are included as contractual obligations in Future Cash Payments for Contractual Obligations and Planned Capital Expenditures in Item 7. MD&A.
Nuclear Fuel-Dominion 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-Dominion Generation primarily utilizes coal, oil and natural gas in its fossil fuel plants.
Dominion Generation’s coal supply is obtained through long-term contracts and short-term spot agreements from both domestic and international suppliers.
Dominion 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.
Dominion Generation manages a portfolio of natural gas transportation contracts (capacity) that allows flexibility in delivering natural gas to its gas turbine fleet, while minimizing costs.
Purchased Power-Dominion Generation purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for utility system load requirements.
Dominion Generation also occasionally purchases electricity from the PJM, ISO-NE and MISO spot markets to satisfy physical forward sale requirements as part of its merchant generation operations.
Dominion Generation Operating Segment-Virginia Power
Presented below is a summary of Virginia Power’s actual system output by energy source:
(1) Excludes ODEC’s 11.6% ownership interest in North Anna.
(2) Excludes ODEC’s 50.0% ownership interest in the Clover power station. The average cost of coal for 2011 Virginia in-system generation was $33.55 per MWh.
(3) Includes oil, hydro and biomass.
SEASONALITY
Sales of electricity for Dominion Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree-days does not produce the same increase in revenue as an increase in cooling degree-days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
NUCLEAR DECOMMISSIONING
In June 2011, the NRC amended its regulations to improve decommissioning planning. As applied to the operators of nuclear power plants, these amendments require licensees to conduct operations in a manner minimizing introduction of residual radioactivity into the site, perform additional surveys, and maintain records of their results. In addition, the amendments make minor changes to financial assurance methods and require additional information on decommissioning and spent fuel management costs after a plant permanently ceases operations. The revised regulations will become effective in December 2012 and are not expected to significantly affect the decommissioning cost estimates or funding for Dominion’s or Virginia Power’s units.
Dominion Generation Operating Segment-Dominion and Virginia Power
Virginia Power has a total of four licensed, operating nuclear reactors at its Surry and North Anna power stations in Virginia.
Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. 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.
Virginia Power believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects the long-term investment horizon, since the units will not be decommissioned for decades, and a positive long-term outlook for trust fund investment returns. Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC.
The total estimated cost to decommission Virginia Power’s four nuclear units is $2.2 billion in 2011 dollars and is primarily based upon site-specific studies completed in 2009. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Virginia Power expects to decommission the Surry and North Anna units during the period 2032 to 2067.
Dominion Generation Operating Segment-Dominion
In addition to the four nuclear units discussed above, Dominion has three licensed, operating nuclear reactors, two at Millstone in Connecticut and one at Kewaunee in Wisconsin. A third Millstone unit ceased operations before Dominion acquired the power station. As part of Dominion’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunee’s trust after decommissioning is completed are required to be refunded to Wisconsin ratepayers. Dominion believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Dominion will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC. The total estimated cost to decommission Dominion’s eight units is $4.7 billion in 2011 dollars and is primarily based upon site-specific studies completed in 2009. For the Millstone and Kewaunee operating units, the current cost estimate assumes decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Millstone Unit 1 is not in service and selected minor decommissioning activities are being performed. This unit will continue to be monitored until full decommissioning activities begin for the remaining Millstone operating units. Dominion expects to start minor decommissioning activities at Millstone Unit 2 in 2035, with full decommissioning of Millstone Units 1, 2 and 3 at the permanent cessation of operations of Millstone Unit 3 during the period 2045 to 2069. In February 2011, the NRC approved the renewal of the Kewaunee operating license. The renewal permits Kewaunee to operate through December 21, 2033 with full decommissioning of Kewaunee during the period 2033 to 2065.
The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion and Virginia Power are shown in the following table.
(1) The cost estimates shown above are total decommissioning cost estimates and differ from the cost estimates used to calculate Dominion’s and Virginia Power’s nuclear decommissioning AROs. Among other items, the cost estimates above do not reflect any reduction for the expected future
recovery from the DOE of certain spent fuel costs based on the Companies’ contracts with the DOE for disposal of spent nuclear fuel.
(2) North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect 89.26% of the decommissioning cost for both of North Anna’s units.
(3) Unit 1 ceased operations in 1998, before Dominion’s acquisition of Millstone.
(4) Millstone Unit 3 is jointly owned by Dominion Nuclear Connecticut, with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation. Decommissioning cost is shown at 100% and the trust funds are shown at Dominion’s ownership percentage. At December 31, 2011, the minority owners held approximately $27 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.
Also see Note 15 and Note 23 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively.
Dominion Energy
Dominion Energy includes Dominion’s regulated natural gas distribution companies, regulated gas transmission pipeline and storage operations, natural gas gathering and by-products extraction activities and regulated LNG operations. Dominion Energy also includes producer services, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates.
The gas transmission pipeline and storage business serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in Dominion’s gas transmission pipeline and storage business is its gas gathering and extraction activity, which sells extracted products at market rates. Dominion’s LNG operations involve the import and storage of LNG at Cove Point and the transportation of regasified LNG to the interstate pipeline grid and mid-Atlantic and Northeast markets. In connection with the recent increase in Eastern U.S. natural gas production, including from the Marcellus and Utica shale formations, Dominion has requested regulatory authority to operate Cove Point as a bi-directional facility, able to import LNG, and vaporize it as natural gas, and liquefy natural gas and export it as LNG. See Future Issues and Other Matters in MD&A for more information.
Revenue provided by Dominion’s regulated gas transmission and storage and LNG operations is based primarily on rates established by FERC. Additionally, Dominion receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain gas transportation, gas storage, LNG storage and regasification services. Dominion’s gas distribution operations serve residential, commercial and industrial gas sales and transportation customers. Revenue provided by its gas distribution operations is based primarily on rates established by the Ohio and West Virginia Commissions. The profitability of these businesses is dependent on Dominion’s ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.
In October 2008, East Ohio implemented a rate case settlement which provided for a straight-fixed-variable rate design.
Under this rate design, East Ohio recovers a larger portion of its fixed operating costs through a flat monthly charge accompanied by a reduced volumetric base delivery rate. Accordingly, East Ohio’s revenue is less impacted by weather-related fluctuations in natural gas consumption than under the traditional rate design.
Earnings from Dominion Energy’s producer services business are unregulated, and are subject to variability associated with changes in commodity prices. Producer services uses physical and financial arrangements to hedge this price risk.
COMPETITION
Dominion Energy’s gas transmission operations compete with domestic and Canadian pipeline companies. Dominion also competes with gas marketers seeking to provide or arrange transportation, storage and other services. Alternative energy sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain long-line pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enable Dominion to tailor its services to meet the needs of individual customers.
Retail competition for gas supply exists to varying degrees in the two states in which Dominion’s gas distribution subsidiaries operate. In Ohio, there has been no legislation enacted to require supplier choice for residential and commercial natural gas consumers. However, Dominion offers an Energy Choice program to customers, in cooperation with the Ohio Commission. At December 31, 2011, approximately 1 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice Program. West Virginia does not require customers to choose their provider in its retail natural gas markets at this time. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customers a choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia. See Regulation-State Regulations-Gas for additional information.
REGULATION
Dominion Energy’s natural gas transmission pipeline, storage and LNG operations are regulated primarily by FERC. Dominion Energy’s gas distribution service, including the rates that it may charge customers, is regulated by the Ohio and West Virginia Commissions. See State Regulations and Federal Regulations in Regulation for more information.
PROPERTIES
Dominion Energy’s gas distribution network is located in the states of Ohio and West Virginia. This network involves approximately 21,800 miles of pipe, exclusive of service lines of two inches in diameter or less. The rights-of-way grants for many natural gas pipelines have been obtained from the actual owner of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.
Dominion Energy has approximately 11,000 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy operates gas processing and fractionation facilities in West Virginia with a total processing capacity of 267,000 mcf per day and fractionation capacity of 582,000 gallons per day. Dominion Energy also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with almost 2,000 storage wells and approximately 349,000 acres of operated leaseholds.
The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 947 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy. The capacity of those fields owned by Dominion’s partners totals about 242 bcf. Dominion Energy also has about 15 bcf of above-ground storage capacity at Cove Point. Dominion Energy has about 128 compressor stations with more than 777,000 installed compressor horsepower.
In August 2009, Dominion announced the proposed development of the Keystone Connector Project, a joint venture with The Williams Companies that would transport new natural gas supplies from the Appalachian Basin to Transcontinental Gas Pipe Line Corporation’s Station 195, providing access to markets throughout the eastern U.S. The joint venture was terminated in June 2011. DTI is currently independently marketing its Keystone Connector Project. Project timing is subject to producer drilling plans in the Appalachian Basin, as well as customer demand throughout the mid-Atlantic and Northeast regions.
In January 2011, Dominion completed the $50 million Cove Point Pier Reinforcement Project to upgrade, expand and modify the existing pier at the Cove Point terminal to accommodate the next generation of LNG vessels (up to 267,000 cubic meters) that are much larger than those that could previously be accommodated (no larger than 148,000 cubic meters).
DTI has announced the Gathering Enhancement Project, a $253 million expansion of its natural gas gathering, processing and liquids facilities in West Virginia. The project is designed to increase the efficiency and reduce high pressures in its gathering system, thus increasing the amount of natural gas local producers can move through DTI’s West Virginia system. Construction started in 2009 and is expected to be completed by the fourth quarter of 2012. The cost of the project will be paid for by rates charged to producers.
In June 2011, FERC approved DTI’s $634 million Appalachian Gateway Project. The project is expected to provide approximately 484,000 dekatherms per day of firm transportation services for new Appalachian gas supplies in West Virginia and southwestern Pennsylvania to an interconnection with Texas Eastern Transmission, LP at Oakford, Pennsylvania. Construction has commenced and transportation services are scheduled to begin by September 2012.
In August 2011, DTI received FERC authorization for the Northeast Expansion Project. The project is expected to provide approximately 200,000 dekatherms per day of firm transportation services for CONSOL’s Marcellus Shale natural gas production from various receipt points in central and southwestern Pennsylvania to a nexus of market pipelines and storage facilities in Leidy, Pennsylvania. The project is expected to cost approximately $100 million. Construction of new compression facilities
at three existing compressor stations in central Pennsylvania is expected to begin in March 2012, with a projected in-service date of November 2012.
In September 2011, FERC approved DTI’s proposed Ellisburg-to-Craigs project. The project is expected to have capacity of approximately 150,000 dekatherms per day, which will be leased by TGP to move Marcellus shale natural gas supplies from TGP’s 300 Line pipeline system in northern Pennsylvania to its 200 Line pipeline system in upstate New York. The project is expected to cost approximately $46 million. Construction of additional compression facilities and a new measurement and regulating station is expected to begin in March 2012, with a projected in-service date of November 2012.
In November 2011, DTI filed a FERC application for approval to construct the $17 million Sabinsville to Morrisville project, a pipeline to move additional Marcellus supplies from a TGP pipeline in northeast Pennsylvania to its line in upstate New York. DTI executed a binding precedent agreement with TGP in October 2010 to provide this firm transportation service up to 92,000 dekatherms per day for a 14-year term. Construction is expected to commence April 2013 with an expected in service date of November 2013.
DTI is developing the Allegheny Storage Project, which is expected to provide approximately 7.5 bcf of incremental storage service and 125,000 dekatherms per day of associated year-round firm transportation service to three local distribution companies under 15-year contracts. Storage capacity for the project will be provided from storage pool enhancements at DTI and capacity leased from East Ohio. DTI intends to construct additional compression facilities and upgrade measurement and regulation in order to provide 115,000 dekatherms per day of transportation service. The remaining 10,000 dekatherms per day of transportation service will not require construction of additional facilities. The $112 million project is expected to be in service in 2014, subject to FERC approval, which DTI requested in February 2012.
In February 2011, DTI concluded a binding open season for its $67 million Tioga Area Expansion Project, which is designed to provide approximately 270,000 dekatherms per day of firm transportation service from supply interconnects in Tioga and Potter Counties in Pennsylvania to DTI’s Crayne interconnect with Texas Eastern Transmission, LP in Greene County, Pennsylvania and the Leidy interconnect with Transcontinental Gas Pipe Line Company in Clinton County, Pennsylvania. Two customers have contracted for the service under 15-year terms. DTI filed a certificate application with FERC in November 2011. Subject to the receipt of regulatory approvals, the project is anticipated to be in service in November 2013.
In January 2011, Dominion announced the development of a natural gas processing and fractionation facility in Natrium, West Virginia, and in July 2011 it executed a contract for the construction of the first phase of the facility. This phase of the project is fully contracted and is expected to be in service by December 2012. The Phase 1 costs for processing, fractionation, plant inlet and outlet natural gas transportation, gathering, and various modes of NGL transportation is approximately $500 million. Dominion is also in negotiations for the possible construction of Phase 2 at Natrium, which could be in service by the fourth quar-
ter of 2013. The complete project is designed to process up to 400,000 mcf of natural gas per day and fractionate up to 59,000 barrels of NGLs per day.
In March 2011, East Ohio filed a request with the Ohio Commission to accelerate the PIR program by nearly doubling its PIR spending to more than $200 million annually. East Ohio identified 1,450 miles of pipeline that need to be replaced, in addition to the pipeline originally identified in the PIR project scope. See Note 14 to the Consolidated Financial Statements for additional information.
SOURCES OF ENERGY SUPPLY
Dominion Energy’s natural gas supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area and gas marketers. Dominion’s large underground natural gas storage network and the location of its pipeline system are a significant link between the country’s major interstate gas pipelines, including the Rockies Express East pipeline, and large markets in the Northeast and mid-Atlantic regions. Dominion’s pipelines are part of an interconnected gas transmission system, which provides access to supplies nationwide for local distribution companies, marketers, power generators and industrial and commercial customers.
Dominion’s underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Northeast, mid-Atlantic and Midwest regions. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transmission capacity.
SEASONALITY
Dominion Energy’s natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March, however implementation of the straight-fixed-variable rate design at East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipeline and storage business can also be weather sensitive. Commodity prices can be impacted by seasonal weather changes, the effects of unusual weather events on operations and the economy. Dominion’s producer services business is affected by seasonal changes in the prices of commodities that it transports, stores and actively markets and trades.
Corporate and Other
Corporate and Other Segment-Virginia Power
Virginia Power’s Corporate and Other segment primarily includes certain specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Corporate and Other Segment-Dominion
Dominion’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) and the net impact of the operations and sale of Peoples, which is
discussed in Note 4 to the Consolidated Financial Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
ENVIRONMENTAL STRATEGY
Dominion and Virginia Power are committed to being good environmental stewards. Their ongoing objective is to provide reliable, affordable energy for their customers while being environmentally responsible. The integrated strategy to meet this objective consists of five major elements:

Compliance with applicable environmental laws, regulations and rules;

Conservation and load management;

Renewable generation development;

Other generation development to maintain fuel diversity, including clean coal, advanced nuclear energy, and natural gas; and

Improvements in other energy infrastructure.
This strategy incorporates Dominion’s and Virginia Power’s efforts to voluntarily reduce GHG emissions, which are described below. See Dominion Generation-Properties for more information on certain of the projects described below, as well as other projects under current development.
Environmental Compliance
Dominion and Virginia Power remain committed to compliance with all applicable environmental laws, regulations and rules related to their operations. Additional information related to Dominion’s and Virginia Power’s environmental compliance matters can be found in Future Issues and Other Matters in MD&A and in Note 23 to the Consolidated Financial Statements.
Conservation and Load Management
Conservation plays a significant role in meeting the growing demand for electricity. The Regulation Act provides incentives for energy conservation and sets a voluntary goal to reduce electricity consumption by retail customers in 2022 by ten percent of the amount consumed in 2006 through the implementation of conservation programs. Legislation in 2009 added definitions of peak-shaving and energy efficiency programs and allowed for a margin on operating expenses and revenue reductions related to energy efficiency programs.
Virginia Power’s DSM programs provide important incremental steps toward achieving the voluntary ten percent energy conservation goal. The conservation and load management plan includes the following DSM programs, which were approved by the Virginia Commission in March 2010 and were rolled out in May 2010:

Residential Lighting Program-an instant, in-store discount on the purchase of qualifying compact fluorescent lights;

Home Energy Improvement-energy audits and improvements for homes of low-income customers;

Smart Cooling Rewards-incentives for residential customers who voluntarily enroll to allow Virginia Power to cycle their air conditioners and heat pumps during periods of peak demand;

Commercial Heating, Ventilating and Air Conditioning Upgrade Program-incentives for commercial customers to improve the energy efficiency of their heating and/or cooling units; and

Commercial Lighting Program-incentives for commercial customers to install energy-efficient lighting.
In September 2011, Virginia Power filed an application for approval of six additional DSM programs and to expand the approved Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs, in addition to requesting annual recovery of DSM program costs. The proposed DSM programs include:

Commercial Energy Audit Program-an on-site energy audit providing commercial customers with information to evaluate potential energy cost savings options;

Commercial Duct Testing & Sealing-an incentive for commercial customers to seal duct and air distribution systems to improve system efficiency;

Commercial Refrigeration Program-an incentive for commercial customers to install more efficient refrigeration technologies;

Commercial Distributed Generation-a redesigned distributed generation program allowing customers to commit their on-site back-up generators to Virginia Power during periods of peak demand;

Residential Lighting Phase II-an extension of the initial in-store discount on the purchase of qualifying compact fluorescent lighting as well as light-emitting diode bulbs to phase out and replace conventional incandescent bulbs; and

Residential Bundle Program-a bundle of four residential programs to be available to residential customers, including a Residential Home Energy Check-up Program, Residential Duct Testing & Sealing Program, Residential Heat Pump Tune-Up Program and Residential Heat Pump Upgrade Program.
In September 2010, Virginia Power filed with the North Carolina Commission an application for approval and its initial request for cost recovery of the five DSM programs initially approved in Virginia, as well as the distributed generation program. In February 2011, the North Carolina Commission approved the five DSM programs approved in Virginia, and Virginia Power subsequently launched the residential lighting program in May 2011 and the remainder of the approved programs in June 2011. In a separate order issued in September of 2011, the North Carolina Commission denied approval of Virginia Power’s proposed distributed generation program.
Virginia Power continues to assess smart grid technologies through a demonstration designed to indicate how these technologies may enhance Virginia Power’s electric distribution system by allowing energy to be delivered more efficiently. The demonstration involves a limited deployment, within Virginia Power’s Virginia service territory, of smart meters that use digital technology to enable two-way communication between the meter and Virginia Power’s electric distribution system. Dependent upon the outcome of the demonstration and certain regulatory proceedings, Virginia Power may make a significant investment in replacing existing meters with Advanced Metering Infrastructure. The technology is intended to help customers monitor and control their
energy use. It is also expected to lead to more efficient use of the power grid, which is expected to result in energy savings and lower environmental emissions. Moreover, deployment of smart grid technology is expected to provide more accurate outage information, fewer service calls, and faster service restoration.
Renewable Generation
Renewable energy is also an important component of a diverse and reliable energy mix. Both Virginia and North Carolina have passed legislation setting targets for renewable power. Virginia Power is committed to meeting Virginia’s goals of 12% renewable power by 2022 and 15% by 2025, and North Carolina’s RPS of 12.5% by 2021. In May 2010, the Virginia Commission approved Virginia Power’s participation in the state’s RPS program. As a participant, Virginia Power is permitted to seek recovery, through rate adjustment clauses, of the costs of programs designed to meet RPS goals. Virginia Power plans to meet the respective RPS targets in Virginia and North Carolina by utilizing existing renewable facilities, as well as through additional renewable generation where it makes sense for customers. In addition, Virginia Power intends to purchase renewable energy certificates, as permitted by each RPS program, to meet any remaining annual requirement needs. Virginia Power continues to explore opportunities to develop new renewable facilities within its service territory, the energy attributes of which would qualify for inclusion in the RPS programs.
Dominion has invested in wind energy through two joint ventures. Dominion is a 50% owner of NedPower. Dominion’s share of this project produces 132 MW of renewable energy. Dominion is also a 50% owner with BP of the first phase of Fowler Ridge, which has a generating capacity of 300 MW. Dominion has a long-term agreement with Fowler Ridge to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In the first quarter of 2011, Dominion completed the sale of its remaining share of the development assets of the second phase of Fowler Ridge to BP.
In October 2011, Virginia Power filed with the Virginia Commission an application to conduct a solar distributed generation demonstration program, consisting of up to a combined 30 MW of company-owned solar distributed generation facilities to be located at selected commercial, industrial and community locations throughout its Virginia service territory, as well as up to a combined 3 MW of customer-owned solar distributed generation facilities that will be subject to a tariff filed with the Virginia Commission in 2012. If approved, this program is expected to generate enough electricity to power about 6,000 homes during peak daylight hours.
Other Generation Development
Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the anticipated growth in demand in its core market of Virginia. Virginia Power expects that these investments collectively will provide the following benefits: expanded electricity production capability, increased technological and fuel diversity and a reduction in the CO2 emission intensity of its generation fleet.
Improvements in Other Energy Infrastructure
Virginia Power’s five-year investment plan includes significant capital expenditures to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service, and are intended to address both continued population growth and increases in electricity consumption by the typical consumer. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed or to be developed in the future.
Virginia Power is taking measures to ensure that its electrical infrastructure can support the expected demand from electric vehicles, which have significantly lower carbon intensity than conventional vehicles. Virginia Power has partnered with Ford Motor Company to help prepare Virginia for the operation of electric vehicles, in a collaboration that involves consumer outreach, educational programs and the exchange of information on vehicle charging requirements.
Dominion, in connection with its five-year growth plan, is also pursuing the construction or upgrade of regulated infrastructure in its natural gas business.
Dominion and Virginia Power’s Strategy for Voluntarily Reducing GHG Emissions
While Dominion and Virginia Power have not established a standalone GHG emissions reduction target or timetable, they are actively engaged in voluntary reduction efforts, as well as working toward achieving required RPS standards established by existing state regulations, as set forth above. The Companies have an integrated voluntary strategy for reducing overall GHG emission intensity that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, oil, hydro and renewable energy, investing in renewable energy projects and promoting energy conservation and efficiency efforts. Below are some of the Companies’ efforts that have or are expected to reduce the Companies’ overall carbon emissions or intensity:

In 2003, Virginia Power retired two oil-fired units at its Possum Point power station, replacing them with a new 559 MW combined-cycle natural gas unit. Virginia Power also converted two coal-fired units at Possum Point to cleaner burning natural gas.

Since 2000, Dominion has added over 2,600 MW of non-emitting nuclear generation and over 3,500 MW of new lower-emitting natural gas-fired generation including nearly 1,600 MW at Virginia Power (excluding Possum Point), to its generation mix.

Virginia Power added 83 MW of renewable biomass and has plans to convert three coal-fired power stations to biomass, which is anticipated to be considered carbon neutral by regulatory agencies.

Dominion has over 800 MW of wind energy in operation or development.

Virginia Power completed construction of the natural gas-fired Bear Garden generating facility in May 2011.

Virginia Power is constructing the natural gas-fired Warren County power station. In connection with the air permit process for Warren County, Virginia Power reached an
agreement with the National Park Service to permanently retire the North Branch power station, a 74 MW coal fired plant located in West Virginia, once Warren County begins commercial operations.

Virginia Power plans to construct an additional combined-cycle natural gas-fired power station similar in size to Warren County to replace coal-fired units at Chesapeake and Yorktown that are anticipated to be retired in 2015 and 2016.

Virginia Power has received an Early Site Permit from the NRC for the possible addition of approximately 1,500 MW of nuclear generation in Virginia. Virginia Power has not yet committed to building a new nuclear unit.

Virginia Power has developed the DSM programs described above.

Virginia Power has initiated a demonstration of smart grid technologies as described above.

In October 2011, Virginia Power announced plans to develop the community solar power program described above.

Dominion retired two coal-fired units at Salem Harbor in 2011 and announced that the remaining units at Salem Harbor will be retired during the second quarter of 2014.

Dominion has announced its plans to retire State Line during the first quarter of 2012.
While Virginia Power’s new Virginia City Hybrid Energy Center, which is currently under construction in southwest Virginia, will be a new source of GHG emissions upon entering service, Virginia Power has taken steps to minimize the impact on the environment. The new plant is expected to use at least 10% biomass for fuel and is designed to be carbon-capture compatible, meaning that technology to capture CO2 can be added to the station if or when it becomes commercially available. Also, Virginia Power has announced plans to convert its coal units at Bremo to natural gas, contingent upon the Virginia City Hybrid Energy Center entering service and receipt of necessary approvals. It is currently estimated that the Virginia City Hybrid Energy Center will have the potential to emit about 4.8 million metric tonnes of direct CO2 emissions in a year assuming a 100% capacity factor and 100% coal-fired operation. Actual emissions will depend on the capacity factor of the facility and the extent to which biomass is burned.
Dominion also developed a comprehensive GHG inventory for calendar year 2010. For Dominion Generation, Dominion’s and Virginia Power’s direct CO2 equivalent emissions, based on equity share (ownership), were approximately 52.4 million metric tonnes and 32.4 million metric tonnes, respectively. For the DVP operating segment’s electric transmission and distribution operations, direct CO2 equivalent emissions were approximately 0.2 million metric tonnes. DTI’s (including Cove Point) direct CO2 equivalent emissions were approximately 3.0 million metric tonnes and East Ohio’s direct CO2 equivalent emissions were approximately 1.4 million metric tonnes. While the Companies do not have final 2011 emissions data, they do not expect a significant variance in emissions from 2010 amounts. With respect to electric generation, primary facility stack emissions of CO2 from carbon based fuel combustion are directly measured via continuous emissions monitor system methods set forth under 40 CFR Part 75 of the U.S. Electric Code of Federal Regulation. For those emission sources not covered under 40 CFR Part 75, and
for methane and nitrous oxide emissions, quantification is based on fuel combustion, higher heating values, emission factors, and global warming potentials as specified in the EPA’s Mandatory Reporting of Greenhouse Gases Rule. For the DVP operating segment’s electric transmission and distribution emissions, the protocol used was The Climate Registry. For Dominion’s natural gas businesses, combustion related emissions were calculated using the EPA Mandatory Reporting of Greenhouse Gases Rule as described above. For DTI, the protocol used to calculate the non-combustion related emissions reported above was Greenhouse Gas Emission Estimation Guidelines for Natural Gas Transmission and Storage, Volume 1-GHG Estimation Methodologies and Procedures-Revision 2, September 28, 2005 developed by the Interstate Natural Gas Association of America. For East Ohio, the protocol used to calculate the non-combustion related emissions was the American Gas Association’s April 2008 Greenhouse Emissions Estimation Methodologies and Procedures for Natural Gas Distribution Operations.
Since 2000, the Companies have tracked the emissions of their electric generation fleet. Their electric generation fleet employs a mix of fuel and renewable energy sources. Comparing annual year 2000 to annual year 2010, Dominion and Virginia Power’s electric generating fleet (based on ownership percentage) reduced their average CO2 emissions rate per MWh of energy produced from electric generation by about 21% and 10%, respectively. During such time period the capacity of Dominion and Virginia Power’s electric generation fleet has grown.
Alternative Energy Initiatives
In addition to the environmental strategy described above, Dominion formed the AES department in April 2009 to conduct research in the renewable and alternative energy technologies sector and to support strategic investments to advance Dominion’s base of understanding of such technologies. AES participates in federal and state policy development on alternative energy and identifies potential alternative energy resource and technology opportunities for Dominion’s business units. For example, in March 2011, AES initiated a Dominion scoping study for a high-voltage underwater transmission line from Virginia Beach into the ocean to support multiple offshore wind farms; the first of many steps with the goal being the development of a transmission line making offshore wind resources available to its customers. A 2010 Dominion study of its existing transmission system in eastern Virginia showed that it is possible to interconnect large scale wind facilities up to an installed capability of 4,500 MW.
REGULATION
Dominion and Virginia Power are subject to regulation by the Virginia Commission, North Carolina Commission, SEC, FERC, EPA, DOE, NRC, Army Corps of Engineers and other federal, state and local authorities.
State Regulations
ELECTRIC
Virginia Power’s electric utility retail service is subject to regulation by the Virginia Commission and the North Carolina Commission.
Virginia Power holds certificates of public convenience and necessity which authorize it to maintain and operate its electric facilities now in operation and to sell electricity to customers. However, Virginia Power may not construct 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 Virginia Power’s transactions with affiliates, transfers of certain facilities and the issuance of certain securities.
Electric Regulation in Virginia
The enactment of the Regulation Act in 2007 significantly changed electric service regulation in Virginia by instituting a modified cost-of-service rate model. With respect to most classes of customers, the Regulation Act ended Virginia’s planned transition to retail competition for its electric supply service. Base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. The Virginia Commission reviews Virginia Power’s base rates, terms and conditions for generation and distribution services on a biennial basis in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a combined two-year historic test period, and the determination of Virginia Power’s authorized ROE prospectively. If, as a result of the earnings test review, the Virginia Commission determines that Virginia Power’s historic earnings for the two-year test period are more than 50 basis points above the authorized level, between 60% and 100% of earnings above this level must be shared with customers through a refund process. Under certain circumstances described in the Regulation Act, the Virginia Commission may also order a base rate increase or reduction during the biennial review. Circumstances where the Virginia Commission may order a base rate decrease include a determination by the Virginia Commission that Virginia Power has exceeded its authorized level of earnings by more than 50 basis points for two consecutive biennial review periods. Virginia Power’s authorized ROE can be set no lower than the average, for a three-year historic period, of the actual returns reported to the SEC by not less than a majority of comparable utilities within the Southeastern U.S., with certain limitations as described in the Regulation Act. Virginia Power’s ROE may be increased or decreased by up to 100 basis points based on operating performance criteria, or alternatively, will be increased by 50 basis points for compliance with Virginia’s RPS.
In addition, the Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation facilities or major unit modifications of existing facilities, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It provides for enhanced returns on capital expenditures relating to the construction or major modification of facilities that are nuclear-powered, clean coal/carbon capture compatible-powered, or renewable-powered, as well as conventional coal and combined-cycle combustion turbine facilities. Costs of fuel used for the generation of electricity, along with costs of purchased power, are recovered from customers through an annually approved fuel rider, as provided under a separate section of the Virginia Code. Decisions of the Virginia Commission may be appealed to the Supreme Court of Virginia.
If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings,
differ materially from Virginia Power’s expectations, it could adversely affect its results of operations, financial condition and cash flows.
2009 BASE RATE REVIEW
Pursuant to the Regulation Act, the Virginia Commission initiated a review of Virginia Power’s base rates, terms and conditions in 2009, including a review of Virginia Power’s earnings for test year 2008. In March 2010, the Virginia Commission issued the Virginia Settlement Approval Order, thus concluding the 2009 case and resolving open issues relating to Virginia Power’s base rates, fuel factor and Riders R, S, T, C1 and C2.
2011 BIENNIAL REVIEW
Pursuant to the Regulation Act and the Virginia Settlement Approval Order, in March 2011, Virginia Power submitted its base rate filing and accompanying schedules in support of the first biennial review of its base rates, terms and conditions, as well as of its earnings for the 2009 and 2010 test period. In November 2011, the Virginia Commission issued the Biennial Review Order.
In the 2011 Biennial Review Order, the Virginia Commission determined that Virginia Power earned an ROE of approximately 13.3% during the 2009 and 2010 combined test years, which exceeded the authorized ROE earnings band of 11.4% to 12.4% established in the Virginia Settlement Approval Order, resulting in an order that Virginia Power refund 60% of earnings above the upper end of the authorized ROE earnings band, or approximately $78 million, to its customers. The actual refund amount is expected to total approximately $81 million, taking into account refunds to be paid to certain non-jurisdictional customers pursuant to their customer contracts. The Virginia Commission also determined that Virginia Power’s new authorized ROE is 10.9%, inclusive of a performance incentive of 50 basis points for meeting RPS targets. Subject to the outcome of Virginia Power’s petition for rehearing or reconsideration described below, this ROE will serve as the ROE against which Virginia Power’s earned return will be compared for all or part of the test periods in the 2013 biennial review proceeding.
With respect to Virginia Power’s rate adjustment clauses, the Virginia Commission determined that, effective December 1, 2011, the ROE applicable to Riders C1 and C2 is 10.4% and the ROE applicable to Riders R and S is 11.4%, inclusive of a statutory enhancement of 100 basis points. The Virginia Commission also found that, as a result of its determination that credits will be applied to customers’ bills, the Regulation Act requires the combination of its existing Riders T, C1, and C2 with Virginia Power’s base costs, revenues and investments, and these Riders will thereafter be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings. Accordingly, the Virginia Commission directed that Virginia Power’s tariff filings pursuant to the Biennial Review Order reflect such combination. The Virginia Commission has initiated a proceeding to address further implementation of this directive. As a result of the Virginia Settlement Approval Order and the Regulation Act, Virginia Power’s base rates will otherwise remain unchanged through at least December 1, 2013.
In December 2011, Virginia Power filed a petition with the Virginia Commission seeking rehearing or reconsideration of the Biennial Review Order, to clarify whether the effective date of the
newly authorized base ROE is prospective from the date the Virginia Commission issued the Biennial Review Order or retrospective to January 1, 2011. Also, in December 2011, Virginia Power filed with the Virginia Commission a Notice of Appeal of the Biennial Review Order to the Supreme Court of Virginia.
See Note 14 to the Consolidated Financial Statements for additional information.
Electric Regulation in North Carolina
Virginia Power’s retail electric base rates in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes and the rules and procedures of the North Carolina Commission. North Carolina base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. If retail electric earnings exceed the returns established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, Virginia Power’s future earnings could be negatively impacted. Fuel rates are subject to revision under annual fuel cost adjustment proceedings. Virginia Power intends to file an application with the North Carolina Commission by March 30, 2012, to increase its base rates. See Note 14 to the Consolidated Financial Statements for additional information.
GAS
Dominion’s gas distribution services are regulated by the Ohio Commission and the West Virginia Commission.
Status of Competitive Retail Gas Services
Both of the states in which Dominion has gas distribution operations have considered legislation regarding a competitive deregulation of natural gas sales at the retail level.
Ohio-Ohio has not enacted legislation requiring supplier choice for residential or commercial natural gas consumers. However, in cooperation with the Ohio Commission, Dominion offers retail choice to residential and commercial customers. At December 31, 2011, approximately 1.0 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice program. In October 2006, East Ohio implemented a program approved by the Ohio Commission as a transitional step towards the improvement and expansion of the Energy Choice program, under which East Ohio entered into gas purchase contracts with selected suppliers at a fixed price above the NYMEX month-end settlement. This Standard Service Offer pricing mechanism replaced the traditional gas cost recovery rate with a monthly market price that eliminated the true-up adjustment, making it easier for customers to compare and switch to competitive suppliers if they so choose.
In June 2008, the Ohio Commission approved a settlement filed in response to East Ohio’s application seeking approval of Phase 2 of its plan to restructure its commodity service. Under that settlement, the existing Standard Service Offer program was continued through March 2009 with an update to the fixed rate adder to the NYMEX price. Starting in April 2009, East Ohio buys natural gas under the Standard Service Offer program for customers not eligible to participate in the Energy Choice program and places Energy Choice-eligible customers in a direct
retail relationship with selected suppliers, which is designated on the customers’ bills. Subject to the Ohio Commission’s approval, East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. East Ohio continues to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.
West Virginia-At this time, West Virginia has not enacted legislation to require customers to choose in the retail natural gas markets served by Hope. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customers a choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.
Rates
Dominion’s gas distribution subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate - Ohio and West Virginia. When necessary, Dominion’s gas distribution subsidiaries seek general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost of service by rate class. A straight-fixed-variable rate design, in which the majority of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohio’s customers pursuant to a 2008 rate case settlement. Base rates for Hope are designed primarily based on a rate design methodology in which the majority of operating costs are recovered through volumetric charges. In addition to general rate increases, Dominion’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective one-, three- or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses. The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure projects and certain other costs that vary widely over time; such costs are excluded from general base rates. See Note 14 to the Consolidated Financial Statements for additional information.
Federal Regulations
FEDERAL ENERGY REGULATORY COMMISSION
Electric
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominion’s merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion’s market-based sales tariffs authorized by FERC. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of
generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.
Dominion and Virginia Power are subject to FERC’s Standards of Conduct that govern conduct between transmission function employees of interstate gas and electricity transmission providers and the marketing function employees of their affiliates. The rule defines the scope of transmission and marketing-related functions that are covered by the standards and is designed to prevent transmission providers from giving their affiliates undue preferences.
Dominion and Virginia Power are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between Virginia Power and Dominion’s merchant plants without first receiving FERC authorization, (2) require the merchant plants and Virginia Power to conduct their wholesale power sales operations separately, and (3) prohibit Virginia Power from sharing market information with merchant plant operating personnel. The rules are designed to prohibit Virginia Power from giving the merchant plants a competitive advantage.
EPACT included provisions to create an ERO. The ERO is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC has certified NERC as the ERO and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of between $1 thousand and $1 million per day, and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
Dominion and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion and Virginia Power employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. Dominion and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cybersecurity programs as well as efforts to ensure appropriate facility ratings for Virginia Power’s transmission lines. In October 2010, NERC issued an industry alert identifying possible discrepancies between the design and actual field conditions of transmission facilities as a potential reliability issue. The alert recommends that entities review their current facilities rating methodology to verify that the methodology is based on actual field conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power is evaluating its transmission facilities for any discrepancies between design and actual field conditions. In addition, NERC has requested the industry to increase the number of assets subject to NERC reliability standards that are designated as critical assets, including cybersecurity assets. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the
expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
Gas
FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate natural gas company subsidiaries, including DTI, Cove Point and the Dominion South Pipeline Company, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.
Dominion’s interstate gas transmission and storage activities are generally conducted on an open access basis, in accordance with certificates, tariffs and service agreements on file with FERC.
Dominion is also subject to the Pipeline Safety Acts of 2002 and 2011, which mandate inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those located in areas of high-density population. Dominion has evaluated its natural gas transmission and storage properties, as required by the Department of Transportation regulations under these Acts, and has implemented a program of identification, testing and potential remediation activities. These activities are ongoing.
See Future Issues and Other Matters in MD&A and Note 14 to the Consolidated Financial Statements for additional information.
Environmental Regulations
Each of Dominion’s and Virginia Power’s operating segments faces substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Companies. If expenditures for pollution control technologies and associated operating costs are not recoverable from customers through regulated rates (in regulated jurisdictions) or market prices (in deregulated jurisdictions), those costs could adversely affect future results of operations and cash flows. Dominion and Virginia Power have applied for or obtained the necessary environmental permits for the operation of their facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance required to be discussed in this Item, see Environmental Matters in Future Issues and Other Matters in MD&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 23 to the Consolidated Financial Statements.
GLOBAL CLIMATE CHANGE
The national and international attention in recent years on GHG emissions and their relationship to climate change has resulted in federal, regional and state legislative or regulatory action in this
area. Dominion and Virginia Power support national climate change legislation that would provide a consistent, economy-wide approach to addressing this issue and are currently taking action to protect the environment and address climate change while meeting the future needs of their growing service territory. Dominion’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including climate change, and Dominion’s Board of Directors receives periodic updates on these matters. See Environmental Strategy above, Environmental Matters in Future Issues and Other Matters in MD&A and Note 23 to the Consolidated Financial Statements for information on climate change legislation and regulation, which information is incorporated herein by reference.
Nuclear Regulatory Commission
All aspects of the operation and maintenance of Dominion’s and Virginia Powers’ nuclear power stations, which are part of the Dominion 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, it could result in substantial increases in the cost of operating and maintaining Dominion’s and Virginia Power’s nuclear generating units. See Nuclear Matters in Future Issues and Other Matters in MD&A for further information.
The NRC also requires Dominion and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and the Companies are required by the NRC to be financially prepared. For information on decommissioning trusts, see Dominion Generation-Nuclear Decommissioning and Note 10 to the Consolidated Financial Statements. See Note 23 to the Consolidated Financial Statements for information on spent nuclear fuel.
Item 1A. Risk Factors
Dominion’s and Virginia Power’s businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond their control. A number of these factors have been identified 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 Item 7. MD&A.
Dominion’s and Virginia Power’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas, and affect the price of energy commodities. In addition, severe weather, including hurricanes and winter storms, can be destructive, causing outages and property damage that require incurring additional expenses. Droughts can result in reduced water levels that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely
affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level.
Dominion and Virginia Power are subject to complex governmental regulation that could adversely affect their results of operations. Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. These operations are also subject to legislation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that the business is conducted in accordance with applicable laws. However, new laws or regulations, the revision or reinterpretation of existing laws or regulations, or penalties imposed for non-compliance with existing laws or regulations may result in substantial expense.
Dominion and Virginia Power could be subject to penalties as a result of mandatory reliability standards. As a result of EPACT, owners and operators of generation facilities and bulk electric transmission systems, including Dominion and Virginia Power, are subject to mandatory reliability standards enacted by NERC and enforced by FERC. Compliance with the mandatory reliability standards may subject the Companies to higher operating costs and may result in increased capital expenditures. If either Dominion or Virginia Power is found not to be in compliance with the mandatory reliability standards it could be subject to remediation costs, as well as sanctions, including substantial monetary penalties.
Dominion’s and Virginia Power’s costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws, including laws and regulations designed to address global climate change, air quality, coal combustion by-products, cooling water and other matters could make certain of the Companies’ generation facilities uneconomical to maintain or operate. Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and Dominion and Virginia Power expect that they will remain significant in the future.
Existing environmental laws and regulations may be revised and/or new laws may be adopted or become applicable to Dominion or Virginia Power. The EPA is expected to issue additional regulations with respect to air quality under the CAA, including revised NAAQS and regulations governing the emissions of GHGs from electric generating units. Risks relating to potential regulation of GHG emissions are discussed below. Dominion and
Virginia Power also expect additional federal water and waste regulations, including regulations concerning cooling water intake structures and coal combustion by-product handling and disposal practices that are expected to be applicable to at least some of its generating facilities.
Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new environmental rules or regulations. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liability on all responsible parties. However, such expenditures, if material, could make the Companies’ generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.
If additional federal and/or state requirements are imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements, such requirements may result in compliance costs that alone or in combination could make some of Dominion’s or Virginia Power’s electric generation units or natural gas facilities uneconomical to maintain or operate. The EPA, environmental advocacy groups, other organizations and some state and other federal agencies are focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. Dominion and Virginia Power expect that additional EPA regulations, and possibly additional state legislation and/or regulations, may be issued resulting in the imposition of additional limitations on GHG emissions or requiring efficiency improvements from fossil fuel-fired electric generating units.
There are also potential impacts on Dominion’s natural gas businesses as federal or state GHG legislation or regulations may require GHG emission reductions from the natural gas sector and could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products. Several regions of the U.S. have moved forward with GHG emission regulations including regions where Dominion has operations. For example, Massachusetts and Rhode Island have implemented regulations requiring reductions in CO2 emissions through RGGI, a cap and trade program covering CO2 emissions from power plants in the Northeast, which affects several of Dominion’s facilities.
Compliance with GHG emission reduction requirements may require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon capture and storage technology, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower emitting generation facilities. The cost of compliance with GHG emission legislation and/or regulation is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon capture and storage technology, and the selected compliance alternatives. The Companies cannot estimate the aggregate effect of such requirements on their results of operations, financial condition or their customers. However,
such expenditures, if material, could make the Companies’ generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.
The rates of Virginia Power are subject to regulatory review. In the Biennial Review Order, the Virginia Commission determined that Virginia Power’s actual ROE during the 2009 and 2010 combined test years exceeded the upper end of the authorized ROE earnings band for that period, resulting in an order that Virginia Power refund approximately $78 million to its customers. The Virginia Commission also determined that Virginia Power’s new authorized ROE is 10.9%, inclusive of a performance incentive of 50 basis points for meeting certain renewable energy targets. Subject to the outcome of the petition for rehearing or reconsideration described below, this ROE will serve as the ROE against which Virginia Power’s earned return will be compared for all or part of the test periods in the 2013 biennial review proceeding. In December 2011, Virginia Power filed a petition with the Virginia Commission seeking a rehearing or reconsideration of the Biennial Review Order to clarify whether the effective date of the newly authorized ROE is the date the Virginia Commission issued the 2011 Biennial Review Order or January 1, 2011. If the Virginia Commission orders that the effective date of the newly authorized ROE is January 1, 2011, such effective date may adversely affect the outcome of the earnings test in the 2013 biennial review. In addition, Virginia Power’s base rates are subject to reduction if the Virginia Commission concludes, in the 2013 biennial review, that Virginia Power’s actual ROE during the test period exceeded the upper end of the authorized ROE earnings band for that period, under circumstances described in the Regulation Act. The Virginia Commission could also order Virginia Power to refund to customers 60% of any such excess earnings for the 2011-2012 earnings test period. The Virginia Commission may alternatively order Virginia Power to refund up to 100% of earnings that exceed the earnings band in a biennial review if it finds that Virginia Power’s total aggregate regulated rates have exceeded annual increases in the U.S. Consumer Price Index, as described in the Regulation Act.
In the 2011 Biennial Review Order, as a result of the Virginia Commission’s determination that credits will be applied to customers’ bills, the Virginia Commission, as required by the Regulation Act, directed Virginia Power to combine its existing Riders T, C1, and C2 with Virginia Power’s base costs, revenues and investments, and to file revised tariffs reflecting such combination. These existing Riders will thereafter be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings. The Virginia Commission has initiated a proceeding to address how this combination will be implemented. Depending on how the Virginia Commission orders the combination of existing Riders T, C1 and C2 to be effected, Virginia Power may be required to discontinue deferral accounting and could potentially not receive full recovery of costs associated with these existing riders. At this time, Virginia Power is not able to estimate the impact, if any, of the outcome of these proceedings.
The rates of Virginia Power’s electric transmission operations and Dominion’s gas transmission and distribution operations are subject to regulatory review. Revenue provided by Virginia Power’s electric
transmission operations and Dominion’s gas transmission and distribution operations is based primarily on rates approved by federal and state regulatory agencies. The profitability of these businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.
Virginia Power’s wholesale charges for electric transmission service are adjusted on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism, Virginia Power’s wholesale electric transmission cost of service is estimated and thereafter adjusted as appropriate to reflect actual costs allocated to Virginia Power by PJM. These wholesale rates are subject to FERC review and prospective adjustment in the event that customers and/or interested state commissions file a complaint with FERC and are able to demonstrate that Virginia Power’s wholesale revenue requirement is no longer just and reasonable.
Similarly, various rates and charges assessed by Dominion’s gas transmission businesses are subject to review by FERC. In addition, Dominion’s gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate.
Risks arising from the reliability of electric generation, transmission and distribution equipment, supply chain disruptions or personnel issues could result in lost revenues and increased expenses, including higher maintenance costs. Operation of the Companies’ generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents, earthquakes and other natural disasters can disrupt generation, transmission and distribution facilities. Because Virginia Power’s transmission facilities are interconnected with those of third parties, the operation of its facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
Operation of the Companies’ generation facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less energy or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement energy and capacity from third parties in the open market to satisfy forward energy and capacity obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.
Dominion’s merchant power business is operating in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion’s merchant power business depends upon favorable market conditions including the ability to
purchase and sell power at prices sufficient to cover its operating costs. Dominion operates in active wholesale markets that expose it to price volatility for electricity and fuel as well as the credit risk of counterparties. Dominion attempts to manage its price risk by entering into hedging transactions, including short-term and long-term fixed price sales and purchase contracts.
In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion does not enter into long-term power purchase agreements or otherwise effectively hedge its output, these changes in market prices could adversely affect its financial results.
Dominion purchases fuel under a variety of terms, including long-term and short-term contracts and spot market purchases. Dominion is exposed to fuel cost volatility for the portion of its fuel obtained through short-term contracts or on the spot market. Fuel prices can be volatile and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs, thus adversely impacting Dominion’s financial results.
Dominion’s and Virginia Power’s generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. Dominion’s and Virginia Power’s generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets in PJM, MISO and ISO-NE depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize PJM, MISO and ISO-NE to make changes in market design. FERC also periodically reviews Dominion’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets, Dominion’s or Virginia Power’s authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of Dominion’s or Virginia Power’s generation business.
War, acts and threats of terrorism, natural disaster and other significant events could adversely affect Dominion’s and Virginia Power’s operations. Dominion and Virginia Power cannot predict the impact that any future terrorist attacks may have on the energy industry in general, or on the Companies’ business in particular. Any retaliatory military strikes or sustained military campaign may affect the Companies’ operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets. In addition, infrastructure facilities, such as electric generation, electric and gas transmission and distribution facilities could be direct targets of, or indirect casualties of, an act of terror. Furthermore, the physical or cybersecurity compromise of the Companies’ facilities could adversely affect the Companies’ ability to manage these facilities effectively. Instability in financial mar-
kets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy and increase the cost of insurance coverage. This could negatively impact the Companies’ results of operations and financial condition.
Dominion and Virginia Power have substantial ownership interests in and operate nuclear generating units; as a result, each may incur substantial costs and liabilities. Dominion’s and Virginia Power’s nuclear facilities are subject to operational, environmental, health and financial risks such as the on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. Dominion and Virginia Power maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If Dominion and Virginia Power are not allowed to recover the additional costs incurred through insurance, or in the case of Virginia Power through regulatory mechanisms, their results of operations could be negatively impacted.
Dominion’s and Virginia Power’s nuclear facilities are also subject to complex government regulation which could negatively impact their results of operations. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending on its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require Dominion and Virginia Power to make substantial expenditures at their nuclear plants. In addition, although the Companies have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could materially and adversely affect their results of operations and/or financial condition. A major incident at a nuclear facility anywhere in the world, such as the nuclear events in Japan in 2011, could cause the NRC to adopt increased safety regulations or otherwise limit or restrict the operation or licensing of domestic nuclear units.
The use of derivative instruments could result in financial losses and liquidity constraints. Dominion and Virginia Power use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity and financial market risks. In addition, Dominion purchases and sells commodity-based contracts primarily in the natural gas market for trading purposes. The Companies could recognize financial losses on these contracts, including as a result of volatility in the market values of the underlying commodities, if a counterparty fails to perform under a contract or upon the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these transactions. 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 under-
lying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
The use of derivatives to hedge future sales may limit the benefit Dominion would otherwise receive from increases in commodity prices. These hedge arrangements generally include collateral requirements that require Dominion to deposit funds or post letters of credit with counterparties, financial intermediaries or clearinghouses to cover the fair value of covered contracts in excess of agreed upon credit limits. For instance, when commodity prices rise to levels substantially higher than the levels where it has hedged future sales, Dominion may be required to use a material portion of its available liquidity or obtain additional liquidity to cover these collateral requirements. In some circumstances, this could have a compounding effect on Dominion’s financial liquidity and results of operations. In addition, the availability or security of the collateral delivered by Dominion may be adversely affected by the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these types of transactions.
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 between the location and/or specifications of the derivative hedging instrument and the hedged item and could adversely affect Dominion’s results of operations.
Dominion’s and Virginia Power’s operations in regards to these transactions are subject to multiple market risks including market liquidity, price volatility, credit strength of the Companies’ counterparties and the financial condition of the financial intermediaries, exchanges and clearinghouses used for the types of transactions. These market risks are beyond the Companies’ control and could adversely affect their results of operations, liquidity and future growth.
The Dodd-Frank Act, which was enacted into law in July 2010, includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Final rules for the over-the-counter derivatives-related provisions of the Dodd-Frank Act, including the clearing, exchange trading and capital and margin requirements, will be established through the on-going rulemaking process of each applicable regulator, including the CFTC and SEC. In June 2011, both the CFTC and SEC confirmed that they would not complete the required rulemakings by the July 2011 deadline under the Dodd-Frank Act. Each agency has granted temporary relief from most derivative-related provisions of the Dodd-Frank Act until the effective date of the applicable rules. Currently, the CFTC’s temporary relief would expire no later than July 16, 2012, if not extended. If, as a result of the rulemaking process, Dominion’s or Virginia Power’s derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs for their derivative activities, including from higher margin requirements. In addition, implementation of, and compliance with, the over-the-counter derivatives provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in increased costs related to the Companies’ derivative activities.
Dominion depends on third parties to produce the natural gas it gathers and processes, and the NGLs it fractionates at its facilities. A reduction in these quantities could reduce Dominion’s revenues.
Dominion obtains its supply of natural gas and NGLs from numerous third-party producers. Such producers are under no obligation to deliver a specific quantity of natural gas or NGLs to Dominion’s facilities, although the producers that have contracted to supply natural gas to Dominion’s natural gas processing and fractionation facility under development in Natrium, West Virginia will generally be subject to contractual minimum fee payments. If producers were to decrease the supply of natural gas or NGLs to Dominion’s systems and facilities for any reason, Dominion could experience lower revenues to the extent it is unable to replace the lost volumes on similar terms.
Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. Dominion and Virginia Power are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Such defaults by customers, suppliers or other third parties may adversely affect the Companies’ financial results.
Dominion and Virginia Power may not complete plant construction or expansion projects that they commence, or they may complete projects on materially different terms or timing than initially anticipated and they may not be able to achieve the intended benefits of any such project, if completed. Several plant construction and expansion projects have been announced and additional projects may be considered in the future. Projects may not be able to be completed on time as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of their counterparties or vendors, or other factors beyond their control. Even if plant construction and expansion projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of Dominion and Virginia Power following the projects may not meet expectations. Additionally, Dominion and Virginia Power may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the plant construction and expansion projects.
Energy conservation could negatively impact Dominion’s and Virginia Power’s financial results. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices, including lighting and electric heat pumps, could lead to declines in per capita energy consumption. To the extent conservation results in reduced energy demand or significantly slowed growth in demand, the value of the Companies’ business activities could be adversely impacted.
An inability to access financial markets could adversely affect the execution of Dominion’s and Virginia Power’s business plans. Dominion and Virginia Power rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for capital expenditures, normal working
capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of Dominion’s and Virginia Power’s control could increase their cost of borrowing or restrict their ability to access one or more financial markets. Further market disruptions could stem from delays in the current economic recovery, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, or the failure of financial institutions on which the Companies rely. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.
Market performance and other changes may decrease the value of decommissioning trust funds and benefit plan assets or increase Dominion’s liabilities, which could then require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trusts to satisfy future obligations to decommission Dominion’s nuclear plants and under its pension and other postretirement benefit plans. Dominion has significant obligations in these areas and holds significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates.
With respect to decommissioning trust funds, a decline in the market value of these assets may increase the funding requirements of the obligations to decommission Dominion’s nuclear plants or require additional NRC-approved funding assurance.
A decline in the market value of the assets held in trusts to satisfy future obligations under Dominion’s pension and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates affect the liabilities under Dominion’s pension and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans.
If the decommissioning trust funds and benefit plan assets are negatively impacted by market fluctuations or other factors, Dominion’s results of operations, financial condition and/or cash flows could be negatively affected.
Changing rating agency requirements could negatively affect Dominion’s and Virginia Power’s growth and business strategy. In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, Dominion and Virginia Power may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in Dominion’s credit ratings or the credit ratings of Virginia Power could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require Dominion to post additional collateral in connection with some of its price risk management activities.
Potential changes in accounting practices may adversely affect Dominion’s and Virginia Power’s financial results. Dominion and Virginia Power cannot predict the impact that future changes in accounting standards or practices may have on public companies
in general, the energy industry or their operations specifically. New accounting standards could be issued that could change the way they record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect 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 Dominion’s and Virginia Power’s operations. Dominion’s and Virginia Power’s business strategy is dependent on their 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 their business and future operating results.
Hostile cyber intrusions could severely impair Dominion’s and Virginia Power’s operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on Dominion’s and Virginia Power’s business. The Companies own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run the Companies’ facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or the Companies’ operations could view the Companies’ computer systems, software or networks as attractive targets for cyber attack. In addition, the Companies’ business requires that they collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.
A successful cyber attack on the systems that control the Companies’ electric generation, electric or gas transmission or distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. The Companies maintain property and casualty insurance that may cover certain damage caused by potential cybersecurity incidents, however, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect the Companies business, financial condition and results of operations.
In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, Dominion and Virginia Power are subject to mandatory cybersecurity regulatory requirements. However, cyber threats continue to evolve and adapt, and, as a result, there is a risk that the Companies could experience a successful cyber attack despite their current security posture and regulatory compliance efforts.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
As of December 31, 2011, Dominion owned its principal executive office and three other corporate offices, all located in Richmond, Virginia. Dominion also leases corporate offices in other cities in which its subsidiaries operate. Virginia Power shares its principal office in Richmond, Virginia, which is owned by Dominion. In addition, Virginia Power’s DVP and Generation segments share certain leased buildings and equipment. See Item 1. Business for additional information about each segment’s principal properties, which information is incorporated herein by reference.
Dominion’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described here and in Item 1. Business.
Substantially all of Virginia Power’s property is subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2011; however, by leaving the indenture open, Virginia Power retains the flexibility to issue mortgage bonds in the future. Certain of Dominion’s merchant generation facilities are also subject to liens.
POWER GENERATION
Dominion and Virginia Power generate electricity for sale on a wholesale and a retail level. The Companies supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2011, Dominion Generation’s total utility and merchant generating capacity was 28,142 MW.
The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2011:
VIRGINIA POWER UTILITY GENERATION
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) Certain coal-fired units are expected to be retired at Chesapeake and Yorktown during 2015 and 2016 as a result of the issuance of the MATS rule.
(2) Planned to convert to gas subject to Virginia City Hybrid Energy Center entering service and necessary approvals.
(3) Facility has been placed into cold reserve status, but can be restarted within a reasonably short period if necessary. North Branch will be permanently retired upon commencement of commercial operations at Warren County.
(4) Seeking regulatory approval to convert to biomass.
(5) Excludes 50% undivided interest owned by ODEC.
(6) Excludes 11.6% undivided interest owned by ODEC.
(7) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.
DOMINION MERCHANT GENERATION
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) Subject to a lien securing the facility’s debt. Also see Note 18 to the Consolidated Financial Statements for additional information on liens related to Kincaid and Fairless.
(2) State Line will be retired in the first quarter of 2012.
(3) Two coal-fired units at Salem Harbor with capacity of 163 MW were retired at the end of 2011 and the Company plans to retire the remaining units on June 1, 2014.
(4) In the first quarter of 2011, Dominion decided to pursue the sale of Kewaunee.
(5) Includes generating units that Dominion operates under leasing arrangements.
(6) Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation.
(7) Excludes 50% membership interest owned by J. POWER Elwood, LLC.
(8) Excludes 50% membership interest owned by BP.
(9) Excludes 50% membership interest owned by Shell.
Item 3. Legal Proceedings
From time to time, Dominion and Virginia Power 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 the Companies, or permits issued by various local, state and/or 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, the Companies and their subsidiaries are involved in various legal proceedings.
In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, New Source Performance Standards, and Title V permit program and the stations’ respective State Implementation Plans. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the CAA.
Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The CAA authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. In addition to any such penalties that may be awarded, an adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time. Such expenditures could affect future results of operations, cash flows, and financial condition. Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.
See Notes 14 and 23 to the Consolidated Financial Statements and Future Issues and Other Matters in MD&A, which information is incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which the Companies are a party.
Item 4. Mine Safety Disclosures
Not applicable.
Executive Officers of Dominion
Information concerning the executive officers of Dominion, each of whom is elected annually, is as follows:
Name and Age
Business Experience Past Five Years(1)
Thomas F. Farrell II (57)
Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date; Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; Chairman of the Board of Directors, President and CEO of CNG from January 2006 to June 2007; Director of Dominion from March 2005 to April 2007.
Mark F. McGettrick (54)
Executive Vice President and CFO of Dominion and Virginia Power from June 2009 to date; Executive Vice President of Dominion from April 2006 to May 2009; President and COO-Generation of Virginia Power from February 2006 to May 2009.
Paul D. Koonce (52)
Executive Vice President of Dominion from April 2006 to date; President and COO of Virginia Power from June 2009 to date; President and COO-Energy of Virginia Power from February 2006 to September 2007.
David A. Christian (57)
Executive Vice President of Dominion from May 2011 to date; President and COO of Virginia Power from June 2009 to date; President and CNO of Virginia Power from October 2007 to May 2009; Senior Vice President-Nuclear Operations and CNO of Virginia Power from April 2000 to September 2007.
David A. Heacock (54)
President and CNO of Virginia Power from June 2009 to date; Senior Vice President of Dominion and President and COO-DVP of Virginia Power from June 2008 to May 2009; Senior Vice President-DVP of Virginia Power from October 2007 to May 2008; Senior Vice President-Fossil & Hydro of Virginia Power from April 2005 to September 2007.
Gary L. Sypolt (58)
Executive Vice President of Dominion from May 2011 to date; President of DTI from June 2009 to date; President-Transmission of DTI from January 2003 to May 2009; President and COO-Transmission of Virginia Power from February 2006 to September 2007.
Robert M. Blue (44)
Senior Vice President-Law, Public Policy and Environment of Dominion, Virginia Power and DRS from January 2011 to date; Senior Vice President-Public Policy and Environment of Dominion and DRS from February 2010 to December 2010; Senior Vice President-Public Policy and Corporate Communications of Dominion and DRS from May 2008 to January 2010; Vice President-State and Federal Affairs of DRS from September 2006 to May 2008.
Steven A. Rogers (50)
Senior Vice President and Chief Administrative Officer of Dominion and President and Chief Administrative Officer of DRS from October 2007 to date; Senior Vice President and CAO of Dominion and Virginia Power from January 2007 to September 2007 and CNG from January 2007 to June 2007.
Ashwini Sawhney (62)
Vice President-Accounting and Controller (CAO) of Dominion from May 2010 to date; Vice President and Controller (CAO) of Dominion from July 2009 to May 2010; Vice President-Accounting of Virginia Power from April 2006 to date; Vice President and Controller of Dominion from April 2007 to June 2009; Vice President-Accounting and Controller of Dominion from January 2007 to April 2007 and of CNG from January 2007 to June 2007.
(1) Any service listed for Virginia Power, CNG, DTI, DEI and DRS reflects service at a subsidiary of Dominion.
Part II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Dominion
Dominion’s common stock is listed on the NYSE. At January 31, 2012, there were approximately 142,000 record holders of Dominion’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion Direct. Discussions of expected dividend payments and restrictions on Dominion’s payment of dividends required by this Item are contained in Liquidity and Capital Resources in Item 7. MD&A and Notes 18 and 21 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 2011 and 2010. Quarterly information concerning stock prices and dividends is disclosed in Note 27 to the Consolidated Financial Statements, which information is incorporated herein by reference.
The following table presents certain information with respect to Dominion’s common stock repurchases during the fourth quarter of 2011.
DOMINION PURCHASES OF EQUITY SECURITIES
(1) In October, November and December 2011, 1,284 shares, 361 shares and 294 shares, respectively, were tendered by employees to satisfy tax withholding obligations on vested restricted stock.
(2) Represents the weighted-average price paid per share.
(3) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion Board of Directors was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion.
Virginia Power
There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion. Restrictions on Virginia Power’s payment of dividends are discussed in Dividend Restrictions in Item 7. MD&A and Note 21 to the Consolidated Financial Statements. Virginia Power paid quarterly cash dividends on its common stock as follows:
Item 6. Selected Financial Data
DOMINION
(1) Amounts attributable to Dominion’s common shareholders.
2011 results include a $139 million after-tax charge reflecting generation plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units and a $59 million after-tax charge reflecting restoration costs associated with damage caused by Hurricane Irene.
2010 results include a $1.4 billion after-tax net income benefit from the sale of substantially all of Dominion’s Appalachian E&P operations, net of charges related to the divestiture and a $206 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, as discussed in Notes 4 and 23 to the Consolidated Financial Statements, respectively. Also in 2010, Dominion recorded $127 million of after-tax impairment charges at certain merchant generation facilities, as discussed in Note 7 to the Consolidated Financial Statements. The loss from discontinued operations in 2010 includes a $140 million after-tax loss on the sale of Peoples.
2009 results include a $435 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings discussed in Note 14 to the Consolidated Financial Statements. Also in 2009, Dominion recorded a $281 million after-tax ceiling test impairment charge related to the carrying value of its Appalachian E&P properties.
2008 results include $109 million of after-tax charges reflecting other-than-temporary declines in the fair value of certain securities held as investments in nuclear decommissioning trusts. In addition, income from discontinued operations in 2008 includes a $120 million after-tax benefit due to the reversal of deferred tax liabilities associated with the sale of Peoples.
2007 results include a $1.5 billion after-tax benefit from the disposition of Dominion’s non-Appalachian E&P operations and a $252 million after-tax impairment charge associated with the sale of Dresden. Also in 2007, Dominion recorded a $137 million after-tax charge resulting from the termination of the long-term power sales agreement associated with State Line. In addition, the reapplication of accounting guidance for cost-based rate regulation to the Virginia jurisdiction of Virginia Power’s generation operations in 2007 resulted in a $158 million after-tax extraordinary charge.
VIRGINIA POWER
2011 results include a $139 million after-tax charge reflecting generation plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired generating units and a $59 million after-tax charge reflecting restoration costs associated with damage caused by Hurricane Irene.
2010 results include a $123 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, discussed in Note 23 to the Consolidated Financial Statements.
2009 results include a $427 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings discussed in Note 14 to the Consolidated Financial Statements.
2007 results reflect the reapplication of accounting guidance for cost-based rate regulation to the Virginia jurisdiction of Virginia Power’s generation operations, which resulted in a $158 million after-tax extraordinary charge.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
MD&A discusses Dominion’s and Virginia Power’s results of operations and general financial condition. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data.
CONTENTS OF MD&A
MD&A consists of the following information:

Forward-Looking Statements

Accounting Matters

Dominion

Results of Operations

Segment Results of Operations

Virginia Power

Results of Operations

Segment Results of Operations

Liquidity and Capital Resources

Future Issues and Other Matters
FORWARD-LOOKING STATEMENTS
This report contains statements concerning Dominion’s and Virginia Power’s 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,” “continue,” “target” or other similar words.
Dominion and Virginia Power 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:

Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;

Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, and earthquakes that can cause outages and property damage to facilities;

Federal, state and local legislative and regulatory developments;

Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances;

Cost of environmental compliance, including those costs related to climate change;

Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;

Unplanned outages of the Companies’ facilities;

Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Dominion’s and Virginia Power’s liquidity position and the underlying value of their assets;

Counterparty credit and performance risk;

Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;

Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;

Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion;

Fluctuations in interest rates;

Changes in federal and state tax laws and regulations;

Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;

Changes in financial or regulatory accounting principles or policies imposed by governing bodies;

Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;

The risks of operating businesses in regulated industries that are subject to changing regulatory structures;

Receipt of approvals for and timing of closing dates for acquisitions and divestitures;

Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, pricing rules and rules involving revenue calculations and new and evolving capacity models;

Political and economic conditions, including inflation and deflation;

Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;

Industrial, commercial and residential growth or decline in the Companies’ service areas and changes in customer growth or usage patterns, including as a result of energy conservation programs;

Additional competition in electric markets in which Dominion’s merchant generation facilities operate;

Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;

Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion;

Timing and receipt of regulatory approvals necessary for planned construction or expansion projects;

The inability to complete planned construction projects within the terms and time frames initially anticipated; and

Adverse outcomes in litigation matters.
Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.
ACCOUNTING MATTERS
Critical Accounting Policies and Estimates
Dominion and Virginia Power 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 their financial condition or results of operations under different conditions or using different assumptions. Dominion and Virginia Power have discussed the
development, selection and disclosure of each of these policies with the Audit Committees of their Boards of Directors. Virginia Power’s Board of Directors also serves as its Audit Committee.
ACCOUNTING FOR REGULATED OPERATIONS
The accounting for Virginia Power’s regulated electric and Dominion’s regulated gas operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs are deferred as regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.
The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions 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. See Notes 13 and 14 to the Consolidated Financial Statements for additional information.
ASSET RETIREMENT OBLIGATIONS
Dominion and Virginia Power recognize liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists and the ARO can be reasonably estimated. These 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, the Companies estimate the fair value of their AROs using present value techniques, in which they 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. The impact on measurements of new AROs or remeasurements of existing AROs, using different cost escalation rates in the future, may be significant. When the Companies revise any assumptions used to calculate the fair value of existing AROs, they adjust the carrying amount of both the ARO liability and the related long-lived asset. The Companies accrete the ARO liability to reflect the passage of time.
In 2011, 2010 and 2009, Dominion recognized $84 million, $85 million and $89 million, respectively, of accretion, and expects to recognize $75 million in 2012. In 2011, 2010 and 2009, Virginia Power recognized $36 million, $35 million and $35 million, respectively, of accretion, and expects to recognize $35 million in 2012. Virginia Power records accretion and depreciation associated with utility nuclear decommissioning AROs as an adjustment to its regulatory liability for nuclear decommissioning.
A significant portion of the Companies’ AROs relates to the future decommissioning of Dominion’s merchant and Virginia Power’s utility nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2011, Dominion’s nuclear decommissioning AROs totaled $1.2 billion, representing approximately 83% of its total AROs. At December 31, 2011, Virginia Power’s nuclear decommissioning AROs totaled $559 million, representing approximately 89% of its 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 the Companies’ nuclear decommissioning obligations.
The Companies 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 their nuclear plants. 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, the Companies’ cost estimates include cost escalation rates that are applied to the base year costs. The Companies 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 nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be a critical assumption.
In December 2011, Dominion recorded a decrease of $290 million in the nuclear decommissioning AROs for its units. Virginia Power recorded a decrease of $95 million in the nuclear decommissioning AROs for its units. The ARO revision was driven by a reduction in anticipated future decommissioning costs due to the expected future recovery from the DOE of certain spent fuel costs based on the Companies’ contracts with the DOE for disposal of spent nuclear fuel, as well as updated escalation rates. In 2009, as a result of updated decommissioning cost studies and applicable escalation rates, Dominion recorded a decrease of $309 million in the nuclear decommissioning AROs of its units, including a $103 million ($62 million after-tax) reduction in other operations and maintenance expense due to a downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service. Virginia Power recorded a decrease of $119 million in the nuclear decommissioning AROs for its units.
INCOME TAXES
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. 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.
Given the uncertainty and judgment involved in the determination and filing of income taxes, there are 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
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
examined by tax authorities with full knowledge of all relevant information. At December 31, 2011, Dominion had $347 million and Virginia Power had $114 million of unrecognized tax benefits.
Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power evaluate quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for 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. The Companies establish a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2011, Dominion had established $96 million of valuation allowances and Virginia Power had no valuation allowances.
ACCOUNTING FOR DERIVATIVE CONTRACTS AND OTHER INSTRUMENTS AT FAIR VALUE
Dominion and Virginia Power use derivative contracts such as futures, swaps, forwards, options and FTRs to manage commodity and financial market risks of their business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies. The majority of investments held in Dominion’s and Virginia Power’s nuclear decommissioning and Dominion’s rabbi and benefit plan trust funds are also subject to fair value accounting. See Notes 7 and 22 to the Consolidated Financial Statements for further information on these fair value measurements.
Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, the Companies consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, the Companies must estimate prices based on available historical and near-term future price information and use of statistical methods, including regression analysis, that reflect their market assumptions.
The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING
As of December 31, 2011, Dominion reported $3.1 billion of goodwill in its Consolidated Balance Sheet. A significant portion resulted from the acquisition of the former CNG in 2000.
In April of each year, Dominion tests its goodwill for potential impairment, and performs additional tests more frequently if
an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2011, 2010 and 2009 annual tests and any interim tests did not result in the recognition of any goodwill impairment.
In general, Dominion estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. For Dominion’s Appalachian E&P operations and Peoples and Hope operations, negotiated sales prices were used as fair value for the tests conducted in 2010 and 2009. Fair value estimates are dependent on subjective factors such as Dominion’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present. See Note 12 to the Consolidated Financial Statements for additional information.
USE OF ESTIMATES IN LONG-LIVED ASSET IMPAIRMENT TESTING
Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing and the selection of an appropriate discount rate. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset, including future production and sales levels, and expected fluctuations of prices of commodities sold and consumed. See Note 7 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets.
EMPLOYEE BENEFIT PLANS
Dominion sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit obligations and the anticipated rate of increase in healthcare costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between Dominion’s assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.
The expected long-term rates of return on plan assets, discount rates and healthcare cost trend rates are critical assumptions. Dominion determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:

Expected inflation and risk-free interest rate assumptions;

Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;

Expected future risk premiums, asset volatilities and correlations;

Forward-looking return expectations derived from the yield on long-term bonds and the price earnings ratios of major stock market indices; and

Investment allocation of plan assets. The strategic target asset allocation for Dominion’s pension funds is 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments, such as private equity investments.
Strategic investment policies are established for Dominion’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include those mentioned above such as employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns.
Dominion develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions. Dominion calculated its pension cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2011, 2010 and 2009. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 7.75% for 2011, 2010 and 2009. The rate used in
calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets.
Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost were 5.9% in 2011 and 6.60% in 2010 and 2009. Dominion selected a discount rate of 5.50% for determining its December 31, 2011 projected pension and other postretirement benefit obligations.
Dominion establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected, and demographics of plan participants. Dominion’s healthcare cost trend rate assumption as of December 31, 2011 is 7% and is expected to gradually decrease to 4.60% by 2060 and continue at that rate for years thereafter.
The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed, while holding all other assumptions constant:
In addition to the effects on cost, at December 31, 2011, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $163 million and its accumulated postretirement benefit obligation by $43 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $174 million. See Note 22 to the Consolidated Financial Statements for additional information.
REVENUE RECOGNITION-UNBILLED REVENUE
Virginia Power recognizes and records 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 amount 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. Virginia Power’s customer receivables included $360 million and $397 million of accrued unbilled revenue at December 31, 2011 and 2010, 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 and other factors, which are the basis for the estimates of unbilled revenues, could have a significant effect on the calculation and therefore on Virginia Power’s results of operations and financial condition.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Other
ACCOUNTING STANDARDS AND POLICIES
During 2009, Dominion and Virginia Power were required to adopt several new accounting standards, which are discussed in Note 3 to the Consolidated Financial Statements.
DOMINION
RESULTS OF OPERATIONS
Presented below is a summary of Dominion’s consolidated results:
Overview
VS. 2010
Net income attributable to Dominion decreased by 50%. Unfavorable drivers include the absence of a gain on the sale of Dominion’s Appalachian E&P operations, lower margins from merchant generation operations, and the impact of less favorable weather, including Hurricane Irene, on electric utility operations. Favorable drivers include the absence of charges related to a workforce reduction program and the absence of a loss on the sale of Peoples, and higher earnings from rate adjustment clauses.
2010 VS. 2009
Net income attributable to Dominion increased by 118%. Favorable drivers include a gain on the sale of Dominion’s Appalachian E&P operations, lower ceiling test impairment charges related to these properties, the absence of a charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings and the impact of favorable weather on electric utility operations. Unfavorable drivers include charges related to a workforce reduction program, a loss on the sale of Peoples, lower margins from merchant generation operations and impairment charges related to certain merchant generation facilities.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion’s results of operations:
An analysis of Dominion’s results of operations follows:
2011 VS. 2010
Net Revenue decreased 7%, primarily reflecting:

A $519 million decrease from merchant generation operations, primarily due to a decrease in realized prices ($347 million) and lower generation ($163 million); and

A $125 million decrease reflecting the sale of substantially all of Dominion’s Appalachian E&P operations in April 2010.
These decreases were partially offset by:

A $32 million increase from Dominion’s gas transmission business primarily related to an increase in revenue from NGLs;

A $28 million increase in producer services primarily related to higher physical margins and favorable price changes on economic hedging positions, all associated with natural gas aggregation, marketing and trading activities;

A $13 million increase from electric utility operations, primarily reflecting:

The impact of rate adjustment clauses ($169 million); and

A decrease in net capacity expenses ($44 million); partially offset by

The impact ($120 million) of a decrease in sales to retail customers, primarily due to a decrease in heating and cooling degree days ($220 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($100 million); and

A decrease due to a charge based on the Biennial Review Order to refund revenues to customers ($81 million).
Other operations and maintenance decreased 6%, primarily reflecting:

A $441 million decrease in salaries, wages and benefits primarily related to a 2010 workforce reduction program; partially offset by

A $96 million increase due to restoration costs associated with damage caused by Hurricane Irene; and

An $89 million net increase in impairment charges related to certain utility and merchant coal-fired generating units.
Gain on sale of Appalachian E&P operations reflects a gain on the sale of these operations, as described in Note 4 to the Consolidated Financial Statements.
Interest and related charges increased 4%, primarily due to the absence of a benefit recorded in 2010 resulting from the discontinuance of hedge accounting for certain interest rate derivatives ($73 million) and an increase in debt issuances in 2011 ($18 million), partially offset by the recognition of hedging gains that had previously been deferred as regulatory liabilities as a result of the Biennial Review Order ($50 million).
Income tax expense decreased $1.3 billion, primarily reflecting lower federal and state taxes largely due to the absence of a gain from the sale of Dominion’s Appalachian E&P operations recorded in 2010.
Loss from discontinued operations reflects the sale of Peoples in 2010.
VS. 2009
Net Revenue increased 8%, primarily reflecting:

A $1.1 billion increase from electric utility operations, primarily reflecting:

The absence of a charge for the settlement of Virginia Power’s 2009 base rate case proceedings ($570 million);

The impact of rate adjustment clauses ($279 million);

An increase in sales to retail customers primarily due to an increase in cooling degree days ($248 million); and

An increase in ancillary revenues received from PJM ($78 million), primarily reflecting an increase in the scheduled dispatch of gas and oil-fired generation units to meet higher demand; partially offset by

A decrease primarily due to the impact of unfavorable economic conditions on customer usage and other factors ($75 million);

A $98 million increase from regulated natural gas distribution operations primarily reflecting increased rider revenue associated with the recovery of bad debt expense ($60 million) and an increase in base rates ($40 million); and

A $46 million increase related to natural gas transmission operations largely due to the completion of the Cove Point expansion project.
These increases were partially offset by:

A $356 million decrease from merchant generation operations due to a decrease at certain nuclear generating facilities ($237 million) primarily due to lower realized prices, a decline in margins at certain fossil generation facilities ($70 million) primarily due to an increase in fuel prices and the expiration of certain requirements-based power sales contracts in December 2009 ($49 million);

A $222 million decrease reflecting the sale of substantially all of Dominion’s Appalachian E&P operations in April 2010; and

A $40 million decrease in producer services primarily related to unfavorable price changes on economic hedging positions and lower physical margins, all associated with natural gas aggregation, marketing and trading activities.
Other operations and maintenance increased $12 million primarily reflecting:

A $240 million net increase in salaries, wages and benefits primarily related to a workforce reduction program;

Impairment charges related to certain merchant generating facilities ($194 million);

A $103 million increase due to the absence of a benefit in 2009 from a downward revision in the nuclear decommissioning ARO for a unit that is no longer in service;

A $56 million increase in bad debt expense at regulated natural gas distribution operations, primarily related to low income assistance programs ($60 million). These expenses are recovered through rates and do not impact net income; and

A $42 million increase in certain electric transmission-related expenditures.
These increases were partially offset by:

A $434 million decrease in ceiling test impairment charges related to the carrying value of Dominion’s E&P properties;

The absence of a $142 million write-off of previously deferred RTO costs in connection with the settlement of Virginia Power’s 2009 base rate case proceedings; and

A $48 million decrease in outage costs due to a decrease in scheduled outage days primarily at certain merchant generation facilities.
DD&A decreased 7%, primarily due to the sale of Dominion’s Appalachian E&P operations ($45 million) and lower amortization due to decreased cost of emissions allowances consumed ($37 million).
Other taxes increased 10%, primarily due to additional property tax from increased investments and higher rates ($16 million), an increase in gross receipts tax due to new non-regulated retail energy customers ($14 million) and higher payroll taxes associated with a workforce reduction program ($12 million).
Gain on sale of Appalachian E&P operations reflects a gain on the sale of these operations, as described in Note 4 to the Consolidated Financial Statements.
Other income decreased 13%, primarily reflecting an increase in charitable contributions ($46 million) and a decrease in interest income ($15 million); partially offset by the absence of an impairment loss on an equity method investment ($30 million) and higher realized gains (including investment income) on nuclear decommissioning trust funds ($12 million).
Interest and related charges decreased 6%, primarily due to a benefit resulting from the net effect of the discontinuance of hedge accounting for certain interest rate hedges and subsequent changes in fair value of these interest rate derivatives ($73 million), partially offset by an increase in interest expense associated with the June 2009 hybrid issuance ($26 million).
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Income tax expense increased $1.5 billion, primarily reflecting higher federal and state taxes largely due to the gain on the sale of Dominion’s Appalachian E&P business.
Loss from discontinued operations primarily reflects a loss on the sale of Peoples.
Outlook
Dominion’s strategy is to continue focusing on its regulated businesses while maintaining upside potential in well-positioned nonregulated businesses. The goals of this strategy are to provide earnings per share growth, a growing dividend and to maintain a stable credit profile. Dominion’s 2011 results were negatively impacted by lower margins from merchant generation operations and less favorable weather on electric utility operations. In 2012, Dominion is expected to experience an increase in net income on a per share basis as compared to 2011. Dominion’s anticipated 2012 results reflect the following significant factors:

The absence of charges incurred in 2011 related to expected plant retirements, impairment of emissions allowances and Hurricane Irene;

Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue, as well as growth projects in gas transmission and distribution operations;

Growth in weather-normalized electric utility sales of 2-2.5% resulting from the recovering economy and rising energy demand;

Reductions in certain operations and maintenance expenses; and

A reduction in interest expense; partially offset by

Lower realized margins from merchant generation operations due to lower commodity prices and the retirement of certain coal units; and

An increase in DD&A.
Dominion expects the bonus depreciation provisions of the tax legislation enacted by the U.S. Congress in 2010, discussed in Note 6 to the Consolidated Financial Statements, to reduce income taxes otherwise payable, resulting in cash savings in 2012 and 2013 of approximately $475 million and $700 million, respectively.
SEGMENT RESULTS OF OPERATIONS
Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. Presented below is a summary of contributions by Dominion’s operating segments to net income attributable to Dominion:
DVP
Presented below are operating statistics related to DVP’s operations:
(1) Thirteen-month average.
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
2011 VS. 2010
(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.
2010 VS. 2009
(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program.
Dominion Generation
Presented below are operating statistics related to Dominion Generation’s operations:
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
2011 VS. 2010
(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.
(2) Kewaunee’s 2011 results of operations have been reflected in the Corporate and Other segment due to Dominion’s decision, in the first quarter of 2011, to pursue a sale of the power station.
2010 VS. 2009
(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program.
Dominion Energy
Presented below are selected operating statistics related to Dominion Energy’s operations. As discussed in Note 4, in April 2010 Dominion completed the sale of substantially all of its Appa-
lachian E&P operations. As a result, production-related operating statistics for the Dominion Energy segment are no longer significant.
(1) Thirteen-month average.
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:
2011 VS. 2010
(1) Primarily reflects an increase in revenue from NGLs.
(2) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.
2010 VS. 2009
(1) Primarily reflects an allowed return on investment through the AMR and PIR programs.
(2) Reflects East Ohio’s sale of 3 bcf of base gas in December 2010 as the Company determined that it could operate its storage system and meet existing and anticipated contractual commitments with less base gas.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results:
TOTAL SPECIFIC ITEMS
Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 26 to the Consolidated Financial Statements for discussion of these items.
VIRGINIA POWER
RESULTS OF OPERATIONS
Presented below is a summary of Virginia Power’s consolidated results:
Overview
VS. 2010
Net income decreased by 4%, primarily reflecting less favorable weather, including Hurricane Irene, and an impairment charge related to certain coal-fired power stations, partially offset by higher earnings from rate adjustment clauses and the absence of charges related to a workforce reduction program.
2010 VS. 2009
Net income increased by 139%, primarily reflecting the absence of a charge in connection with the settlement of the 2009 base rate case proceedings, favorable weather and a benefit from rate adjustment clauses, partially offset by charges related to a workforce reduction program.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Power’s results of operations:
An analysis of Virginia Power’s results of operations follows:
2011 VS. 2010
Net Revenue increased $13 million, primarily reflecting:

The impact of rate adjustment clauses ($169 million); and

A decrease in net capacity expenses ($44 million); partially offset by

The impact ($120 million) of a decrease in sales to retail customers, primarily due to a decrease in heating and cooling degree days ($220 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($100 million); and

A decrease due to a charge based on the Biennial Review Order to refund revenues to customers ($81 million).
Other operations and maintenance decreased $2 million, primarily reflecting:

A $267 million decrease in salaries, wages and benefits as well as certain administrative and general costs primarily due to a 2010 workforce reduction program; and

A $54 million decrease in planned outage costs primarily due to fewer scheduled outage days at certain generation facilities; partially offset by

A $228 million impairment charge related to certain coal-fired generating units; and

A $96 million increase due to restoration costs associated with damage caused by Hurricane Irene.
Depreciation and amortization expense increased 7%, primarily due to property additions.
Other income decreased 12%, primarily due to a decrease in the equity component of AFUDC ($17 million), partially offset by an increase in amounts collectible from customers for taxes in connection with contributions in aid of construction ($5 million).
2010 VS. 2009
Net Revenue increased 33%, primarily reflecting:

The absence of a charge for the settlement of the 2009 base rate case proceedings ($570 million);

The impact of rate adjustment clauses ($279 million);

An increase in sales to retail customers primarily due to an increase in cooling degree days ($248 million); and

An increase in ancillary revenues received from PJM ($78 million), primarily reflecting an increase in the scheduled dispatch of gas and oil-fired generation units to meet higher demand.
These increases were partially offset by:

A decrease primarily due to the impact of unfavorable economic conditions on customer usage and other factors ($75 million).
Other operations and maintenance increased 8%, primarily reflecting:

A $177 million net increase in salaries, wages and benefits primarily due to a workforce reduction program;

A $42 million increase in certain electric transmission-related expenditures; and

A $19 million increase in storm damage and service restoration costs.
These increases were partially offset by:

The absence of a $130 million write-off of previously deferred RTO costs in connection with the settlement of Virginia Power’s 2009 base rate case proceedings.
Depreciation and amortization expense increased 5%, primarily due to property additions.
Other taxes increased 14%, primarily reflecting additional property tax due to increased investments and higher rates ($12 million), incremental use tax that is recoverable through a customer surcharge ($8 million) and higher payroll taxes associated with a workforce reduction program ($7 million).
Income tax expense increased $395 million, primarily reflecting higher pretax income in 2010.
Outlook
Virginia Power expects to provide growth in net income in 2012. Virginia Power’s anticipated 2012 results reflect the following significant factors:

The absence of charges incurred in 2011 related to expected plant retirements, impairment of emissions allowances and Hurricane Irene;

Growth in weather-normalized electric sales of 2-2.5% resulting from the recovering economy and rising energy demand; and

Construction and operation of growth projects and associated rate adjustment clause revenue; partially offset by

An increase in planned outages at certain nuclear facilities.
Virginia Power expects the bonus depreciation provisions of the tax legislation enacted by the U.S. Congress in 2010, discussed in Note 6 to the Consolidated Financial Statements, to reduce income taxes otherwise payable, resulting in cash savings of approximately $500 million in 2012.
SEGMENT RESULTS OF OPERATIONS
Presented below is a summary of contributions by Virginia Power’s operating segments to net income:
DVP
Presented below are operating statistics related to Virginia Power’s DVP segment:
(1) Thirteen-month average.
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
2011 VS. 2010
(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.
2010 VS. 2009
(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion Generation
Presented below are operating statistics related to Virginia Power’s Dominion Generation segment:
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
2011 VS. 2010
2010 VS. 2009
(1) Primarily reflects a reduced benefit from FTRs, due to the crediting of certain FTRs allocated to Virginia Power against Virginia jurisdictional fuel factor expenses subject to deferral accounting beginning July 1, 2009.
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results.
SPECIFIC ITEMS ATTRIBUTABLE TO OPERATING SEGMENTS
Corporate and Other primarily includes specific items attributable to Virginia Power’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 26 to the Consolidated Financial Statements for a discussion of these items.
LIQUIDITY AND CAPITAL RESOURCES
Dominion and Virginia Power 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 issuances of debt and/or equity securities.
At December 31, 2011, Dominion had $1.7 billion of unused capacity under its credit facilities, including $341 million of unused capacity under joint credit facilities available to Virginia Power. See additional discussion under Credit Facilities and Short-Term Debt.
A summary of Dominion’s cash flows is presented below:
(1) 2009 amount includes $5 million of cash classified as held for sale in Dominion’s Consolidated Balance Sheet.
(2) 2009 amount includes $2 million of cash classified as held for sale in Dominion’s Consolidated Balance Sheet.
A summary of Virginia Power’s cash flows is presented below:
Operating Cash Flows
In 2011, net cash provided by Dominion’s operating activities increased by $1.2 billion, primarily due to lower income tax payments, lower payments related to the Virginia Settlement Approval Order, and the absence of contributions to pension plans made in 2010; partially offset by lower merchant generation margins and the impact of less favorable weather on electric utility operations.
In 2011, net cash provided by Virginia Power’s operating activities increased by $615 million, primarily due to higher deferred fuel cost recoveries in its Virginia jurisdiction, lower payments related to the Virginia Settlement Approval Order, and the absence of contributions to Dominion’s pension plans made in 2010. The increase was partially offset by the impact of less favorable weather, higher restoration costs due to Hurricane Irene, and net changes in other working capital items.
Dominion believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In 2010, Dominion’s Board of Directors adopted a new dividend policy that raised its target payout ratio. In 2012, the Board affirmed the dividend policy and established an annual dividend rate of $2.11 per share of common stock, a 7.1% increase over the 2011 rate. Declarations of dividends are subject to further Board approval. Virginia Power believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and provide dividends to Dominion.
The Companies’ operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, and which are discussed in Item 1A. Risk Factors.
CREDIT RISK
Dominion’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion’s credit exposure as of December 31, 2011 for these activities. 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.
(1) Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 33% of the total net credit exposure.
(2) The five largest counterparty exposures, combined, for this category represented approximately 1% of the total net credit exposure.
(3) The five largest counterparty exposures, combined, for this category represented approximately 8% of the total net credit exposure.
(4) The five largest counterparty exposures, combined, for this category represented approximately 12% of the total net credit exposure.
Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers and was not considered material at December 31, 2011.
Investing Cash Flows
In 2011, net cash used in Dominion’s investing activities was $3.3 billion as compared to net cash provided by investing activities of $419 million in 2010, primarily reflecting the absence of the proceeds received in 2010 from the sale of Dominion’s Appalachian E&P operations and the sale of Peoples.
In 2011, net cash used in Virginia Power’s investing activities decreased by $478 million, primarily due to lower capital expenditures and restricted funds spent in 2011 as compared to restricted funds deposited in 2010 for the purpose of funding certain qualifying construction projects.
Financing Cash Flows and Liquidity
Dominion and Virginia Power rely on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by their operations. As discussed in Credit Ratings, the Companies’ ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances and, in the case of Virginia Power, approval by the Virginia Commission.
Each of the Companies currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows the Companies to use automatic shelf registration statements to register any offering of securities, other than those for business combination transactions.
In 2011, net cash provided by Dominion’s financing activities was $378 million as compared to net cash used in financing activities of $2.2 billion in 2010, primarily due to net debt issuances in 2011 as compared to net debt repayments in 2010, reflecting, in part, the use of proceeds in 2010 from the sales of Dominion’s Appalachian E&P operations and Peoples to repay debt.
In 2011, net cash used in Virginia Power’s financing activities was $53 million as compared to net cash provided by financing activities of $1.0 billion in 2010, primarily reflecting lower net debt issuances in 2011 as compared to 2010 as a result of higher cash flow from operations.
CREDIT FACILITIES AND SHORT-TERM DEBT
Dominion and Virginia Power use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.
In connection with commodity hedging activities, the Companies are required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, the Companies may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, the Companies vary the form of collateral provided to counterparties after weighing the costs and benefits of various factors associated with the different forms of collateral. These factors include short-term borrowing and short-term investment rates, the spread over these short-term rates at which the Companies can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
DOMINION
Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:
(1) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.
(2) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.
(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were 0.47% at December 31, 2011.
VIRGINIA POWER
Virginia Power’s short-term financing is supported by two joint revolving credit facilities with Dominion. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion and Virginia Power and for other general corporate purposes.
Virginia Power’s share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion, were as follows:
(1) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.
(2) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.
(3) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.46% at December 31, 2011.
In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility that
was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This facility supports certain tax-exempt financings of Virginia Power.
LONG-TERM DEBT
During 2011, Dominion issued the following long-term debt:
Virginia Power did not issue senior notes during 2011.
In December 2010, Brayton Point borrowed approximately $160 million and approximately $75 million in connection with the Massachusetts Development Finance Agency Recovery Zone Facility Bonds, Series 2010 A and the Solid Waste Disposal Revenue Bonds, Series 2010 B, respectively, which mature in 2041. The proceeds are being used to finance certain qualifying facilities at Brayton Point. Due to unfavorable market conditions, Dominion acquired the bonds upon issuance in December 2010 with the intention of remarketing them to third parties at a later time. At December 31, 2010, these bonds had not been remarketed and thus were not reflected on the Consolidated Balance Sheet. In July 2011, the Series 2010 B bonds were remarketed to a third party using a remarketing process, and bear interest at a variable rate for the first five years, after which they will bear interest at a market rate to be determined at that time. In August 2011, the Series 2010 A bonds were remarketed to third parties using a remarketing process, and bear interest at a coupon rate of 2.25% for the first five years, after which they will bear interest at a market rate to be determined at that time.
In December 2010 and September 2009, Virginia Power borrowed $100 million and $60 million, respectively, in connection with the $160 million Industrial Development Authority of Wise County Solid Waste and Sewage Disposal Revenue Bonds, Series 2009 A, which mature in 2040. The proceeds are being used to finance certain qualifying facilities at the Virginia City Hybrid Energy Center. Due to unfavorable market conditions, Virginia Power acquired the bonds upon issuance with the intention of remarketing them to third parties at a later time. At December 31, 2010, these bonds had not been remarketed and thus were not reflected on the Consolidated Balance Sheets. In March 2011, the bonds were remarketed to a third party and bear interest at a variable rate for the first five years, after which they will bear interest at a market rate to be determined at that time.
In December 2011, Virginia Power borrowed $75 million in connection with the Economic Development Authority of the County of Chesterfield Pollution Control Refunding Revenue Bonds, Series 2011 A, which mature in 2017 and bear interest during the initial period at a variable rate for the first five years, after which they will bear interest at a market rate to be determined at that time, using a remarketing process. The proceeds were used to refund the principal amount of the Industrial Development Authority of the County of Chesterfield, Virginia Money Market Municipals™ Pollution Control Revenue Bonds,
Series 1987 A and Series 1987 B that would otherwise have matured in June 2017.
During 2011, Dominion and Virginia Power repaid and repurchased $637 million and $91 million, respectively, of long-term debt and notes payable.
ISSUANCE OF COMMON STOCK
Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in the Company’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. During 2011, Dominion Direct® and the Dominion employee savings plans purchased Dominion common stock on the open market with the proceeds received through these programs, rather than having additional new common shares issued. In January 2012, Dominion began issuing new common shares for these plans.
During 2011, Dominion issued approximately 1.2 million shares of common stock and received cash proceeds of $38 million through the exercise of employee stock options.
In January 2012, Dominion filed a new SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at the market program. The Company entered into four separate Sales Agency Agreements with each of BNY Mellon Capital Markets, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. LLC, and Goldman Sachs & Co., to effect sales under the program. However, with the exception of issuing approximately $320 million in equity through employee savings plans, direct stock purchase and dividend reinvestment plans, and other employee and director benefit plans, Dominion does not anticipate issuing common stock in 2012.
In 2011, Virginia Power did not issue any shares of its common stock to Dominion.
REPURCHASE OF COMMON STOCK
In 2011, Dominion announced that it intended to repurchase between $600 million and $700 million of common stock with cash tax savings resulting from the extension of the bonus depreciation allowance. During 2011, Dominion repurchased approximately 13 million shares of common stock for approximately $601 million on the open market under this program, at an average price of $46.37 per share. Dominion does not plan to repurchase additional shares under this program during 2012.
BORROWINGS FROM PARENT
Virginia Power has the ability to borrow funds from Dominion under both short-term and long-term borrowing arrangements and at December 31, 2011, its nonregulated subsidiaries had outstanding borrowings, net of repayments, under the Dominion money pool of $187 million.
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. Dominion and Virginia Power believe that their current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion and Virginia Power may affect their ability to access these funding sources or cause an increase in the return required by investors. Dominion’s and Virginia Power’s credit ratings may affect their liquidity, cost of borrowing
under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which they are able to offer their debt securities.
Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for Dominion and Virginia Power are affected by each company’s financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.
Credit ratings as of February 23, 2012 follow:
As of February 23, 2012, Fitch, Moody’s and Standard & Poor’s maintained a stable outlook for their respective ratings of Dominion and Virginia Power.
A downgrade in an individual company’s credit rating would not necessarily restrict its ability to raise short-term and long-term financing as long as its credit rating remains investment grade, but it would likely increase the cost of borrowing. Dominion and Virginia Power work closely with Fitch, Moody’s and Standard & Poor’s with the objective of maintaining their current credit ratings. The Companies may find it necessary to modify their business plans to maintain or achieve appropriate credit ratings and such changes may adversely affect growth and EPS.
Debt Covenants
As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion and Virginia Power 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 capital stock, 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 Dominion and Virginia Power.
Some of the typical covenants include:

The timely payment of principal and interest;

Information requirements, including submitting financial reports filed with the SEC and information about changes in Dominion’s and Virginia Power’s credit ratings to lenders;

Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
related to merger or consolidation, and restrictions on disposition of all or substantially all assets;

Compliance with collateral minimums or requirements related to mortgage bonds; and

Limitations on liens.
Dominion and Virginia Power are required to pay annual commitment fees to maintain their credit facilities. In addition, their credit agreements contain various terms and conditions that could affect their ability to borrow under these facilities. They include maximum debt to total capital ratios and cross-default provisions.
As of December 31, 2011, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:
(1) Indebtedness as defined by the bank agreements excludes junior subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets.
These provisions apply separately to Dominion and Virginia Power. If Dominion or Virginia Power or any of either company’s material subsidiaries fails to make payment on various debt obligations in excess of $100 million, the lenders could require that company to accelerate its repayment of any outstanding borrowings under the credit facility and the lenders could terminate their commitment to lend funds to that company. Accordingly, any default by Dominion will not affect the lenders’ commitment to Virginia Power. However, any default by Virginia Power would affect the lenders’ commitment to Dominion under the joint credit agreements.
Dominion executed RCCs in connection with its issuance of the following hybrid securities:

June 2006 hybrids;

September 2006 hybrids; and

June 2009 hybrids.
See Note 18 to the Consolidated Financial Statements for terms of the RCCs.
At December 31, 2011, the termination dates and covered debt under the RCCs associated with Dominion’s hybrids were as follows:
(1) Automatically extended, as set forth in the RCC, for additional quarterly periods, to the extent the maturity date is extended.
Dominion and Virginia Power monitor the debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2011, there have been no events of default under or changes to Dominion’s or Virginia Power’s debt covenants.
Dividend Restrictions
The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a divi-
dend to an affiliate if found to be detrimental to the public interest. At December 31, 2011, the Virginia Commission had not restricted the payment of dividends by Virginia Power.
Certain agreements associated with Dominion’s and Virginia Power’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion or Virginia Power’s ability to pay dividends or receive dividends from their subsidiaries at December 31, 2011.
See Note 18 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes, which information is incorporated herein by reference.
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
CONTRACTUAL OBLIGATIONS
Dominion and Virginia Power are party to numerous contracts and arrangements obligating them 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 and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion and Virginia Power are parties as of December 31, 2011. 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 the Consolidated Balance Sheets, other than current maturities of long-term debt, interest payable and certain derivative instruments. The majority of Dominion’s and Virginia Power’s current liabilities will be paid in cash in 2012.
(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.
(2) Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2011 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 18 to the Consolidated Financial Statements. Does not reflect Dominion’s ability to defer interest payments on junior subordinated notes.
(3) Primarily consists of operating leases.
(4) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.
(5) Represents the summation of settlement amounts, by contracts, due from Dominion if all physical or financial transactions among its counterparties and Dominion were liquidated and terminated.
(6) Includes capital, operations, and maintenance commitments.
(7) Excludes regulatory liabilities, AROs and employee benefit plan obligations, which are not contractually fixed as to timing and amount. See Notes 13, 15 and 22 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $256 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 6 to the Consolidated Financial Statements.
(8) Includes interest rate swap agreements.
(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.
(2) Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2011 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 18 to the Consolidated Financial Statements.
(3) Primarily consists of operating leases.
(4) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.
(5) Excludes regulatory liabilities, AROs and employee benefit plan contributions that are not contractually fixed as to timing and amount. See Notes 13, 15 and 22 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $75 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 6 to the Consolidated Financial Statements.
PLANNED CAPITAL EXPENDITURES
Dominion’s planned capital expenditures are expected to total approximately $4.3 billion, $4.8 billion and $3.9 billion in 2012, 2013 and 2014, respectively. Dominion’s expenditures are expected to include construction and expansion of electric generation and natural gas transmission, processing, and storage facilities, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel and the buyout of the lease at Fairless in 2013.
Virginia Power’s planned capital expenditures are expected to total approximately $2.6 billion, $3.0 billion and $2.6 billion in 2012, 2013 and 2014, respectively. Virginia Power’s expenditures are expected to include construction and expansion of electric generation facilities, construction improvements and expansion of electric transmission and distribution assets and purchases of nuclear fuel.
Dominion and Virginia Power expect to fund their capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the respective company’s Board of Directors.
Based on available generation capacity and current estimates of growth in customer demand, Virginia Power will need additional generation in the future. See DVP, Dominion Generation and Dominion Energy-Properties in Item 1. Business for a discussion of Dominion’s and Virginia Power’s expansion plans.
These estimates are based on a capital expenditures plan reviewed and endorsed by Dominion’s Board of Directors in late 2011 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. The Companies may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.
Use of Off-Balance Sheet Arrangements
GUARANTEES
Dominion primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others. See Note 23 to the Consolidated Financial Statements for additional information, which information is incorporated herein by reference.
LEASING ARRANGEMENT
Dominion leases the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004.
Through September 30, 2011, Juniper held various power plant leases, including Fairless. In October 2011, the last lease other than Fairless expired and the related asset was sold by Juniper. With Fairless being its sole remaining asset, Juniper no longer qualified for the business scope exception as of October 2011, which required that Dominion determine whether Juniper is a VIE. Dominion concluded Juniper is a VIE because the entity’s capitalization is insufficient to support its operations, the power to direct the most significant activities of the entity are not performed by the equity holders, and Dominion, through its residual value guarantee discussed above, guarantees a portion of the residual value of Fairless. The activities that most significantly impact Juniper’s economic performance relate to the operation of Fairless. The decisions related to the operations of Fairless are made by Dominion and as such, Dominion is considered the primary beneficiary.
As the primary beneficiary, Dominion began consolidating Juniper in the fourth quarter of 2011. As a result, this leasing arrangement is no longer considered an off-balance sheet arrangement.
See Note 16 to the Consolidated Financial Statements for additional information.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
FUTURE ISSUES AND OTHER MATTERS
See Item 1. Business, Item 3. Legal Proceedings, and Notes 14 and 23 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other matters that may impact future results of operations and/or financial condition.
Environmental Matters
Dominion and Virginia Power 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.
ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES
Dominion incurred approximately $184 million, $228 million and $252 million of expenses (including depreciation) during 2011, 2010, and 2009 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $223 million and $250 million in 2012 and 2013, respectively. In addition, capital expenditures related to environmental controls were $403 million, $351 million, and $266 million for 2011, 2010 and 2009, respectively. These expenditures are expected to be approximately $228 million and $103 million for 2012 and 2013, respectively.
Virginia Power incurred approximately $129 million, $144 million and $134 million of expenses (including depreciation) during 2011, 2010 and 2009, respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $149 million and $164 million in 2012 and 2013, respectively. In addition, capital expenditures related to environmental controls were $77 million, $101 million and $109 million for 2011, 2010 and 2009, respectively. These expenditures are expected to be approximately $42 million and $65 million for 2012 and 2013, respectively.
FUTURE ENVIRONMENTAL REGULATIONS
Air
The 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 Dominion’s and Virginia Power’s facilities are subject to the CAA’s permitting and other requirements.
The EPA has finalized rules establishing a new 1-hour NAAQS for NO2 and a new 1-hour NAAQS for SO2, which could require additional NOX and SO2 controls in certain areas where the Companies operate. Until the states have developed implementation plans for these standards, the impact on Dominion’s or Virginia Power’s facilities that emit NOX and SO2 is uncertain.
In January 2010, the EPA also proposed a new, more stringent NAAQS for ozone and had planned to finalize the rule in 2011. In September 2011, the EPA announced a delay from 2011 to 2014 of the rulemaking, therefore NOx controls that may have
been required by the rulemaking are also expected to be delayed. However, the EPA’s decision to delay the rulemaking has been challenged in federal court and the length of delay in possible NOx controls, if any, will depend on the outcome of that litigation. In the interim, the EPA is proceeding with implementation of the current ozone standard and is expected to make final attainment/nonattainment designations by June 2012. Until the litigation is final and the states have developed implementation plans for the new NOX, SO2 and ozone standards, it is not possible to determine the impact on Dominion’s or Virginia Power’s facilities that emit NOX and SO2. The Companies cannot currently predict with certainty whether or to what extent the new rules will ultimately require additional controls, however, if significant expenditures are required, it could adversely affect Dominion’s results of operations, and Dominion’s and Virginia Power’s cash flows.
In June 2005, the EPA finalized amendments to the Regional Haze Rule, also known as the Clean Air Visibility Rule. The rule requires the states to implement Best Available Retrofit Technology requirements for sources to address impacts to visual air quality through regional haze state implementation plans, but allows other alternative options. The EPA has recently announced a schedule to complete rulemakings on regional haze state implementation plans during 2012. Although Dominion and Virginia Power anticipate that the emission reductions achieved through compliance with other CAA required programs will generally address this rule, additional emission reduction requirements may be imposed on the Companies’ facilities.
Water
The 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. Dominion and Virginia Power must comply with all aspects of the CWA programs at their operating facilities. In July 2004, the EPA published regulations under CWA Section 316(b) that govern existing utilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold. In April 2008, the U.S. Supreme Court granted an industry request to review the question of whether Section 316(b) authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. The U.S. Supreme Court ruled in April 2009 that the EPA has the authority to consider costs versus environmental benefits in selecting the best technology available for reducing impacts of cooling water intakes at power stations. It is currently unknown how the EPA will interpret the ruling in its ongoing rulemaking activity addressing cooling water intakes as well as how the states will implement this decision. In April 2011, the EPA published the proposed rule related to Section 316(b) in the Federal Register, and agreed to publish a final rule no later than July 27, 2012.
The rule in its proposed form seeks to establish a uniform national standard for impingement, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA proposes to delegate entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of nine facility-specific factors, including a social cost-benefit test.
The proposed rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Under this proposal, Dominion has 18 facilities that may be subject to these proposed regulations. If finalized as proposed, Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power cannot estimate the need or potential for entrainment controls under the proposed rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. However, the impacts of this proposed rule may be material to results of operations, financial condition, and/or cash flows.
Solid and Hazardous Waste
In June 2010, the EPA proposed federal regulations under the RCRA for management of coal combustion by-products generated by power plants. The EPA is considering two possible options for the regulation of coal combustion by-products, both of which fall under the RCRA. Under the first proposal, the EPA would classify these by-products as special wastes subject to regulation under subtitle C, the hazardous waste provisions of the RCRA, when destined for disposal at landfills or surface impoundments. Under the second proposal, the EPA would regulate coal combustion by-products under subtitle D of the RCRA, the section for non-hazardous wastes. While the Companies cannot currently predict the outcome of this matter, regulation under either option will affect Dominion’s and Virginia Power’s onsite disposal facilities and coal combustion by-product management practices, and potentially require material investments.
Climate Change Legislation and Regulation
In December 2009, the EPA issued their Final Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act, finding that GHGs “endanger both the public health and the public welfare of current and future generations.” On April 1, 2010, the EPA and the Department of Transportation’s National Highway Safety Administration announced a joint final rule establishing a program that will dramatically reduce GHG emissions and improve fuel economy for new cars and trucks sold in the United States. These rules took effect in January 2011 and established GHG emissions as regulated pollutants under the CAA.
In May 2010, the EPA issued the Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule that, combined with prior actions, require Dominion and Virginia Power to obtain permits for GHG emissions for new and modified facilities over certain size thresholds, and meet best available control technology for GHG emissions. The EPA has issued draft guidance for GHG permitting, including best available control technology. The EPA has also announced a schedule for proposing standards to regulate GHG emissions under the NSPS that would apply to new, modified and existing fossil-fired electric generating units. In August 2011, the EPA announced a delay in the schedule for proposing these regulations. Regulations were expected to be proposed by July 2011 and finalized by May 2012. The schedule for a proposed rulemaking governing a GHG
NSPS for existing sources is now delayed beyond January 2012, while a proposed NSPS governing new and modified units is expected to be released in early 2012.
There are other legislative proposals that may be considered that would have an indirect impact on GHG emissions. There is the potential for the U.S. Congress to consider a mandatory Clean Energy Standard. In addition to possible federal action, some regions and states in which Dominion and Virginia Power operate have already adopted or may adopt GHG emission reduction programs. Any of these new or contemplated regulations may affect capital costs, or create significant permitting delays, for new or modified facilities that emit GHGs.
In July 2008, Massachusetts passed the GWSA. Among other provisions, the GWSA sets economy-wide GHG emissions reduction goals for Massachusetts, including reductions of 25% below 1990 levels by 2020, interim goals for 2030 and 2040 and reductions of 80% below 1990 levels by 2050. No regulations impacting Dominion under the GWSA have been proposed. Dominion operates two coal/oil-fired generating power stations in Massachusetts and acts as a retail electric supplier in Massachusetts, all of which are subject to the implementation of the GWSA.
In December 2009, the governors of 11 Northeast and mid-Atlantic states, including Connecticut, Maryland, Massachusetts, New York, Pennsylvania, and Rhode Island (RGGI states plus Pennsylvania) signed a memorandum of understanding committing their states toward developing a low carbon fuel standard to reduce GHG emissions from vehicles. The memorandum of understanding established a process to develop a regional framework by 2011 and examine the economic impacts of a low carbon fuel standard program. Although economic studies and policy options were examined in 2011, a definitive framework has yet to be established.
Dodd-Frank Act
The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The Dodd-Frank Act includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can choose to exempt their hedging transactions from these clearing and exchange trading requirements. In addition, the Dodd-Frank Act allows applicable regulators, including the CFTC and SEC, to impose initial and variation margin requirements on entities who execute swaps. End users were not expressly exempted from these requirements for non-cleared swaps and rules have been proposed that address the margin obligations to be imposed on non-cleared swaps entered with end users. Final rules for the over-the-counter derivative-related provisions of the Dodd-Frank Act, including the clearing, exchange trading and margin requirements, will be established through the ongoing rulemaking process of the applicable regulators. In June 2011, both the CFTC and the SEC confirmed that they would not complete the required rulemakings by the July 2011 deadline under the Dodd-Frank Act. Each agency has granted temporary relief from most derivative-related provisions of the Dodd-Frank Act until the effective date of the applicable rules. Currently, the CFTC’s temporary relief
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
would expire no later than July 16, 2012, if not extended. If, as a result of the rulemaking process, Dominion’s or Virginia Power’s derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs, including from higher margin requirements, for their derivative activities. In addition, implementation of, and compliance with, the over-the-counter derivative provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in increased costs related to the Companies’ derivative activities. Due to the ongoing rulemaking process, the Companies are currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on their financial condition, results of operations or cash flows.
Nuclear Matters
In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as INPO. Like other U.S. nuclear operators, Dominion has been gathering supporting data and participating in industry initiatives focused on the ability to respond to and mitigate the consequences of design-basis and beyond-design-basis events at its stations. In July 2011, an NRC Task Force provided initial recommendations based on its review of the Fukushima Daiichi accident; and in October 2011, the NRC Staff provided its views on the prioritization of these recommendations and suggested several additional measures. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations; and that same month an Appropriations Act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as expeditiously as possible. The NRC anticipates issuance of orders and information requests requiring specific reviews and actions by the first anniversary of the earthquake and tsunami in March 2012. These actions, if adopted, could require nuclear plant modifications and may impact future operations and/or capital requirements at U.S. nuclear facilities, including those owned by Dominion and Virginia Power.
In August 2011, a magnitude 5.8 earthquake near Mineral, Virginia caused the two reactors at North Anna to shut down immediately, as designed. Some of the earthquake’s vibrations briefly exceeded North Anna’s licensing design basis at certain frequencies, however, Virginia Power’s inspections have shown no significant damage to equipment at the station from the earthquake. The reactors were placed in cold shutdown condition pending completion of NRC inspection and review. North Anna returned to full service in November 2011, following receipt of NRC approval to restart the two reactors.
Cove Point Export and Re-Export Projects
In September 2011, Cove Point filed the first part of a two-part domestic export authorization request with the DOE. The DOE approved the request in October 2011. The approval allows for long-term, multi-contract authority to liquefy for export domestically-produced LNG from the Cove Point terminal up to the equivalent of approximately 1 bcf of natural gas per day over a twenty-five year period. The approval also allows for Cove Point to act as an agent for third parties to liquefy for export domestically-produced LNG to other countries that (i) have a free
trade agreement with the U.S. that includes natural gas, and (ii) possess the capacity to import LNG via ocean-going carriers.
Cove Point filed the second part of the domestic export authorization application in October 2011. In the application, Cove Point requested authority to export domestically-produced LNG to other countries (i) with which the U.S. does not prohibit free trade, but does not have a free trade agreement that includes natural gas, and (ii) that possess the capacity to import LNG via ocean-going carriers.
Cove Point is not yet committed to operating an LNG export facility. Cove Point intends to secure customer commitments before deciding whether to proceed, and regulatory approvals will also be required. Subject to a final decision on pursuing the project, as well as securing applicable regulatory and other approvals, construction of liquefaction facilities to convert natural gas into LNG could begin in 2014.
In addition to the domestic export project, in August 2011, Cove Point filed an application with the DOE seeking blanket authority to re-export foreign-sourced LNG from the Cove Point terminal. In January 2012, the DOE approved the request to re-export up to the equivalent of 150 bcf of natural gas over a two-year period. The approval allows Cove Point to act as an agent for third parties to re-export LNG to other countries (i) other than those with which the U.S. prohibits free trade, and (ii) that possess the capacity to import LNG via ocean-going carriers. Cove Point must also obtain FERC approval prior to undertaking the minimal construction required for re-export.
Brayton Point and Salem Harbor CAA Section 114 Request
In May 2010, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at Brayton Point and Salem Harbor. Dominion submitted its response to the request in November 2010 and cannot predict the outcome of this matter.
Pipeline Safety Act
In January 2012, the Pipeline Safety Act was signed into law. The Pipeline Safety Act is intended to address pipeline safety issues that received national attention following a series of significant incidents involving pipelines. The Act provides the U.S. DOT with enhanced safety review authority and requires pipeline owners and operators to confirm, through records or testing, the maximum allowable operating pressure of certain gas pipelines in populated or certain high consequence areas. Operators that fail to confirm the maximum allowable operating pressure for the
identified locations within six months of enactment must conduct new testing. The Pipeline Safety Act also requires the U.S. DOT Pipeline and Hazardous Materials Safety Administration to consider certain factors and, if appropriate, to issue regulations requiring automatic shut-off valves on new or replaced pipelines where economically, technically and operationally feasible and to establish time limits for accident and incident notification. In addition, the Act doubles the maximum civil penalty for violations of the U.S. DOT’s compliance and safety rules from $100,000 to $200,000 for an individual violation and from $1,000,000 to $2,000,000 for a series of violations. While Dominion cannot estimate the potential financial statement impacts of the Pipeline Safety Act, additional operations and maintenance expenses and/or capital expenditures required to comply with the new rules are not expected to be material.
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 of Item 7. MD&A. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact Dominion and Virginia Power.
MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT
Dominion’s and Virginia Power’s financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in Dominion’s and Virginia Power’s electric operations, Dominion’s gas procurement operations, and Dominion’s energy marketing and trading operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt. In addition, they are exposed to investment price risk through various portfolios of equity and debt 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 or interest rates.
Commodity Price Risk
To manage price risk, Dominion and Virginia Power primarily hold commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products. As part of its strategy to market energy and to manage related risks, Dominion also holds commodity-based financial derivative instruments for trading purposes.
The derivatives used to manage commodity price risk are executed within established policies and procedures and may
include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices 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 observable market prices.
A hypothetical 10% unfavorable change in commodity prices of Dominion’s non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $179 million and $183 million as of December 31, 2011 and 2010, respectively. A hypothetical 10% unfavorable change in commodity prices of Dominion’s commodity-based financial derivative instruments held for trading purposes would have resulted in a decrease in fair value of approximately $8 million and $5 million as of December 31, 2011 and 2010, respectively.
A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of Virginia Power’s non-trading commodity-based financial derivatives as of December 31, 2011 or 2010.
The impact of a change in energy commodity prices on Dominion’s and Virginia Power’s non-trading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.
Interest Rate Risk
Dominion and Virginia Power manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments designated under fair value hedging and outstanding for Dominion and Virginia Power, a hypothetical 10% increase in market interest rates would not have resulted in a material change in annual earnings as of December 31, 2011 or 2010.
Dominion and Virginia Power may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. At December 31, 2010, Dominion and Virginia Power had no such interest rate derivatives outstanding; therefore, Dominion and Virginia Power had no sensitivity to changes in interest rates related to these interest rate derivatives. At December 31, 2011, Dominion and Virginia Power had $2.3 billion and $1.3 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $31 million and $15 million, respectively, in the fair value of these interest rate derivatives held by Dominion and Virginia Power at December 31, 2011.
The impact of a change in market interest rates on these anticipatory hedges at a point in time is not necessarily representative of the results that will be realized when such contracts are settled. Net gains and/or losses from interest rate derivatives used for
anticipatory hedging purposes, to the extent realized, will generally be amortized over the life of the respective debt issuance being hedged.
Investment Price Risk
Dominion and Virginia Power are subject to investment price risk due to securities held as investments in decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value.
Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $54 million and $95 million in 2011 and 2010, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2011 and 2010, Dominion recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $52 million and $182 million, respectively.
Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $24 million and $44 million in 2011 and 2010, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2011 and 2010, Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $25 million and $67 million, respectively.
Dominion sponsors pension and other postretirement benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power employees participate in these plans. Aggregate actual returns for Dominion’s pension and other post-
retirement plan assets were $273 million in 2011 and $624 million in 2010, versus expected returns of $519 million and $479 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the periodic cost recognized for employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. As of December 31, 2011 and 2010, a hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion’s plan assets would result in an increase in net periodic cost of approximately $13 million for pension benefits and $3 million for other postretirement benefits.
Risk Management Policies
Dominion and Virginia Power 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 credit and commodity risk management policies of all subsidiaries, including Virginia Power. 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 these credit policies and Dominion’s and Virginia Power’s December 31, 2011 provision for credit losses, management believes that it is unlikely that a material adverse effect on Dominion’s or Virginia Power’s financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
Item 8. Financial Statements and Supplementary Data
Page No.
Dominion Resources, Inc.
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009
Consolidated Balance Sheets at December 31, 2011 and 2010
Consolidated Statements of Equity at December 31, 2011, 2010 and 2009 and for the years then ended
Consolidated Statements of Comprehensive Income at December 31, 2011, 2010 and 2009 and for the years then ended
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009
Virginia Electric and Power Company
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009
Consolidated Balance Sheets at December 31, 2011 and 2010
Consolidated Statements of Common Shareholder’s Equity at December 31, 2011, 2010 and 2009 and for the years then ended
Consolidated Statements of Comprehensive Income at December 31, 2011, 2010 and 2009 and for the years then ended
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009
Combined Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2011 and 2010, and the related consolidated statements of income, equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of Dominion’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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 Dominion Resources, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, in 2009 Dominion changed its methods of accounting to adopt a new accounting standard for the impairment framework for oil and gas properties.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Dominion’s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2012 expressed an unqualified opinion on Dominion’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 2012
Dominion Resources, Inc.
Consolidated Statements of Income
(1) Includes income tax expense of $21 million and $16 million in 2010 and 2009, respectively.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Balance Sheets
(1) 1 billion shares authorized; 570 million shares and 581 million shares outstanding at December 31, 2011 and 2010, respectively.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Statements of Equity
(1) Includes at-the-market issuances and a debt-for-common stock exchange.
(2) See Note 3 for additional information.
(3) Includes subsidiary preferred dividends related to noncontrolling interests of $17 million in 2011, 2010 and 2009.
(4) See Note 16 for consolidation of a VIE in October 2011.
(5) Shares issued in excess of principal amounts related to converted securities. See Note 18 for further information on convertible securities.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements
Dominion Resources, Inc.
Consolidated Statements of Comprehensive Income
(1) Other comprehensive income for the year ended December 31, 2009 excludes a $20 million ($12 million after-tax) adjustment to AOCI representing the cumulative effect of the change in accounting principle related to the recognition and presentation of other-than-temporary impairments.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Statements of Cash Flows
(1) 2009 amount includes $5 million of cash classified as held for sale in Dominion’s Consolidated Balance Sheet.
(2) 2009 amount includes $2 million of cash classified as held for sale in Dominion’s Consolidated Balance Sheet.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
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 (“Virginia Power”) as of December 31, 2011 and 2010, and the related consolidated statements of income, common shareholder’s equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of Virginia Power’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. Virginia Power 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 Virginia Power’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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 2012
Virginia Electric and Power Company
Consolidated Statements of Income
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Balance Sheets
(1) 500,000 shares and 300,000 shares authorized at December 31, 2011 and 2010, respectively; 274,723 shares outstanding at December 31, 2011 and 2010.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Common Shareholder’s Equity
(1) See Note 3 for additional information.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Comprehensive Income
(1) Other comprehensive income for the year ended December 31, 2009 excludes a $3 million ($2 million after-tax) adjustment to AOCI representing the cumulative effect of the change in accounting principle related to the recognition and presentation of other-than-temporary impairments.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Combined Notes to Consolidated Financial Statements
NOTE 1. NATURE OF OPERATIONS
Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion’s operations are conducted through various subsidiaries, including Virginia Power, a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s common stock is owned by Dominion. Dominion’s operations also include a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, an LNG import and storage facility in Maryland and regulated gas transportation and distribution operations in Ohio and West Virginia. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations.
Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of the operations and sale of Peoples, which is discussed in Note 4. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 26 for further discussion of Dominion’s and Virginia Power’s operating segments.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
General
Dominion and Virginia Power make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with 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.
Dominion’s and Virginia Power’s Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of their respective majority-owned subsidiaries and those VIEs where Dominion has been determined to be the primary beneficiary.
Dominion and Virginia Power report certain contracts, instruments and investments at fair value. See Note 7 for further information on fair value measurements.
Dominion maintains pension and other postretirement benefit plans. Virginia Power participates in certain of these plans. See Note 22 for further information on these plans.
Certain amounts in the 2010 and 2009 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2011 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.
Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.
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. The Companies collect sales, consumption and consumer utility taxes; however, these amounts are excluded from revenue. Dominion’s customer receivables at December 31, 2011 and 2010 included $423 million and $466 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2011 and 2010 included $360 million and $397 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers.
The primary types of sales and service activities reported as operating revenue for Dominion are as follows:

Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;

Regulated gas sales consist primarily of state-regulated retail natural gas sales and related distribution services;

Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties;

Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services and associated derivative activity. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; and

Other revenue consists primarily of sales of oil and NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes miscellaneous service revenue from electric and gas distribution operations, and gas processing and handling revenue.
The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:

Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and

Other revenue consists primarily of miscellaneous service revenue from electric distribution operations and miscellaneous
revenue from generation operations, including sales of capacity and other commodities.
Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs
Where permitted by regulatory authorities, the differences between Virginia Power’s actual electric fuel and purchased energy expenses and Dominion’s purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.
Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 84% is currently subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.
Income Taxes
A consolidated federal income tax return is filed for Dominion and its subsidiaries, including Virginia Power. In addition, where applicable, combined income tax returns for Dominion and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed. Virginia Power participates in an intercompany tax sharing agreement with Dominion and its subsidiaries, and its current income taxes are based on its taxable income or loss, determined on a separate company basis.
Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.
Dominion and Virginia Power recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.
If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the consolidated balance sheets and current payables are included in accrued interest, payroll and taxes on the consolidated balance sheets, except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities.
Dominion and Virginia Power recognize changes in estimated interest payable on net underpayments of income taxes in interest expense. Changes in interest receivable related to net overpayments of income taxes and estimated penalties that may result from the settlement of some uncertain tax positions are recognized in other income. In its Consolidated Statements of Income for 2011, Dominion recognized interest income of $12 million and interest expense of $7 million and a reduction in penalties of less than $1 million. In 2010, Dominion recognized a reduction in interest expense of $18 million and a reduction in penalties of less than $1 million; in 2009, Dominion recognized a reduction in interest expense of $19 million and a reduction in penalties of $2 million. Dominion had accrued interest receivable of $48 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2011 and interest receivable of $27 million and interest and penalties payable of less than $1 million at December 31, 2010.
In 2011, Virginia Power recognized interest income of $12 million, and penalties were immaterial. Virginia Power had accrued interest receivable of $17 million at December 31, 2011. Virginia Power’s interest and penalties were immaterial in 2010 and 2009.
At December 31, 2011, Virginia Power’s Consolidated Balance Sheet included $18 million of current federal income taxes receivable, $34 million of current state income taxes payable and $110 million of noncurrent federal and state income taxes payable. At December 31, 2010, Virginia Power’s Consolidated Balance Sheet included $46 million of prepaid federal and state income taxes and $102 million of noncurrent federal and state income taxes payable.
Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.
Cash and Cash Equivalents
Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 2011 and 2010, Dominion’s accounts payable included $75 million and $56 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 2011 and 2010, Virginia Power’s accounts payable included $40 million and $28 million, respectively, of checks outstanding but not yet presented for payment. For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.
Derivative Instruments
Dominion and Virginia Power use derivative instruments such as futures, swaps, forwards, options and FTRs to manage the commodity, currency exchange and financial market risks of their business operations.
All derivatives, other than those for which an exception applies, are reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are
Combined Notes to Consolidated Financial Statements, Continued
reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.
Dominion and Virginia Power do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion had margin assets of $319 million and $244 million associated with cash collateral at December 31, 2011 and 2010, respectively. Dominion had margin liabilities of $66 million and $62 million associated with cash collateral at December 31, 2011 and 2010, respectively. Virginia Power had margin assets of $41 million associated with cash collateral at December 31, 2011. Virginia Power’s margin assets associated with cash collateral were not material at December 31, 2010. Virginia Power’s margin liabilities associated with cash collateral were not material at December 31, 2011 and 2010.
To manage price risk, Dominion and Virginia Power hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. As part of Dominion’s strategy to market energy and manage related risks, it also manages a portfolio of commodity-based financial derivative instruments held for trading purposes. Dominion uses established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and uses various derivative instruments to reduce risk by creating offsetting market positions.
Statement of Income Presentation:

Derivatives Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis.

Derivatives Not Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses or interest and related charges based on the nature of the underlying risk.
In Virginia Power’s generation operations, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.
DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS
Dominion and Virginia Power designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, Dominion and Virginia Power formally document the relationship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using
the hedging instrument. The Companies assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges.
Cash Flow Hedges-A majority of Dominion’s and Virginia Power’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and other energy-related products. The Companies also use foreign currency contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which Dominion and Virginia Power are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.
Fair Value Hedges-Dominion also uses fair value hedges to mitigate the fixed price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, Dominion and Virginia Power have designated interest rate swaps as fair value hedges on certain fixed-rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Derivative gains and losses from the hedged item are reclassified to earnings when the hedged item is included in earnings, or earlier, if the hedged item no longer qualifies for hedge accounting. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting.
See Note 7 for further information about fair value measurements and associated valuation methods for derivatives. See Note 8 for further information on derivatives.
Property, Plant and Equipment
Property, plant and equipment, including additions and replacements is recorded at original cost, consisting of labor and materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as it is incurred.
In 2011, 2010 and 2009, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $85 million, $102 million and $76 million, respectively. In 2011, 2010 and 2009, Virginia Power capitalized AFUDC to property, plant and equipment of $31 million, $61 million and $47 million,
respectively. Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2011, 2010 and 2009, Virginia Power recorded $20 million, $13 million and $34 million of AFUDC related to these projects, respectively.
For Virginia Power property subject to cost-of-service rate regulation, including electric distribution, electric transmission, and generation property and for certain Dominion natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement, with gains and losses recorded on the sales of property. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be retired or abandoned significantly before the end of their useful lives, the net carrying value is reclassified from plant-in-service when it becomes probable they will be retired or abandoned.
For Dominion and Virginia Power property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.
Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. Dominion’s and Virginia Power’s depreciation rates on utility property, plant and equipment are as follows:
Dominion’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:
Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.
Dominion follows the full cost method of accounting for its gas and oil E&P activities, which subjects capitalized costs to a quarterly ceiling test using hedge-adjusted prices. Due to the April
2010 sale of substantially all of its Appalachian E&P operations Dominion no longer has any significant gas and oil properties subject to the ceiling test calculation.
In 2010, Dominion recorded a ceiling test impairment charge of $21 million ($13 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income primarily due to a decline in hedge-adjusted prices reflecting the discontinuance of hedge accounting for certain cash flow hedges, as discussed in Note 4.
In 2009, Dominion recorded a ceiling test impairment charge of $455 million ($281 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income. Excluding the effects of hedge-adjusted prices in calculating the ceiling limitation, the impairment would have been $631 million ($387 million after-tax).
In 2010, Dominion recognized a gain from the sale of substantially all of its Appalachian E&P operations as discussed in Note 4.
Emissions Allowances
Emissions allowances permit the holder of the allowance to emit certain gaseous by-products of fossil fuel combustion, including SO2, NOX and CO2. SO2 and NOX emissions allowances are issued to Dominion and Virginia Power by the EPA and may also be purchased and sold via third party contracts. CO2 emissions allowances are available for purchase by Dominion through quarterly auctions held by participating RGGI states. Compliance with the RGGI requirements only applies to certain of Dominion’s merchant power stations located in the Northeast.
Allowances held may be transacted with third parties or consumed as these emissions are generated. Allowances allocated to or acquired by the Companies’ generation operations are held primarily for consumption.
Allowances held for consumption are classified as intangible assets in the Consolidated Balance Sheets. Carrying amounts are based on the cost to acquire the allowances or, in the case of a business combination, on the fair values assigned to them in the allocation of the purchase price of the acquired business. A portion of Dominion’s and Virginia Power’s SO2 and NOX allowances are issued by the EPA at zero cost.
These allowances are amortized in the periods the emissions are generated, with the amortization reflected in DD&A in the Consolidated Statements of Income. Purchases and sales of these allowances are reported as investing activities in the Consolidated Statements of Cash Flows and gains or losses resulting from sales are reported in other operations and maintenance expense in the Consolidated Statements of Income. See Note 7 for discussion of impairments related to emissions allowances.
Long-Lived and Intangible Assets
Dominion and Virginia Power perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 7 for a discussion of impairments related to certain long-lived assets and intangible assets with finite lives.
Combined Notes to Consolidated Financial Statements, Continued
Regulatory Assets and Liabilities
The accounting for Dominion’s regulated gas and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.
The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions 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.
Asset Retirement Obligations
Dominion and Virginia Power recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Dominion reports accretion of AROs associated with its natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Virginia Power reports accretion of AROs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Accretion of all other AROs is reported in other operations and maintenance expense in the Consolidated Statements of Income.
Amortization of Debt Issuance Costs
Dominion and Virginia Power 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 issuances.
Investments
MARKETABLE EQUITY AND DEBT SECURITIES
Dominion accounts for and classifies investments in marketable equity and debt securities as trading or available-for-sale securities.
Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities.

Trading securities include marketable equity and debt securities held by Dominion in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

Available-for-sale securities include all other marketable equity and debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other available-for-sale securities, including those held in Dominion’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.
In determining realized gains and losses for marketable equity and debt securities, the cost basis of the security is based on the specific identification method.
NON-MARKETABLE INVESTMENTS
Dominion and Virginia Power account for illiquid and privately held securities for which market prices or quotations are not readily available under either the equity or cost method. Non-marketable investments include:

Equity method investments when Dominion and Virginia Power have the ability to exercise significant influence, but not control, over the investee. Dominion’s investments are included in investments in equity method affiliates and Virginia Power’s investments are included in other investments in their Consolidated Balance Sheets. Dominion and Virginia Power record equity method adjustments in other income in the Consolidated Statements of Income including: their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

Cost method investments when Dominion and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion’s and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds.
OTHER-THAN-TEMPORARY IMPAIRMENT
Dominion and Virginia Power periodically review their investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period.
Decommissioning Trust Investments-Special Considerations

The FASB amended its guidance for the recognition and presentation of other-than-temporary impairments, which Dominion and Virginia Power adopted effective April 1, 2009. The recognition provisions of this guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities. Prior to the adoption of this guidance, Dominion and Virginia Power considered all debt securities held by their nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired as they did not have the ability to ensure the investments were held through the anticipated recovery period.

Debt Securities-Effective with the adoption of this guidance, using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is the case, but the debt security is deemed to have experienced a credit loss, the Companies record the credit loss in earnings and any remaining portion of the unrealized loss in other comprehensive income. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

Equity securities and other investments-Dominion’s and Virginia Power’s method of assessing other-than-temporary declines requires demonstrating the ability to hold individual securities for a period of time sufficient to allow for the anticipated recovery in their market value prior to the consideration of the other criteria mentioned above. Since the Companies have limited ability to oversee the day-to-day management of nuclear decommissioning trust fund investments, they do not have the ability to ensure investments are held through an anticipated recovery period. Accordingly, they consider all equity and other securities as well as non-marketable investments held in nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired.
Inventories
Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory used in East Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at $48 million at December 31, 2011 and 2010. Based on the average price of gas purchased during 2011 and 2010, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $86 million and $107 million, respectively. Stored gas inventory held by Hope and certain nonregulated gas operations is valued using the weighted-average cost method.
Gas Imbalances
Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas deliv-
ered or received. Dominion values these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion from other parties are reported in other current assets and imbalances that Dominion owes to other parties are reported in other current liabilities in the Consolidated Balance Sheets.
Goodwill
Dominion evaluates goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.
NOTE 3. NEWLY ADOPTED ACCOUNTING STANDARDS
RECOGNITION AND PRESENTATION OF OTHER-THAN-TEMPORARY IMPAIRMENTS
The FASB amended its guidance for the recognition and presentation of other-than-temporary impairments, which Dominion and Virginia Power adopted effective April 1, 2009. The recognition provisions of this guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities. Prior to the adoption of this guidance, as described in Note 2, the Companies considered all debt securities held by their nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired as they did not have the ability to ensure the investments were held through the anticipated recovery period.
Upon the adoption of this guidance for debt investments held at April 1, 2009, Dominion recorded a $20 million ($12 million after-tax) and Virginia Power recorded a $3 million ($2 million after-tax) cumulative effect of a change in accounting principle to reclassify the non-credit related portion of previously recognized other-than-temporary impairments from retained earnings to AOCI, reflecting the fixed-income investment managers’ intent and ability to hold the debt securities until recovery of their fair values up to their cost bases.
SEC FINAL RULE, MODERNIZATION OF OIL AND GAS REPORTING
Effective December 31, 2009, Dominion adopted the SEC Final Rule, Modernization of Oil and Gas Reporting, which revised the existing Regulation S-K and Regulation S-X reporting requirements. Under the new requirements, the ceiling test is calculated using an average price based on the prior 12-month period rather than period-end prices. Due to the April 2010 sale of substantially all of its Appalachian E&P operations, Dominion no longer has any significant gas and oil properties subject to the ceiling test calculation.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 4. DISPOSITIONS
Sale of Appalachian E&P Operations
In April 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. The transaction includes the mineral rights to approximately 491,000 acres in the Marcellus Shale formation. Dominion retained certain oil and natural gas wells located on or near its natural gas storage fields. The transaction generated after-tax proceeds of approximately $2.2 billion and resulted in an after-tax gain of approximately $1.4 billion, which includes a $134 million write-off of goodwill, recorded in the second quarter of 2010.
The results of operations for Dominion’s Appalachian E&P business are not reported as discontinued operations in the Consolidated Statements of Income since Dominion did not sell its entire U.S. cost pool.
Due to the sale, hedge accounting was discontinued for certain cash flow hedges since it became probable that the forecasted sales of gas would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a $42 million ($25 million after-tax) benefit, recorded in operating revenue in its Consolidated Statement of Income, reflecting the reclassification of gains from AOCI to earnings for these contracts in March 2010.
Sale of Peoples
In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The sale resulted in an after-tax loss of approximately $140 million, including post-closing adjustments, and a $79 million write-off of goodwill. The sale also resulted in after-tax expenses of approximately $27 million, including transaction and benefit-related costs. Prior to the sale, Peoples had income from operations of $12 million after-tax during 2010.
The following table presents selected information regarding the results of operations of Peoples, which are reported as dis-continued operations in Dominion’s Consolidated Statements of Income:
(1) Includes a loss and other charges related to the sale of Peoples.
(2) Includes the impact of a $22 million charge due to a reduction of the previously established regulatory asset and a loss and other charges related to the sale.
NOTE 5. OPERATING REVENUE
Dominion’s and Virginia Power’s operating revenue consists of the following:
NOTE 6. INCOME TAXES
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. Dominion and Virginia Power are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.
In 2010, U.S. federal legislation was enacted that allows taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of 2011, when placed in service before 2013, and otherwise provides an extension of the fifty percent bonus depreciation allowance for qualifying capital expenditures through 2012.
In December 2011, the IRS issued temporary regulations that provide guidance to taxpayers on the treatment of amounts paid to acquire, produce or improve tangible property and of dispositions of such property. The temporary regulations generally are effective for expenditures made on or after January 1, 2012. Any changes for tax treatment elected by Dominion or required by the regulations will be effective prospectively; however, implementation will require a calculation of the cumulative effect of the changes on prior years, and it is expected that such amount will have to be included in the determination of Dominion’s taxable income in 2012, or possibly over a four-year period beginning in 2012. The IRS is expected to issue additional procedural guidance regarding 2012 tax return filing requirements and how the requirements may be implemented for electric generation operations and gas transmission and distribution systems.
Dominion believes the evaluation and implementation of the temporary regulations will require an extensive effort and may permit, or require, changes to how Dominion determines whether expenditures incurred related to plant and equipment should be deducted as repairs or capitalized and depreciated on its tax returns. Since changes will be concerned with the timing for
deducting expenditures for tax purposes, the impact of implementation will be reflected in the amount of income taxes payable or receivable, cash flows from operations and deferred taxes. Except to the extent the implementation impacts deferred taxes and, therefore, the rate base used to establish customer rates for regulated utilities, results of operations should not be materially affected. Pending the issuance of additional procedural guidance from the IRS and progress of the evaluation process, Dominion cannot estimate the impact of implementing the temporary regulations.
Continuing Operations
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
(1) In 2011, Dominion’s federal income tax expense includes a $346 million benefit related to its current year operating loss that is expected to be used in future years, and state income tax expense reflects changes in the amount of income apportioned among states, higher tax credits, claims for refunds and previously unrecognized tax benefits due to the expiration of statutes of limitations.
(2) In 2011, Virginia Power’s federal income tax expense includes a $54 million benefit related to a portion of its current year operating loss that is expected to be used in future years. Also, in 2011 and 2010, Virginia Power’s federal income tax expense reflects the amounts of current year operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to Dominion’s and Virginia Power’s effective income tax rate as follows:
Dominion’s and Virginia Power’s effective tax rates in 2010 reflect reductions of deferred tax assets of $57 million and $17 million, respectively, resulting from the enactment of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act of 2010, which eliminated the employer’s deduction, beginning in 2013, for that portion of its retiree prescription drug coverage cost that is being reimbursed by the Medicare Part D subsidy. In addition, Dominion’s effective tax rate in 2010 includes higher state income taxes and the impact of goodwill written off that is not deductible for tax purposes associated with the sale of the Appalachian E&P operations.
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.
Combined Notes to Consolidated Financial Statements, Continued
The Companies’ deferred income taxes consist of the following:
At December 31, 2011, Dominion had the following deductible loss and credit carryforwards:

Federal loss carryforwards of $1.0 billion that expire if unutilized during the period 2021 through 2031;

Federal production tax credits of $13 million that expire if unutilized through 2031;

State loss carryforwards of $1.1 billion that expire if unutilized during the period 2014 through 2031. A valuation allowance on $866 million of these carryforwards has been established;

State minimum tax credits of $101 million that do not expire;

State investment tax credits of $6 million that expire if unutilized through 2014; and

State investment tax credits of $3 million that do not expire.
At December 31, 2011, Virginia Power had the following deductible loss and credit carryforwards:

Federal loss carryforwards of $157 million that expire if unutilized through 2031; and

State minimum tax credits of $1 million that do not expire.
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 tax authorities with full knowledge of all relevant information. The amount of tax return positions that are not recognized in the financial statements is disclosed as unrecognized tax benefits. These unrecognized tax benefits may impact the financial statements by increasing income taxes payable, reducing tax refunds receivable or changing deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, an increase in taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities.
A reconciliation of changes in the Companies’ unrecognized tax benefits follows:
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from claims for tax benefits, or portions thereof, that may not be realized, remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitation. For Dominion and its subsidiaries, these unrecognized tax benefits were $184 million, $133 million and $95 million at December 31, 2011, 2010 and 2009, respectively. For Dominion, the change in these unrecognized tax benefits increased income tax expense by $51 million in 2011 and $38 million in 2010 and decreased income tax expense by $26 million in 2009. For Virginia Power, these unrecognized tax benefits were $20 million at December 31, 2011 and $14 million at December 31, 2010 and 2009. For Virginia Power, the change in these unrecognized tax benefits increased income tax expense by $6 million in 2011 and by less than $1 million in 2010 and decreased income tax expense by $7 million in 2009.
A portion of Dominion’s and Virginia Power’s unrecognized tax benefits balances at December 31, 2011 represents tax positions for which the ultimate deductibility is highly certain; however, there is uncertainty about the timing of such deductibility. When uncertainty about the deductibility of amounts is limited to the timing of such deductibility, any tax liabilities recognized for prior periods would be subject to offset with the availability of refundable amounts from later periods when such deductions could otherwise be taken. Pending resolution of these uncertainties, interest is accrued until the period in which the amounts would become deductible.
For Dominion and its subsidiaries, the U.S. federal statute of limitations has expired for years prior to 2006, except that Dominion has reserved the right to pursue refunds related to the calculation of interest to be capitalized in connection with improvements to in-service plant and equipment for the years 1995 through 2005. The IRS position provides that capitalized interest must also be computed on the adjusted tax basis of in-service assets that are idled while making improvements to them. In response to litigation initiated by Dominion in March 2008, the United States Court of Federal Claims ruled in February 2011, sustaining the IRS position. In July 2011, Dominion
filed an appeal with the United States Court of Appeals for the Federal Circuit. Dominion believes the ultimate resolution of this matter will not have a material impact on its cash flows, results of operations or financial condition.
In January 2012, the Appellate Division of the IRS informed Dominion that the Joint Committee had completed its review of the settlement of tax years 2004 and 2005 for Dominion and its consolidated subsidiaries. Since the measurement of unrecognized tax benefits in 2011 considered the results of completed settlement negotiations, Dominion’s results of operations in 2012 will not be affected.
In 2011, the IRS completed its fieldwork in the examination of Dominion’s consolidated tax returns for tax years 2006 and 2007. Dominion and the IRS have resolved all issues, except Dominion is reserving the right to pursue a refund related to the capitalized interest issue that is currently being litigated.
The IRS examination of tax years 2008, 2009 and 2010 will begin in the first quarter of 2012.
It is reasonably possible that resolution of the litigation related to capitalized interest and settlements with and payments to tax authorities in 2012 could reduce unrecognized tax benefits for Dominion and Virginia Power by $24 million and $15 million, respectively. Dominion’s unrecognized tax benefits could also be reduced by up to $18 million, including $8 million for Virginia Power, to recognize prior period amounts becoming otherwise deductible in 2012 and the expiration of statutes of limitations. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, Dominion’s earnings could increase by up to $7 million with no material impact on Virginia Power’s earnings.
Otherwise, with regard to 2011 and prior years, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2012.
For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows:
(1) Virginia is the only state considered major for Virginia Power’s operations.
Dominion and Virginia Power are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are subject to examination.
Discontinued Operations
Income tax expense in 2010 for Dominion’s discontinued operations primarily reflects the impact of goodwill written off in the sale of Peoples that is not deductible for tax purposes and the reversal of deferred taxes for which the benefit was offset by the reversal of income tax-related regulatory assets.
NOTE 7. FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of Dominion’s and Virginia Power’s own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion and Virginia Power apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, and nuclear decommissioning trust and other investments including those held in Dominion’s rabbi, pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above. These credit adjustments are currently not material to the derivative fair values.
The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, they seek price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, they consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases they must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect their market assumptions.
For options and contracts with option-like characteristics where observable pricing information is not available from external sources, the Companies generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. The Companies use other option models under special circumstances, including a Spread Approximation Model when contracts include different commodities or commodity locations and a Swing Option Model when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, the
Combined Notes to Consolidated Financial Statements, Continued
Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.
The inputs and assumptions used in measuring fair value include the following:
For commodity and foreign currency derivative contracts:

Forward commodity prices

Forward foreign currency prices

Price volatility

Volumes

Commodity location

Interest rates

Credit quality of counterparties and Dominion and Virginia Power

Credit enhancements

Time value
For interest rate derivative contracts:

Interest rate curves

Credit quality of counterparties and Dominion and Virginia Power

Credit enhancements

Time value
For investments:

Quoted securities prices and indices

Securities trading information including volume and restrictions

Maturity

Interest rates

Credit quality

NAV (only for alternative investments)
Dominion and Virginia Power regularly evaluate and validate the inputs used to estimate fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities and investments in which the Companies transact.
The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value, into three broad levels:

Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as the majority of exchange-traded derivatives, and exchange-listed equities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion.

Level 2-Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and
inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps, interest rate swaps, foreign currency forwards and options, certain Treasury securities, money market funds, and corporate, state and municipal debt securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion.

Level 3-Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for Dominion and Virginia Power consist of long-dated commodity derivatives, FTRs and other modeled commodity derivatives. Additional instruments categorized in Level 3 for Dominion include NGLs and natural gas peaking options and alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments, held in benefit plan trust funds.
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.
Fair value measurements are categorized as Level 3 when a significant amount of price or other inputs that are considered to be unobservable are used in their valuations. Long-dated commodity derivatives are generally based on unobservable inputs due to the length of time to settlement and the absence of market activity and are therefore categorized as Level 3. For NGL derivatives, market illiquidity requires a valuation based on proxy markets that do not always correlate to the actual instrument, therefore they are categorized as Level 3. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from ISO auctions, which are generally not considered to be liquid markets. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets. Alternative investments are categorized as Level 3 due to the absence of quoted market prices, illiquidity and the long-term nature of these assets. These investments are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date.
For derivative contracts, Dominion and Virginia Power recognize transfers among Level 1, Level 2 and Level 3 based on fair values as of the first day of the month in which the transfer occurs. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable
inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.
At December 31, 2011, Dominion’s and Virginia Power’s net balance of commodity derivatives categorized as Level 3 fair value measurements was a net liability of $71 million and $28 million, respectively. A hypothetical 10% increase in commodity prices would increase Dominion’s and Virginia Power’s net liability by $73 million and $2 million, respectively. A hypothetical 10% decrease in commodity prices would decrease Dominion’s and Virginia Power’s net liability by $74 million and $2 million, respectively.
Nonrecurring Fair Value Measurements
MERCHANT POWER STATIONS
In June 2010, Dominion evaluated State Line for impairment due to the station’s relatively low level of profitability combined with the EPA’s issuance of a new stringent 1-hour primary NAAQS for SO2 that would likely require significant environmental capital expenditures in the future. As a result of this evaluation, Dominion recorded an impairment charge of $163 million ($107 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of $59 million.
During March 2011, Dominion determined that it was unlikely that State Line would participate in the May 2011 PJM capacity base residual auction that would commit State Line’s capacity from June 2014 through May 2015. This determination reflected an expectation that margins for coal-fired generation will remain compressed in the 2014 and 2015 period in combination with the expectation that State Line may be impacted during the same time period by environmental regulations that would likely require significant capital expenditures. As a result, Dominion evaluated State Line for impairment since it was more likely than not that State Line would be retired before the end of its previously estimated useful life. As a result of this evaluation, Dominion recorded an impairment charge of $55 million ($39 million after-tax) reflected in other operations and maintenance expense in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of less than $1 million.
In December 2010, Dominion recorded an impairment charge of $31 million ($20 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down the long-lived assets of Salem Harbor to their estimated fair value of less than $1 million as a result of profitability issues.
As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of State Line’s and Salem Harbor’s long-lived assets in these impairment tests. These were considered Level 3 fair value measurements due to the use of significant unobservable inputs including estimates of future power and other commodity prices.
EMISSIONS ALLOWANCES
In September 2010, Virginia Power evaluated its SO2 emissions allowances not expected to be consumed by its generating units for potential impairment due to the significant decline in market prices since the July 2010 release of the EPA’s proposed replacement rule for CAIR, ultimately known as CSAPR. As a result of this evaluation, Virginia Power recorded an impairment charge of $13 million ($8 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down its SO2 emissions allowances not expected to be consumed to their estimated fair value of less than $1 million.
In the third quarter of 2011, Dominion and Virginia Power evaluated their SO2 emissions allowances not expected to be consumed by generating units for potential impairment due to the EPA’s issuance of CSAPR as discussed in Note 23. Prior to the issuance of CSAPR, Dominion and Virginia Power held $57 million and $43 million, respectively, of SO2 emissions allowances obtained for ARP and CAIR compliance. Due to CSAPR’s establishment of a new allowance program and the elimination of CAIR, Dominion and Virginia Power have more SO2 emissions allowances than needed for ARP compliance. As a result of this evaluation, Dominion and Virginia Power recorded an impairment charge of $57 million ($34 million after-tax) and $43 million ($26 million after-tax), respectively, in other operations and maintenance expense in their Consolidated Statements of Income, to write down these emissions allowances to their estimated fair value of less than $1 million.
To estimate the value of these emissions allowances in both impairment tests, Dominion utilized a market approach by obtaining broker quotes to validate CSAPR’s impact on emissions allowance prices. However, due to limited market activity for future SO2 vintage year allowances, these are considered a Level 3 fair value measurement.
Recurring Fair Value Measurements
Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion’s pension and other postretirement benefit plans are presented in Note 22.
Combined Notes to Consolidated Financial Statements, Continued
DOMINION
The following table presents Dominion’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
(1) Includes investments held in the nuclear decommissioning and rabbi trusts.
The following table presents the net change in Dominion’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
The following table presents Dominion’s gains and losses included in earnings in the Level 3 fair value category:
VIRGINIA POWER
The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
(1) Includes investments held in the nuclear decommissioning trusts.
The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
The gains and losses included in earnings in the Level 3 fair value category, including those attributable to the change in unrealized gains and losses relating to assets still held at the reporting date, were classified in electric fuel and other energy-related purchases expense in Virginia Power’s Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended 2011, 2010 and 2009.
Fair Value of Financial Instruments
Substantially all of Dominion’s and Virginia Power’s financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, customer and other receivables, short-term debt and accounts payable are representative of fair value because of the short-term nature of these instruments. For Dominion’s and Virginia Power’s financial instruments that are not recorded at fair value, the 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.
Combined Notes to Consolidated Financial Statements, Continued
(2) Includes amounts which represent the unamortized discount and premium. At December 31, 2011, and 2010, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt, of approximately $105 million and $49 million, respectively.
(3) Includes amounts which represent the unamortized premium.
(4) Includes issuance expenses of $2 million at December 31, 2011 and 2010.
NOTE 8. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES
Dominion and Virginia Power are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as currency exchange and interest rate risks of their business operations. The Companies use derivative instruments to manage exposure to these risks, and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes. As discussed in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivatives are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings. See Note 7 for further information about fair value measurements and associated valuation methods for derivatives.
DOMINION
The following table presents the volume of Dominion’s derivative activity as of December 31, 2011. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.
(1) Includes options.
(2) Includes NGLs and oil.
Selected information about Dominion’s hedge accounting activities follows:
(1) For the year ended December 31, 2011, includes $(1) million recorded in purchased gas and $(4) million recorded in operating revenue in Dominion’s Consolidated Statement of Income. For the year ended December 31, 2010, includes $(1) million recorded in purchased gas and $4 million recorded in operating revenue in Dominion’s Consolidated Statement of Income. For the year ended December 31, 2009, includes $(5) million recorded in purchased gas and $1 million recorded in operating revenue in Dominion’s Consolidated Statement of Income.
(2) For the year ended December 31, 2011, includes $(5) million recorded in purchased gas and $1 million recorded in operating revenue in Dominion’s Consolidated Statement of Income. For the year ended December 31, 2010, includes $(3) million recorded in purchased gas and $2 million recorded in operating revenue in Dominion’s Consolidated Statement of Income.
(3) Amounts excluded from the measurement of ineffectiveness related to cash flow hedges for the years ended December 31, 2011, 2010 and 2009 were not material.
(4) For the year ended December 31, 2011, amount was recorded in operating revenue in Dominion’s Consolidated Statement of Income. For the year ended December 31, 2009, includes $22 million recorded in operating revenue and $1 million recorded in electric fuel and other energy-related purchases in Dominion’s Consolidated Statement of Income.
The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at December 31, 2011:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.
The sale of the majority of Dominion’s remaining E&P operations resulted in the discontinuance of hedge accounting for certain cash flow hedges in 2010, as discussed in Note 4.
In addition, changes to Dominion’s financing needs during the first and second quarters of 2010 resulted in the discontinuance of hedge accounting for certain cash flow hedges since it was determined that the forecasted interest payments would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a benefit recorded to interest and related charges reflecting the reclassification of gains from AOCI to earnings of $110 million ($67 million after-tax) for 2010. The reclassification of gains from AOCI to earnings was partially offset by subsequent changes in fair value for these contracts of $37 million ($23 million after-tax) for 2010.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Dominion’s derivatives and where they are presented in its Consolidated Balance Sheets:
(1) Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheets.
(2) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheets.
The following tables present the gains and losses on Dominion’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
(1) Amounts deferred into AOCI have no associated effect in Dominion’s Consolidated Statements of Income.
(2) Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income.
(3) Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges.
(4) Amounts recorded in Dominion’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.
Combined Notes to Consolidated Financial Statements, Continued
(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income.
(2) Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges.
VIRGINIA POWER
The following table presents the volume of Virginia Power’s derivative activity at December 31, 2011. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.
For the years ended December 31, 2011, 2010 and 2009, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to the time value of options and changes in the differences between spot prices and forward prices.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:
(1) Current derivative assets are presented in other current assets in Virginia Power’s Consolidated Balance Sheets.
(2) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheets.
The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
(1) Amounts deferred into AOCI have no associated effect in Virginia Power’s Consolidated Statements of Income.
(2) Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.
(3) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges.
(4) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.
(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.
(2) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.
(3) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges.
NOTE 9. EARNINGS PER SHARE
The following table presents the calculation of Dominion’s basic and diluted EPS:
(1) Potentially dilutive securities consist of options, goal-based stock and contingently convertible senior notes.
Combined Notes to Consolidated Financial Statements, Continued
Potentially dilutive securities with the right to acquire approximately 1.2 million common shares for the year ended December 31, 2009 were not included in the calculation of diluted EPS because the exercise or purchase prices of those instruments were greater than the average market price of Dominion’s common shares. There were no potentially dilutive securities excluded from the calculation of diluted EPS for the years ended December 31, 2011 and 2010.
NOTE 10. INVESTMENTS
DOMINION
Equity and Debt Securities
RABBI TRUST SECURITIES
Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled $90 million and $93 million at December 31, 2011 and 2010, respectively. Net unrealized losses on trading securities totaled less than $1 million in 2011. Net unrealized gains on trading securities totaled $5 million and $11 million in 2010 and 2009, respectively. Cost-method investments held in Dominion’s rabbi trusts totaled $17 million and $18 million at December 31, 2011 and 2010, respectively.
DECOMMISSIONING TRUST SECURITIES
Dominion holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below.
(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.
(2) Includes pending purchases of securities of $11 million and $43 million at December 31, 2011 and 2010, respectively.
(3) The fair value of securities in an unrealized loss position was $164 million and $252 million at December 31, 2011 and 2010, respectively.
The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at December 31, 2011 by contractual maturity is as follows:
Presented below is selected information regarding Dominion’s marketable equity and debt securities held in nuclear decommissioning trust funds.
(1) The increase in proceeds primarily reflects the replacement of commingled funds with actively managed portfolios. Does not include
$1 billion of proceeds reflected in Dominion’s Consolidated Statement of Cash Flows from the sale of temporary investments consisting of time deposits and Treasury Bills, purchased following the sale of substantially all of Dominion’s Appalachian E&P operations.
(2) Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2.
Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:
(1) Amounts include other-than-temporary impairment losses for debt securities of $6 million, $10 million and $13 million at December 31, 2011, 2010 and 2009, respectively.
Equity Method Investments
Investments that Dominion accounts for under the equity method of accounting are as follows:
Dominion’s equity earnings on these investments totaled $35 million in 2011 and $42 million in 2010 and 2009. Excluding a $123 million distribution in 2009 from Fowler Ridge, Dominion received distributions from these investments of $55 million, $60 million and $63 million in 2011, 2010, and 2009, respectively. As of December 31, 2011 and 2010, the carrying amount of Dominion’s investments exceeded Dominion’s share of underlying equity in net assets by approximately $32 million and $7 million, respectively. The differences relate to Dominion’s investments in wind projects and primarily reflect its capitalized interest during construction and the excess of its cash contributions over the book value of development assets contributed by Dominion’s partners for these projects. The differences are generally being amortized over the useful lives of the underlying assets.
VIRGINIA POWER
Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below.
(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.
(2) Includes pending purchases of securities of $13 million and $35 million at December 31, 2011 and 2010, respectively.
(3) The fair value of securities in an unrealized loss position was $99 million and $159 million at December 31, 2011 and 2010, respectively.
Combined Notes to Consolidated Financial Statements, Continued
The fair value of Virginia Power’s debt securities at December 31, 2011, by contractual maturity is as follows:
Presented below is selected information regarding Virginia Power’s marketable equity and debt securities.
(1) The increase in proceeds primarily reflects the replacement of commingled funds with actively managed portfolios.
(2) Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2.
Virginia Power recorded other-than-temporary impairment losses on investments as follows:
(1) Amounts include other-than-temporary impairment losses for debt securities of $4 million, $6 million and $7 million at December 31, 2011, 2010 and 2009, respectively.
Other Investments
Dominion and Virginia Power hold restricted cash and cash equivalent balances that primarily consist of money market fund investments held in trust for the purpose of funding certain qualifying construction projects. At December 31, 2011 and 2010, Dominion had $147 million and $415 million, respectively, and Virginia Power had $32 million and $169 million, respectively, of restricted cash and cash equivalents. These balances are presented in Other Current Assets and Investments in the Consolidated Balance Sheets.
NOTE 11. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment and their respective balances for the Companies are as follows:
(1) 2011 amount includes $957 million due to consolidation of a VIE.
Jointly-Owned Power Stations
Dominion’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2011 is as follows:
(1) Units jointly owned by Virginia Power.
(2) Unit jointly owned by Dominion.
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.
NOTE 12. GOODWILL AND INTANGIBLE ASSETS
Goodwill
In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The sale resulted in an after-tax loss of approximately $140 million, which included a $79 million write-off of goodwill.
In April 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. The transaction resulted in an after-tax gain of approximately $1.4 billion, which included a $134 million write-off of goodwill.
The changes in Dominion’s carrying amount and segment allocation of goodwill are presented below:
(1) Goodwill amounts do not contain any accumulated impairment losses.
Combined Notes to Consolidated Financial Statements, Continued
Other Intangible Assets
Dominion’s and Virginia Power’s other intangible assets are subject to amortization over their estimated useful lives. Dominion’s amortization expense for intangible assets was $78 million, $107 million and $155 million for 2011, 2010 and 2009, respectively. In 2011, Dominion acquired $124 million of intangible assets, primarily representing software and licenses, with an estimated weighted-average amortization period of approximately 11 years. Amortization expense for Virginia Power’s intangible assets was $22 million for 2011, and $26 million for both 2010 and 2009. In 2011, Virginia Power acquired $26 million of intangible assets, primarily representing software and licenses, with an estimated weighted-average amortization period of 11 years. The components of intangible assets are as follows:
Annual amortization expense for these intangible assets is estimated to be as follows:
NOTE 13. REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities include the following:
(1) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power’s generation operations. See Note 14 for more information.
(2) Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain riders. See Note 14 for more information.
(3) Reflects unrecovered gas costs at Dominion’s regulated gas operations, which are recovered through quarterly or annual filings with the applicable regulatory authority.
(4) As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.
(5) Amounts to be recovered through an annual surcharge to reimburse Virginia Power for incremental sales taxes being incurred due to the repeal of the public service company sales tax exemption in Virginia.
(6) Reflects costs anticipated to be recovered in base rates for certain coal units expected to be retired.
(7) Under PIPP, eligible customers can receive energy assistance based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rider according to East Ohio tariff provisions. See Note 14 for more information regarding PIPP.
(8) Represents unrecognized pension and other postretirement benefit costs expected to be recovered through future rates by certain of Dominion’s rate-regulated subsidiaries.
(9) Amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes.
(10) Primarily reflects costs recognized in excess of amounts included in regulated rates charged by Dominion’s regulated gas operations before rates were updated to reflect a change in accounting method for other postretirement benefit costs.
(11) Reflects a reserve associated with the settlement of Virginia Power’s 2009 base rate case proceedings and associated with the Biennial Review Order. See Note 14 for more information.
(12) Rates charged to customers by the Companies’ regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.
(13) Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related ARO.
At December 31, 2011, approximately $198 million of Dominion’s and $127 million of Virginia Power’s regulatory assets represented past expenditures on which they do not currently earn a return. Dominion’s expenditures primarily include deferred cost of fuel used in electric generation. The above expenditures are expected to be recovered within the next two years.
NOTE 14. REGULATORY MATTERS
As a result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in
excess of the accrued liability (if any) for such matters. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss does not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on Dominion’s or Virginia Power’s financial position, liquidity or results of operations. The following is a discussion of Dominion’s and Virginia Power’s material pending and recent regulatory matters.
Electric Regulation in Virginia
The enactment of the Regulation Act in 2007 significantly changed electric service regulation in Virginia by instituting a modified cost-of-service rate model. With respect to most classes of customers, the Regulation Act ended Virginia’s planned transition to retail competition for its electric supply service.
The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It provides for enhanced returns on capital expenditures on specific new generation projects, including but not limited to combined cycle gas generation, nuclear generation, clean coal/carbon capture compatible generation, and renewable generation projects. The Regulation Act also continues statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.
If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.
2009 Base Rate Review
Pursuant to the Regulation Act, the Virginia Commission initiated a review of Virginia Power’s base rates, terms and conditions in 2009, including a review of Virginia Power’s earnings for test year 2008. In March 2010, the Virginia Commission issued the Virginia Settlement Approval Order, thus concluding the 2009 case and resolving open issues relating to Virginia Power’s base rates, fuel factor and Riders R, S, T, C1 and C2. Virginia Power’s fourth quarter 2009 results included a charge of $782 million ($477 million after-tax) as a result of the 2009 Base Rate Review. Dominion’s 2009 results include an additional charge of $12 million ($8 million after-tax) recorded in other operations and maintenance expense, reflecting the write-off of previously deferred RTO costs since recovery was no longer probable based on the 2009 Base Rate Review.
2011 Biennial Review
Pursuant to the Regulation Act and the Virginia Settlement Approval Order, in March 2011, Virginia Power submitted its base rate filing and accompanying schedules in support of the first biennial review of its base rates, terms and conditions, as well as of its earnings for the 2009 and 2010 test period. The biennial review included a determination of whether Virginia Power’s
Combined Notes to Consolidated Financial Statements, Continued
earnings for the 2009 and 2010 combined test years were within 50 basis points of the authorized ROE of 11.9% established in the Virginia Settlement Approval Order, as well as authorization of an ROE which will be applicable to base rates and Riders R, S, C1 and C2 and which will be used to measure base rate earnings during the 2013 biennial review proceeding. As a result of the Virginia Settlement Approval Order and the Regulation Act, Virginia Power’s base rates are not subject to change based on the 2011 biennial review. In November 2011, the Virginia Commission issued the Biennial Review Order.
Base ROE
The Virginia Commission determined that Virginia Power’s new authorized ROE is 10.9%, inclusive of a performance incentive of 50 basis points for meeting certain RPS targets. Subject to the outcome of Virginia Power’s petition for rehearing or reconsideration described below, this ROE will serve as the ROE against which Virginia Power’s earned return will be compared for all or part of the test periods in the 2013 biennial review proceeding. The Virginia Commission ordered that the 50 basis point RPS performance incentive will not be included in the ROE applicable to any rate adjustment clauses. The Virginia Commission declined to award a performance incentive for generating plant performance, customer service or operating efficiency in connection with this biennial review, but instead will initiate a rulemaking proceeding to develop performance incentive criteria to be applied in future biennial review proceedings.
In December 2011, Virginia Power filed a petition with the Virginia Commission seeking rehearing or reconsideration of the Biennial Review Order, to confirm the effective date of the newly authorized 10.9% base ROE. In December 2011, Virginia Power also filed a Notice of Appeal with the Virginia Commission of the Biennial Review Order to the Supreme Court of Virginia.
ROE Applicable to Riders C1, C2, R, and S
Effective December 1, 2011, the ROE applicable to Riders C1 and C2 is 10.4%. An ROE of 11.3% applied through November 30, 2011.
For Riders R and S, effective December 1, 2011, the ROE is 11.4%, inclusive of a statutory enhancement of 100 basis points. An ROE of 12.3%, inclusive of a statutory enhancement of 100 basis points, applied through November 30, 2011.
Earned Return for 2009 and
The Virginia Commission determined that Virginia Power earned an ROE of approximately 13.3% during the 2009 and 2010 combined test years, which exceeded the authorized ROE earnings band of 11.4% to 12.4% established in the Virginia Settlement Approval Order. Based on the determination that Virginia Power had excess earnings, the Virginia Commission ordered Virginia Power to refund 60% of earnings above the upper end of the authorized ROE earnings band, or approximately $78 million, to its customers, which is being provided in the form of credits to customers’ bills amortized over a six-month period during 2012. A charge for the refund was recognized in operating revenues in the 2011 Consolidated Statement of Income. The actual aggregate refund amount is expected to total approximately $81 million, taking into account refunds to be paid to certain non-jurisdictional customers pursuant to their customer contracts.
Base Rates and Existing Riders T, C1, and C2
As a result of the Virginia Commission’s determination that credits will be applied to customers’ bills, the Virginia Commission, as required by the Regulation Act, directed Virginia Power to combine its existing Riders T, C1, and C2 with Virginia Power’s base costs, revenues and investments, and to file revised tariffs reflecting such combination pursuant to the Biennial Review Order. These Riders will thereafter be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings. The Virginia Commission has initiated a proceeding to address further implementation of this directive. Virginia Power’s base rates will otherwise remain unchanged through at least December 1, 2013.
Earnings Test Adjustments
The Virginia Commission ruled on numerous contested proposals to adjust Virginia Power’s earnings for the 2009 and 2010 combined test periods. Among other adjustments, the Virginia Commission approved Virginia Power’s ratemaking treatment of fuel inventories held by its wholly-owned subsidiaries. As a result of this finding, Virginia Power included in rate base approximately $177 million and $188 million in fuel inventory costs for 2009 and 2010, respectively. The Virginia Commission also adopted Virginia Power’s treatment that includes, for regulatory earnings purposes, its AIP and LTIP expenses up to a 100% payout ratio. The Virginia Commission excluded from expense approximately $21 million in incentive plan costs that exceeded a payout ratio of 100%, allowing a net recovery of approximately $95 million of incentive compensation expense for the biennial review period. The Virginia Commission denied Virginia Power’s ratemaking treatment that expensed the entire cost of its 2010 voluntary separation plan in 2010, ruling instead to amortize the cost through the end of 2011. This matches the costs of the plan with the period of realization of savings, which reduces 2010 operating costs (and, in turn, increases 2011 operating costs) by approximately $103 million for purposes of the earnings test. Other than influencing the amount earned above the authorized ROE earnings band, the earnings test adjustments above did not have an impact to the Consolidated Financial Statements.
In addition, the Virginia Commission required Virginia Power to recognize a gain, for purposes of the earnings test, of approximately $44 million on the settlement of certain interest rate hedging contracts in 2010, as opposed to amortizing the gains over the forecasted term of planned debt instruments that were not issued. Virginia Power determined that it was no longer probable that these derivative gains would be included in future base rates as the Virginia Commission would not allow the amortization of these amounts in future periods. As a result, Virginia Power removed approximately $50 million in December 2011 from regulatory liabilities and recognized the deferred derivative settlement gains in Interest and Other Charges in the Consolidated Statements of Income.
Virginia Fuel Expenses
In May 2011, Virginia Power submitted its annual fuel factor filing to the Virginia Commission, proposing an annual increase for the rate year beginning July 1, 2011. This revised factor included a projected $434 million balance of prior year under- recovered fuel expenses. To reduce the impact to customers, as an alternative, Virginia Power proposed to recover this projected
prior year deferred fuel balance over a two-year period beginning July 1, 2011. In June 2011, the Virginia Commission approved the two-year recovery proposal, resulting in an increase of approximately $319 million in annual fuel revenue for the rate year beginning July 1, 2011. The rate increase is designed to recover $217 million of unrecovered fuel expenses from the prior fuel year as well as a $102 million increase in anticipated fuel expenses for the 2012 fuel year.
Generation Riders R and S
In connection with the Bear Garden and Virginia City Hybrid Energy Center projects, in March 2011, the Virginia Commission approved annual updates for Riders R and S with revenue requirements of $78 million and $199 million, respectively, for the April 1, 2011 to March 31, 2012 rate year, utilizing the 12.3% placeholder ROE (inclusive of a 100 basis point statutory enhancement) pending the Virginia Commission’s ROE determination in the 2011 biennial review. Virginia Power’s proposed revenue requirements for Riders R and S for the April 1, 2012 to March 31, 2013 rate year were adjusted to approximately $76 million and $231 million, respectively, and are pending final Virginia Commission approval. Future annual updates for Riders R and S will provide revenue requirements reflecting any true-ups to revenue requirements approved for the previous calendar year, including the ROE determined in the Biennial Review Order. Construction of Bear Garden was completed and the facility commenced commercial operations in the second quarter of 2011.
DSM Riders C1 and C2
In connection with Virginia Power’s five DSM programs approved by the Virginia Commission, in March 2011, the Virginia Commission approved the annual updates for Riders C1 and C2 with revenue requirements of approximately $6 million and $12 million, respectively, for the April 1, 2011 to March 31, 2012 rate year, utilizing an 11.3% placeholder ROE pending the Virginia Commission’s ROE determination in the 2011 biennial review. By order issued in June 2011, the Virginia Commission extended the rates through April 2012.
In September 2011, Virginia Power filed with the Virginia Commission an application for approval of six new energy efficiency DSM programs, along with an annual update to Riders C1 and C2. Virginia Power’s proposed revenue requirement for the May 1, 2012 through April 30, 2013 rate year is approximately $72 million, as amended in February 2012 to reflect, along with other adjustments, the determination of a 10.4% ROE applicable to Riders C1 and C2 in the Biennial Review Order. As discussed above, previously implemented Riders C1 and C2 will be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings, and the Virginia Commission has initiated a proceeding to address further implementation of this directive.
Transmission Rider T
In May 2011, Virginia Power filed its annual update to Rider T with the Virginia Commission. The proposed $481 million annual revenue requirement, effective September 1, 2011, represented an increase of approximately $144 million over the revenue requirement associated with the Rider T customer rates previously in effect. In July 2011, the Virginia Commission issued
an order approving a revenue requirement of $466 million for the September 1, 2011 to August 31, 2012 rate year. As discussed above, previously implemented Rider T will be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings, and the Virginia Commission has initiated a proceeding to address further implementation of this directive.
Generation Rider W
In May 2011, Virginia Power requested approval from the Virginia Commission to construct and operate Warren County, as well as approval of Rider W. In February 2012, the Virginia Commission approved Certificates of Public Convenience and Necessity for Warren County and related transmission facilities. The Virginia Commission also approved Virginia Power’s proposed revised revenue requirement of $35 million for the April 1, 2012 to March 31, 2013 rate year, reflecting an ROE of 11.4%, inclusive of a statutory enhancement of 100 basis points for Rider W, consistent with the Biennial Review Order. In addition, the Virginia Commission approved an ROE enhancement of 100 basis points for Rider W for a period of 10 years following commercial operations. The facility is expected to start commercial operations in late 2014.
Generation Rider B
In June 2011, Virginia Power filed applications with the Virginia Commission seeking regulatory approval to convert three of its coal-fired power stations to biomass. The applications included a request for approval of Rider B. Virginia Power’s proposed revenue requirement for Rider B is approximately $6 million for the April 1, 2012 to March 31, 2013 rate year, as adjusted to reflect the base ROE authorized in the Biennial Review Order, and inclusive of a renewable generating unit statutory enhancement of 200 basis points. To qualify for federal production tax credits associated with renewable energy generation, the power stations must commence operation as biomass generation facilities by December 31, 2013. Virginia Power has requested Virginia Commission approval of the biomass conversions on a schedule that will enable qualification for these tax credits.
Solar Distributed Generation Demonstration Program
In October 2011, Virginia Power filed with the Virginia Commission an application to conduct a solar distributed generation demonstration program, consisting of up to a combined 30 MW of Company-owned solar distributed generation facilities to be located at selected commercial, industrial and community locations throughout its Virginia service territory, as well as up to a combined 3 MW of customer-owned solar distributed generation facilities that will be subject to a tariff filed with the Virginia Commission in 2012. Virginia Power proposed to construct and operate the Company-owned facilities in two phases, with Phase I (up to 10 MW) from the date of approval through the end of 2013 and Phase II (up to 20 MW) from the beginning of 2014 to the end of 2015. Virginia Power did not seek a rate adjustment clause for Phase I facilities with this filing; Phase I costs will be recovered as part of base rates in a future biennial review. Virginia Power indicated that it may seek a rate adjustment clause at a future time for Phase II costs.
Combined Notes to Consolidated Financial Statements, Continued
Electric Transmission Projects
Portions of the Mt. Storm-to-Doubs line and certain associated facilities are approaching the end of their expected service lives and require replacement with new facilities to maintain reliable service. Virginia Power owns, and has been designated by PJM to rebuild, 96 miles of the line in West Virginia and Virginia, and The Potomac Edison Company owns, and has been designated by PJM to rebuild, the remaining three miles of the line in Maryland. In September 2011, the Virginia Commission approved Virginia Power’s application to rebuild its portion of the Mt. Storm-to-Doubs line. The approval of the West Virginia Commission was not required. Subject to applicable state and federal regulatory approvals, Virginia Power’s portion of the rebuild project is expected to be completed by June 2015.
In October 2008, the Virginia Commission authorized construction of the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line. The Meadow Brook-to-Loudoun line was placed in service in April 2011 and the Carson-to-Suffolk line was placed in service in May 2011.
In June 2010, the Virginia Commission authorized the construction of the Hayes-to-Yorktown line along the proposed eight-mile route utilizing existing easements and property previously acquired for the transmission line right-of-way. In accordance with the Virginia Commission’s approval, approximately 4.2 miles of the Hayes-to-Yorktown line will be constructed overhead and approximately 3.8 miles will be installed underground in order to cross under the York River. The Hayes-to-Yorktown line is expected to be completed by June 2012.
In January 2012, the Virginia Commission authorized the replacement at higher voltage of approximately 43 miles of existing transmission lines between the Dooms and Bremo substations. Subject to the receipt of other applicable state and federal regulatory approvals, Dooms-to-Bremo is expected to be completed by May 2014.
In December 2011, Viginia Power submitted an application to the Virginia Commission for approval of the Waxpool-Brambleton-BECO line. This project is required to provide requested service to a new datacenter campus in Loudoun County, Virginia. Virginia Power expects PJM to authorize Waxpool-Brambleton-BECO as part of the 2012 RTEP within the first half of 2012. Subject to the receipt of applicable state and federal regulatory approvals, Waxpool-Brambleton-BECO is expected to be completed by November 2013.
North Anna Power Station
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna, which Virginia Power owns along with ODEC. In May 2010, Virginia Power announced its decision to replace the reactor design previously selected for the potential third nuclear unit with the US-APWR technology. In June 2010, Virginia Power and ODEC amended the COL application to reflect the selection of the US-APWR technology. In January 2011, Virginia Power and the DOE terminated their cooperative agreement to share equally the cost of developing a COL. The agreement references the technology previously selected by Virginia Power. DOE funding related to COL development activities is not available under the agreement for activities related to the US-APWR technology. In February 2011, ODEC informed Virginia Power of its intent to no longer partic-
ipate in the development of a potential new unit at North Anna. In December 2011, Virginia Power acquired ODEC’s interest in the project, thereby terminating ODEC’s involvement in the development of a potential third unit at North Anna.
Virginia Power has not yet committed to building a new nuclear unit at North Anna. If Virginia Power decides to build the new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power continues to pursue the COL from the NRC. Based on the current NRC schedule, the COL could be issued as early as late 2014.
The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the ASLB of the NRC permitted BREDL to intervene in the proceeding. All of BREDL’s previous contentions in this proceeding have been dismissed. In September 2011, BREDL submitted a new proposed contention seeking to litigate issues related to the August 2011 Mineral, Virginia earthquake. In October 2011, the ASLB granted a motion filed by Virginia Power, with the consent of BREDL and the NRC staff to hold any ruling on this proposed contention in abeyance until Virginia Power completes an assessment of this earthquake. No other persons have sought to intervene in the proceeding. If a new contention is not admitted, the mandatory NRC hearing will be uncontested with respect to other issues.
On April 14, 2011, twenty-one organizations and individuals that had previously intervened opposing various reactor licensing proceedings filed a petition requesting that the NRC suspend all decisions regarding reactor licensing and design certification pending completion of an NRC task force review of the events at Fukushima, Japan, among other requested relief. The North Anna 3 COL proceeding is one of the pending proceedings identified in this petition, and BREDL served the petition in the North Anna 3 COL proceeding on April 18, 2011. In September 2011, the NRC denied the petitioners’ requests to suspend licensing and design certification proceedings. The only relief granted was the petitioners’ request that the NRC perform a safety analysis of the regulatory implications of the Fukushima event to the extent it is doing so.
Virginia Power continues to pursue various environmental permits that would be needed to support future construction and operation of a third nuclear unit at North Anna.
North Carolina Regulation
In February 2010, in preparation for the end of a five-year moratorium on Virginia Power’s North Carolina base rates, Virginia Power filed an application with the North Carolina Commission to increase its base rates and adjust its fuel rates. In December 2010, the North Carolina Commission issued the North Carolina Settlement Approval Order approving a settlement agreement among all parties to the base rate and fuel case except one, which did not oppose the settlement. The North Carolina Settlement Approval Order authorized an increase in base revenues of approximately $8 million. In addition, the North Carolina Settlement Approval Order allowed the recovery through fuel rates of 85% of the net energy costs of power purchases from both PJM and other wholesale suppliers and from the non-utility generators subject to economic dispatch that do not provide actual cost data. The North Carolina Settlement Approval Order authorized an ROE of 10.7% and a capital structure composed of
49% long-term debt and 51% common equity. The new base and fuel rates became effective on January 1, 2011.
In December 2011, the North Carolina Commission issued an order approving a settlement agreement among Virginia Power, the Public Staff of the North Carolina Commission and other interested parties in Virginia Power’s fuel case for its North Carolina service territory. The settlement agreement provides for a $36 million increase in Virginia Power’s fuel revenues for one year, effective January 1, 2012, including approximately $13 million in under recovery of fuel expenses for the previous fuel period.
Virginia Power intends to file an application with the North Carolina Commission by March 30, 2012, to increase base rates.
Ohio Regulation
PIR Program
In March 2011, East Ohio filed a request with the Ohio Commission to accelerate the PIR program by nearly doubling its PIR spending to more than $200 million annually. East Ohio identified 1,450 miles of pipeline that need to be replaced, in addition to the pipeline originally identified in the PIR project scope. East Ohio plans to accelerate the pace of the program by investing more resources in its infrastructure in the near term, in an effort to promote ongoing public safety and reduce operating costs over the longer term. In August 2011, the Ohio Commission approved the stipulation by East Ohio, the Staff of the Ohio Commission and other interested parties in East Ohio’s accelerated PIR proceeding. The stipulation provides for an increase in annual PIR capital investment from the current level of approximately $120 million stepping up to approximately $160 million by 2013. In addition, the stipulation provides for cost recovery over a five-year period commencing upon the approval of the Ohio Commission. In accordance with the stipulation, East Ohio requested the dismissal of its appeal at the Ohio Supreme Court regarding its opposition to the Ohio Commission’s order concerning East Ohio’s first year PIR cost recovery charge.
In August 2011, East Ohio submitted its annual application to adjust the cost recovery charge under the previously approved PIR program. A supplement to the application was filed in September 2011. The proposed recovery charge includes actual costs and a return related to investments made through June 30, 2011. A settlement agreement approved by the Ohio Commission in October 2011 supports the revenue requirement of $37 million reflected in the application.
PIPP Plus Program
Under the Ohio PIPP Plus program, eligible customers can receive energy assistance based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP plan payment amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. The PIPP Plus program sets the customer’s monthly payments at 6% of household income and provides for forgiveness credits to the customer’s balance when required payments are received in full by the due date. Such credits may result in the elimination of the customer’s arrearage balance over 24 months.
In March 2011, the Ohio Commission approved East Ohio’s annual update of the PIPP Rider, which reflected the elimination of accumulated arrearages and projected deferred program costs of approximately $112 million for the 12-month period from April 2011 to March 2012.
UEX Rider
East Ohio files an annual UEX Rider with the Ohio Commission, pursuant to which it seeks recovery of the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar-for-dollar recovery of East Ohio’s actual write-offs of uncollectable amounts. In 2011, East Ohio deferred approximately $62 million of bad debt expense for recovery through the UEX Rider.
House Bill 95
Ohio enacted utility reform legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future. In December 2011, East Ohio filed an application requesting authority to implement a capital expenditure program under the new law. If the application is approved, East Ohio would be able to defer as a regulatory asset carrying costs, depreciation and property tax associated with approximately $95 million in capital expenditures for assets placed in service but not yet reflected in rates.
Federal Regulation
FERC-Electric
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominion’s merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion’s market-based sales tariffs authorized by FERC. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.
Rates
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
In July 2008, Virginia Power filed an application with FERC requesting a revision to its revenue requirement to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 1.5% for four of the
Combined Notes to Consolidated Financial Statements, Continued
projects (including the Meadow Brook-to-Loudoun and Carson-to-Suffolk lines, which were completed in 2011) and an incentive of 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008. The total cost for all eleven projects is estimated at $877 million, and all projects are currently expected to be completed by 2012. Numerous parties sought rehearing of the FERC order in August 2008, and rehearing is pending. Although Virginia Power cannot predict the outcome of the rehearing, it is not expected to have a material effect on results of operations.
In March 2010, ODEC and NCEMC filed a complaint with FERC against Virginia Power claiming that approximately $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. ODEC and NCEMC requested that FERC establish procedures to determine the amount of costs for each applicable project that should be excluded from Virginia Power’s rates. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. In February 2012, Virginia Power submitted to FERC a settlement agreement to resolve all issues set for hearing. All transmission customer parties to the proceeding joined the settlement. The Virginia Commission, North Carolina Commission and Public Staff of the North Carolina Commission, while not parties to the settlement, have agreed to not oppose the settlement. If accepted by FERC, the settlement provides for payment by Virginia Power to the transmission customer parties of $250,000 per year for ten years and resolves all matters other than the incremental cost of certain underground transmission facilities, which will be set for briefing. While Virginia Power cannot predict the outcome of the briefing, it is not expected to have a material effect on results of operations.
PJM
For recovery of costs of investments of new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a regional rate design where all customers pay a uniform rate based on the costs of such investment. For recovery of costs of investment in new PJM-planned transmission facilities that operate below 500 kV, FERC affirmed its earlier decision to allocate costs on a beneficiary pays approach. A notice of appeal of this decision was filed in February 2008 at the U.S. Court of Appeals for the Seventh Circuit. In August 2009, the court denied the petition for review concerning the rate design for existing facilities, but granted the petition concerning the rate design for new facilities that operate at or above 500 kV, and remanded the issue of existing facilities back to FERC for further proceedings. Although Dominion and Virginia Power cannot predict the outcome of the FERC proceedings on remand, the impact of any PJM rate design changes on the Companies’ results of operations is not expected to be material.
In May 2008, the RPM Buyers filed a complaint with FERC claiming that PJM’s Reliability Pricing Model’s transitional auctions have produced unjust and unreasonable capacity prices. The RPM Buyers requested that a refund effective date of June 1, 2008 be established and that FERC provide appropriate relief from unjust and unreasonable capacity charges within 15 months. In September 2008, FERC dismissed the complaint. The RPM
Buyers requested rehearing of the FERC order in October 2008 and rehearing was denied in June 2009. A notice of appeal was filed in August 2009 by the Maryland Public Service Commission and the New Jersey Board of Public Utilities at the U.S. Court of Appeals for the Fourth Circuit. In November 2009, the Court transferred the appeal to the Court of Appeals for the District of Columbia Circuit. In February 2011, the Court of Appeals denied the petition for review, concluding that FERC had adequately explained why the rates were just and reasonable.
In November 2011, PJM issued a formal notification that it would recalculate certain ancillary service revenues that had previously been paid during 2009, 2010 and 2011. Also in November 2011, PJM requested FERC permission to suspend its rebilling and repayment obligations associated with the recalculation of such revenues and petitioned FERC to establish a proceeding to determine the appropriate recalculations for the revenues during this period. In December 2011, FERC permitted the suspension of rebilling and repayment by PJM, subject to the outcome of FERC’s proceedings to determine the appropriate revenue recalculation. Virginia Power has accrued a liability of $36 million as of December 31, 2011 for estimated future billing adjustments from PJM related to the ancillary service revenues.
FERC-Gas
FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate natural gas company subsidiaries, including DTI, Cove Point and the Dominion South Pipeline Company, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.
In December 2007, DTI and the IOGA entered into a settlement agreement on DTI’s gathering and processing rates, which DTI and IOGA agreed in May 2010 to extend through December 31, 2014. DTI, at its option, may elect to extend the agreement for an additional year through December 31, 2015. The settlement extension maintains the gas retainage fee structure that DTI has had since 2001. The rates are 10.5% for gathering and 0.5% for processing. Under the settlement, DTI continues to retain all revenues from its liquids sales, thus maintaining cash flow from the liquids business. In October 2011, DTI requested and received FERC approval of the negotiated rates associated with the agreement extension.
In May 2011, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective July 1, 2011. Cove Point proposed an annual cost of service of approximately $150 million. In June 2011, FERC accepted a July 1, 2011 effective date for all proposed rates but two of which were suspended to be effective December 1, 2011. In December 2011, Cove Point, FERC trial staff and the other active parties in the rate case reached a settlement in principle on all issues set for hearing by FERC, as well as on all outstanding proposed tariff changes filed in May 2011. The parties expect to file the stipulation and agreement resolving all outstanding issues in the rate case in March 2012.
NOTE 15. ASSET RETIREMENT OBLIGATIONS
AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of Dominion’s and Virginia Power’s long-lived assets. Dominion’s and Virginia Power’s AROs are primarily associated with the decommissioning of their nuclear generation facilities. In addition, Dominion’s AROs include plugging and abandonment of gas and oil wells, interim retirements of natural gas gathering, transmission, distribution and storage pipeline components, and the future abatement of asbestos expected to be disturbed in the Companies’ generation facilities.
The Companies have also identified, but not recognized, AROs related to retirement of Dominion’s LNG facility, Dominion’s gas storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in the Companies’ generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 2010 and 2011 were as follows:
(1) Includes $9 million, $14 million and $15 million reported in other current liabilities at December 31, 2009, 2010, and 2011, respectively.
(2) Primarily reflects the effect of lower anticipated costs due to the expected future recovery from the DOE of certain spent fuel storage costs.
(3) Includes $1 million, $3 million and $1 million reported in other current liabilities at December 31, 2009, 2010 and 2011, respectively.
Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 2011 and 2010, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $3.0 billion and $2.9 billion, respectively. At December 31, 2011 and 2010, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.4 billion and $1.3 billion, respectively.
NOTE 16. VARIABLE INTEREST ENTITIES
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
Virginia Power has long-term power and capacity contracts with four non-utility generators with an aggregate summer generation capacity of approximately 870 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $1.3 billion as of December 31, 2011. Virginia Power paid $211 million, $213 million, and $210 million for electric capacity and $125 million, $164 million, and $117 million for electric energy to these entities for the years ended December 31, 2011, 2010 and 2009, respectively.
Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $389 million, $465 million, and $416 million for the years ended December 31, 2011, 2010 and 2009, respectively. Virginia Power determined that it is not the most closely associated entity with DRS and therefore not the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power. Virginia Power has no obligation to absorb more than its allocated share of DRS costs.
Dominion leases the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. Dominion makes annual lease payments of approximately $53 million. The lease expires in 2013 and, at that time, Dominion may renew the lease on terms mutually agreeable to Dominion and Juniper based on original project costs and current
Combined Notes to Consolidated Financial Statements, Continued
market conditions; purchase Fairless for approximately $923 million or sell Fairless, on behalf of Juniper, to an independent third party. If Fairless is sold and the proceeds from the sale are less than its original construction cost, Dominion would be required to make a payment to the lessor in an amount up to 70.75% of the original project costs adjusted for certain other costs as specified in the lease. The lease agreement does not contain any provisions that involve credit rating or stock price trigger events. Dominion expects to purchase Fairless when the lease expires in 2013.
Juniper was formed in 2003 as a limited partnership and was organized for the purpose of acquiring and constructing a number of assets for lease. Such assets were financed with proceeds from the issuance of bank debt, privately placed long-term debt and partnership capital received from Juniper’s general and limited partners. Dominion has no voting equity interest in Juniper. Because Juniper had been subject to the business scope exception, Dominion was not required to evaluate whether Juniper was a VIE prior to October 2011.
Through September 30, 2011, Juniper held various power plant leases, including Fairless. In October 2011, the last lease other than Fairless expired and the related asset was sold by Juniper. With Fairless being its sole remaining asset, Juniper no longer qualified as a business as of October 2011, which required that Dominion determine whether Juniper is a VIE. Dominion concluded Juniper is a VIE because the entity’s capitalization is insufficient to support its operations, the power to direct the most significant activities of the entity are not performed by the equity holders, and Dominion, through its residual value guarantee discussed above, guarantees a portion of the residual value of Fairless. The activities that most significantly impact Juniper’s economic performance relate to the operation of Fairless. The decisions related to the operations of Fairless are made by Dominion and as such, Dominion is considered the primary beneficiary.
Accordingly, Dominion consolidated Juniper in October 2011 and recorded, at fair value, approximately $957 million of property, plant and equipment, $896 million of debt and $61 million of noncontrolling interests. The debt is non-recourse to Dominion and is secured by Juniper’s assets. The annual lease payments made by Dominion to Juniper for Fairless are now eliminated in the Consolidated Statements of Income and are excluded from the lease commitments table in Note 23.
Dominion has not provided any financial or other support to Juniper in the current period that it was not previously contractually required to provide.
NOTE 17. SHORT-TERM DEBT AND CREDIT AGREEMENTS
Dominion and Virginia Power use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.
DOMINION
Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:
(1) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.
(2) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.
(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were 0.47% and 0.41% at December 31, 2011 and 2010, respectively.
VIRGINIA POWER
Virginia Power’s short-term financing is supported by two joint revolving credit facilities with Dominion. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion and Virginia Power and for other general corporate purposes.
Virginia Power’s share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion, were as follows:
(1) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016.
This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.
(2) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.
(3) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.46% and 0.41% at December 31, 2011 and 2010, respectively.
In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility that was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This facility supports certain tax-exempt financings of Virginia Power.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 18. LONG-TERM DEBT
(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2011.
(2) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. Certain variable rate tax-exempt financings are supported by a $120 million credit facility that terminates in September 2016.
(3) $160 million of tax-exempt bonds due in 2040 issued by the Industrial Development Authority of Wise County on behalf of Virginia Power were remarketed to a third party and included in the Consolidated Balance Sheets in March 2011. These bonds were originally issued in December 2010 and September 2009 but were not included in the 2010 Consolidated Balance Sheet because the bonds had been temporarily purchased and were held by Virginia Power.
(4) At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 and $600 million of Dominion’s 8.875% senior notes due 2019 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015 and January 2014, respectively.
(5) Convertible into a combination of cash and shares of Dominion’s common stock at any time when the closing price of common stock equals 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter. At the option of holders on December 15, 2013 or 2018, these securities are subject to redemption at 100% of the principal amount plus accrued interest. These senior notes have been callable by Dominion since December 15, 2011.
(6) In September 2011, the $500 million 6.3% 2006 Series B Enhanced Junior Subordinated Notes due 2066 began bearing interest at the three-month LIBOR plus 2.3%, reset quarterly.
(7) Represents debt assumed by Dominion from the merger of its former CNG subsidiary.
(8) Juniper notes issued in 2004 and consolidated in October 2011 due to Dominion becoming the primary beneficiary of this VIE. This amount excludes $48 million of net unamortized premium in 2011. The debt is non-recourse to Dominion and is secured by Juniper’s assets.
(9) Represents debt associated with Kincaid. The debt is non-recourse to Dominion and is secured by the facility’s assets ($530 million at December 31, 2011) and revenue.
(10) $235 million of tax-exempt bonds due in 2041 issued by the Massachusetts Development Finance Agency on behalf of Brayton Point were remarketed to third parties in July and August 2011, and included in the Consolidated Balance Sheet. These bonds were originally issued in December 2010 but were not included in the 2010 Consolidated Balance Sheet because the bonds had been temporarily purchased and were held by Dominion.
(11) Represents the valuation of certain fair value hedges associated with Dominion’s fixed-rate debt.
(12) Includes $4 million of net unamortized discount in 2011.
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, 2011, were as follows:
Dominion’s and Virginia Power’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2011, there were no events of default under these covenants.
In January 2012, Virginia Power issued $450 million of 2.95% senior notes that mature in 2022. The proceeds were used for general corporate purposes including the repayment of short-term debt.
Convertible Securities
At December 31, 2011, Dominion had $143 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominion’s common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. At issuance, the notes were valued at a conversion rate of 27.173 shares of common stock per $1,000 principal amount of senior notes, which represented a conversion price of $36.80. The conversion rate is subject to adjustment upon certain events such as subdivisions, splits, combinations of common stock or the issuance to all common stock holders of certain common stock rights, warrants or options and certain dividend increases. As of December 31, 2011, the conversion rate had been adjusted to 28.9178 shares, primarily due to individual dividend payments above the level paid at issuance.
The number of shares included in the denominator of the diluted EPS calculation is calculated as the net shares issuable for the reporting period based upon the average market price for the period. This results in an increase in the average shares outstanding used in the calculation of Dominion’s diluted EPS when the conversion price is lower than the average market price of Dominion’s common stock over the period, and results in no adjustment when the conversion price exceeds the average market price.
The senior notes are convertible by holders into a combination of cash and shares of Dominion’s common stock under any of the following circumstances:
(1) The closing price of Dominion’s common stock equals 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter;
(2) The senior notes are called for redemption by Dominion;
(3) The occurrence of specified corporate transactions; or
(4) The credit rating assigned to the senior notes by Moody’s is below Baa3 and by Standard & Poor’s is below BBB- or the ratings are discontinued for any reason.
The senior notes were not eligible for conversion during the first quarter of 2011. However, since the closing price of Dominion’s common stock was equal to 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days of each quarter, the senior notes were eligible for conversion during each of the last three quarters of 2011. During 2011, approximately $59 million of the contingent convertible senior notes were converted by holders. As of December 31, 2011, the closing price of Dominion’s common stock was equal to $41.50 per share or higher for at least 20 out of the last 30 consecutive trading days; therefore, the senior notes are eligible for conversion during the first quarter of 2012. Beginning in 2007, the notes have been eligible for contingent interest if the average trading price as defined in the indenture equals or exceeds 120% of the principal amount of the senior notes. Holders have the right to require Dominion to purchase these senior notes for cash at 100% of the principal amount plus accrued interest in December 2013 or 2018, or if Dominion undergoes certain fundamental changes. The senior notes have been callable by Dominion since December 15, 2011.
Junior Subordinated Notes Payable to Affiliated Trusts
In previous years, Dominion established several subsidiary capital trusts, each as a finance subsidiary of the respective parent company, which hold 100% of the voting interests. The trusts sold trust preferred securities representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trusts. In exchange for the funds realized from the sale of the trust preferred securities and common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trusts, Dominion issued various junior subordinated notes. The junior subordinated notes constitute 100% of each capital trust’s
Combined Notes to Consolidated Financial Statements, Continued
assets. Each trust must redeem its trust preferred securities when their respective junior subordinated notes are repaid at maturity or if redeemed prior to maturity.
The following table provides summary information about the trust preferred securities and junior subordinated notes outstanding as of December 31, 2011:
Junior subordinated notes/debentures held as assets by each capital trust were as follows:
(1) $258 million-Dominion Resources, Inc. 7.83% Debentures due 12/1/2027.
(2) $10 million-Dominion Resources, Inc. 8.4% Debentures due 1/15/2031.
Interest charges related to Dominion’s junior subordinated notes payable to affiliated trusts were $21 million for the years ended December 31, 2011, 2010 and 2009.
Distribution payments on the trust preferred securities are considered to be fully and unconditionally guaranteed by the respective parent company that issued the debt instruments held by each trust when all of the related agreements are taken into consideration. Each guarantee agreement only provides for the guarantee of distribution payments on the relevant 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 the payment of amounts by Dominion when they are due on the junior subordinated notes. Dominion may defer interest payments on the junior subordinated notes on one or more occasions for up to five consecutive years and the related trusts must also defer distributions. If the payment on the junior subordinated notes is deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments, during the deferral period. Also, during any deferral period, Dominion 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.
Enhanced Junior Subordinated Notes
In June 2006 and September 2006, Dominion issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids will bear interest at 7.5% per year until June 30, 2016. Thereafter, they will bear interest at the three-month LIBOR plus 2.825%, reset quarterly. Beginning September 30, 2011, the September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly. Previously, interest was fixed at 6.3% per year.
In June 2009, Dominion issued $685 million (including $60 million related to the underwriter’s option to purchase additional notes to cover over-allotments) of 8.375% June 2009 hybrids. The June 2009 hybrids are listed on the New York Stock Exchange under the symbol DRU.
Dominion may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.
Dominion executed RCCs in connection with its issuance of all of the hybrids described above. Under the terms of the RCCs, Dominion covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. In September 2011, Dominion amended the RCCs of the June 2006 hybrids and September 2006 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock issuances from 180 days to 365 days. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.
In both December 2011 and April 2010, Dominion purchased and cancelled $16 million of the September 2006 hybrids. These purchases were conducted in compliance with the RCC. In late February 2012, Dominion launched a tender offer to purchase up to $150 million of additional September 2006 hybrids, which amount may be increased or decreased at Dominion’s sole discretion. All purchases will be conducted in compliance with the RCC.
NOTE 19. PREFERRED STOCK
Dominion is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2011 or 2010.
Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference, and had 2.59 million preferred shares issued and outstanding at December 31, 2011 and 2010. Upon involuntary liquidation, dissolution or winding-up of Virginia Power, each share would be entitled to receive $100 plus accrued cumulative dividends.
Holders of Virginia Power’s 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, upon default in dividends or in special statutory proceedings and as required by Virginia law (such as mergers, consolidations, sales of assets, dissolution and changes in voting rights or priorities of preferred stock).
Presented below are the series of Virginia Power preferred stock that were outstanding as of December 31, 2011:
(1) Through 7/31/2012; $100.36 commencing 8/1/2012; $100.00 commencing 8/1/2013.
(2) Through 8/31/2012; $100.35 commencing 9/1/2012; $100.00 commencing 9/1/2013.
(3) Dividend rate was 6.25% until 3/20/2011. Effective 3/20/11 the rate reset to 6.12% until 3/20/2014 after which the rate will be determined according to periodic auctions for periods established by Virginia Power at the time of the auction process.
NOTE 20. SHAREHOLDERS’ EQUITY
Issuance of Common Stock
DOMINION
Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in the Company’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. During 2011, Dominion Direct® and the Dominion employee savings plans purchased Dominion common stock on the open market with the proceeds received through these programs, rather than having additional new common shares issued. In January 2012, Dominion began issuing new common shares for these direct stock purchase plans.
During 2011, Dominion issued approximately 1.2 million shares of common stock and received cash proceeds of $38 million through the exercise of employee stock options.
In January 2012, Dominion filed a new SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at the market program. The Company entered into four separate Sales Agency Agreements with each of BNY Mellon Capital Markets, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. LLC, and Goldman Sachs & Co., to effect sales under the program. However, with the exception of issuing approximately $320 million in equity through employee savings plans, direct stock purchase and dividend reinvestment plans, and other employee and director benefit plans, Dominion does not anticipate issuing common stock in 2012.
VIRGINIA POWER
In 2011, Virginia Power did not issue any shares of its common stock to Dominion. In 2010 and 2009, Virginia Power issued 33,013 and 31,877 shares of its common stock to Dominion for approximately $1 billion in each year, for the purpose of retiring short-term demand note borrowings from Dominion.
Shares Reserved for Issuance
At December 31, 2011, Dominion had approximately 54 million shares reserved and available for issuance for Dominion Direct®, employee stock awards, employee savings plans, director stock compensation plans and contingent convertible senior notes.
Repurchase of Common Stock
In March 2010, Dominion began repurchasing common shares in anticipation of proceeds from the sale of its Appalachian E&P operations. During 2010, Dominion repurchased 21.4 million shares of its common stock for approximately $900 million.
In 2011, Dominion announced that it intended to repurchase between $600 million and $700 million of common stock with cash tax savings resulting from the extension of the bonus depreciation allowance. During 2011, Dominion repurchased approximately 13 million shares of common stock for approximately $601 million on the open market under this program, at an average price of $46.37 per share. Dominion does not plan to repurchase additional shares under this program during 2012.
Accumulated Other Comprehensive Income (Loss)
Presented in the table below is a summary of AOCI by component:
Stock-Based Awards
The 2005 Incentive Compensation Plan permits stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Plan permits grants of restricted stock and stock options. Under provisions of both plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. At December 31, 2011, approximately 33 million shares were available for future grants under these plans.
Dominion measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion’s results for the years ended December 31, 2011, 2010 and 2009 include $39 million, $40 million, and $44 million, respectively, of compensation costs and $13 million, $15 million, and $17 million, respectively of income tax benefits related to Dominion’s stock-based compensation
Combined Notes to Consolidated Financial Statements, Continued
arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. Excess tax benefits are classified as a financing cash flow. During the years ended December 31, 2011, 2010 and 2009, Dominion realized $2 million, $10 million, and $5 million, respectively, of excess tax benefits from the vesting of restricted stock awards and exercise of stock options.
STOCK OPTIONS
The following table provides a summary of changes in amounts of stock options outstanding as of and for the years ended December 31, 2011, 2010 and 2009. No options were granted under any plan in 2011, 2010 or 2009.
(1) Intrinsic value represents the difference between the exercise price of the option and the market value of Dominion’s stock.
Dominion issues new shares to satisfy stock option exercises. Dominion received cash proceeds from the exercise of stock options of approximately $38 million, $63 million, and $49 million in the years ended December 31, 2011, 2010 and 2009, respectively.
RESTRICTED STOCK
Restricted stock grants are made to officers under Dominion’s LTIP and may also be granted to certain key contributors from time to time. The fair value of Dominion’s restricted stock awards is equal to the market price of Dominion’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2011, 2010 and 2009:
As of December 31, 2011, unrecognized compensation cost related to nonvested restricted stock awards totaled $18 million and is expected to be recognized over a weighted-average period of 2.1 years. The fair value of restricted stock awards that vested was $28 million, $26 million, and $29 million in 2011, 2010 and 2009, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion stock and the applicable federal, state and local tax withholding rates. Shares tendered for taxes are added to the shares remaining to be issued and become available for reissuance as incentive awards.
GOAL-BASED STOCK
Goal-based stock awards are granted to officers who have not achieved a certain targeted level of share ownership in lieu of cash-based performance grants. In 2008 and 2009, goal-based stock awards were also made to certain key non-officer employees. Current outstanding goal-based shares include awards granted to officers in February 2010 and February 2011.
The issuance of awards is based on the achievement of multiple performance metrics during a two-year period, including ROIC, BVP and TSR relative to that of a peer group of companies for 2009, and for 2010 and 2011 the two metrics of ROIC and TSR relative to that of a peer group of companies. The actual number of shares issued will vary between zero and 200% of targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is equal to the market price of Dominion’s stock on the date of grant. Goal-based stock awards granted to key non-officer employees convert to restricted stock at the end of the two-year performance period and generally
vest three years from the original grant date. Awards to officers vest at the end of the two-year performance period. All goal-based stock awards are settled by issuing new shares.
After the performance period for the April 2008 grants ended on December 31, 2009, the CGN Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 147 thousand shares of the outstanding goal-based stock awards granted in April 2008 were converted to 186 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2011. For awards to officers, 12 thousand shares of the outstanding goal-based stock awards were converted to 15 thousand non-restricted shares and issued to the officers.
After the performance period for the April 2009 grants ended on December 31, 2010, the CGN Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 132 thousand shares of the outstanding goal-based stock awards granted in April 2009 were converted to 168 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2012. For awards to officers, 20 thousand shares of the outstanding goal-based stock awards were converted to 25 thousand non-restricted shares and issued to the officers.
The following table provides a summary of goal-based stock activity for the years ended December 31, 2011, 2010 and 2009:
At December 31, 2011, the targeted number of shares expected to be issued under the February 2010 and February 2011 awards was approximately 12 thousand. In January 2012, the CGN Committee determined the actual performance against metrics established for the February 2010 awards with a performance period that ended December 31, 2011. Based on that determination, the total number of shares to be issued under the February 2010 goal-based stock awards was approximately 15 thousand.
As of December 31, 2011, unrecognized compensation cost related to nonvested goal-based stock awards was not material.
CASH-BASED PERFORMANCE GRANTS
Cash-based performance grants are made to Dominion’s officers under Dominion’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.
The targeted amount of the cash-based performance grant made to officers in April 2008 was $12 million, but the actual payout of the award in February 2010 determined by the CGN Committee was $15 million, based on the level of performance metrics achieved.
In February 2009, a cash-based performance grant was made to officers. A portion of the grant, representing the $11 million targeted amount as of December 31, 2010, was paid in December 2010, based on the achievement of three performance metrics during 2009 and 2010: ROIC, BVP and TSR relative to that of a peer group of companies. The total amount of the award under the grant was $14 million and the remaining $3 million of the grant was paid in February 2011. At December 31, 2010, a liability of $3 million had been accrued for the remaining portion of the award.
In February 2010, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $14 million, which included the $12 million targeted amount, was paid in December 2011, based on the achievement of two performance metrics during 2010 and 2011: ROIC and TSR relative to that of a peer group of companies. The total expected award under the grant is $20 million and the remaining portion of the grant will be paid by March 15, 2012. At December 31, 2011, a liability of $5 million had been accrued for the remaining portion of the award.
In February 2011, a cash-based performance grant was made to officers. Payout of the performance grant will occur by March 15, 2013 based on the achievement of two performance metrics during 2011 and 2012: ROIC and TSR relative to that of a peer group of companies. At December 31, 2011, the targeted amount of the grant was $12 million and a liability of $6 million had been accrued for this award.
NOTE 21. DIVIDEND RESTRICTIONS
The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2011, the Virginia Commission had not restricted the payment of dividends by Virginia Power.
Certain agreements associated with Dominion’s and Virginia Power’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s or Virginia Power’s ability to pay dividends or receive dividends from their subsidiaries at December 31, 2011.
See Note 18 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes.
NOTE 22. EMPLOYEE BENEFIT PLANS
DOMINION
Dominion provides certain benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit
Combined Notes to Consolidated Financial Statements, Continued
plans, Dominion reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.
Dominion maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension program also provides benefits to certain retired executives under a company-sponsored nonqualified employee benefit plan. The nonqualified plan is funded through contributions to a grantor trust.
Dominion provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service. In January 2011, Dominion amended its retiree healthcare and life benefits to change the eligibility age, effective January 1, 2012, for the majority of nonunion employees from 55 with 10 years of service to 58 with 10 years of service, resulting in an approximately $71 million reduction to the other postretirement benefit plan obligation. The eligibility requirements for nonunion employees hired on or after January 1, 2008, who benefit under the Retiree Medical Account design, as well as for union employees are not affected by this plan design change.
Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and the rate of compensation increases.
Dominion uses December 31 as the measurement date for all of its employee benefit plans. Dominion uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.
Dominion’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Aggregate actual returns for Dominion’s pension and other postretirement plan assets were $273 million in 2011 and $624 million in 2010, versus expected returns of $519 million and $479 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.
The Medicare Act introduced a federal subsidy to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Dominion determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D. Dominion received a federal subsidy of $5 million for each of 2011 and 2010. In December 2011, Dominion elected to change its method of receiving the subsidy under Medicare Part D for retiree prescription drug coverage from the Retiree Drug Subsidy to the EGWP. This change is expected to be effective January 1, 2013. As a result of this change, Dominion recognized a decrease in its other postretirement benefit obligations of approximately $170 million as of December 31, 2011. This change is also expected to reduce other postretirement benefit costs by approximately $20 million annually beginning in 2012.
Funded Status
The following table summarizes the changes in Dominion’s pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status:
(1) Represents transfer of pension plan assets and obligation for all active Peoples employees as of February 1, 2010. See Note 4 for more information on the sale of Peoples completed in February 2010.
(2) 2010 amounts relate to the sales of Peoples and Dominion’s Appalachian E&P operations and a workforce reduction program.
(3) Represents a one-time special termination benefit for certain employees in connection with a workforce reduction program.
The ABO for all of Dominion’s defined benefit pension plans was $4.5 billion and $4.1 billion at December 31, 2011 and 2010, respectively.
Under its funding policies, Dominion evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion determines the amount of contributions for the current year, if any, at that time. During 2011, Dominion made no contributions to its qualified defined benefit pension plans and no contributions are currently expected in 2012. Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion’s subsidiaries fund other postretirement benefit costs through VEBAs. Dominion’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion expects to contribute approximately $16 million to the Dominion VEBAs in 2012.
Dominion does not expect any pension or other postretirement plan assets to be returned to the Company during 2012.
The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets:
(1) The increase primarily reflects a decrease in the discount rate as of December 31, 2011.
The following table provides information on the ABO and fair value of plan assets for pension plans with an ABO in excess of plan assets:
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
The above benefit payments for other postretirement benefit plans for 2012 are expected to be offset by a Medicare Part D subsidy of approximately $5 million. As a result of the adoption of the EGWP as discussed above, beginning in 2013 Dominion will receive an increased level of Medicare Part D subsidies, in the form of reduced costs rather than a direct reimbursement.
Plan Assets
Dominion’s overall objective for investing its pension and other postretirement plan assets is to achieve the best possible long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for its pension funds are 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the United States. Non-U.S. equity includes investments in large-cap companies located outside of the United States including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity REITs and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.
Strategic investment policies are established for Dominion’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.
Combined Notes to Consolidated Financial Statements, Continued
For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 7.
The fair values of Dominion’s pension plan assets by asset category are as follows:
(1) Includes net assets related to pending sales of securities of $26 million at December 31, 2010.
The fair values of Dominion’s other postretirement plan assets by asset category are as follows:
(1) Includes net assets related to pending sales of securities of $1 million at December 31, 2010.
The following table presents the changes in Dominion’s pension and other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category:
Net Periodic Benefit Cost
The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:
(1) 2010 amounts relate to the sales of Peoples and Dominion’s Appalachian E&P operations and a workforce reduction program.
(2) Represents a one-time special termination benefit for certain employees in connection with a workforce reduction program.
Combined Notes to Consolidated Financial Statements, Continued
The components of AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit (credit) cost are as follows:
(1) As of December 31, 2011, of the $2.2 billion related to pension benefits, $1.4 billion is included in AOCI, with the remainder included in regulatory assets and liabilities; the $14 million related to other postretirement benefits consists of $16 million included in regulatory assets and liabilities and $(2) million included in AOCI. As of December 31, 2010, of the $1.8 billion and $240 million related to pension benefits and other postretirement benefits, $978 million and $75 million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.
The following table provides the components of AOCI and regulatory assets and liabilities as of December 31, 2011 that are expected to be amortized as components of periodic benefit cost in 2012:
Dominion determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans by using a combination of:
•
Expected inflation and risk-free interest rate assumptions;
•
Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;
•
Expected future risk premiums, asset volatilities and correlations;
•
Forward-looking return expectations derived from the yield on long-term bonds and the price earnings ratios of major stock market indices; and
•
Investment allocation of plan assets.
Dominion develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions.
Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans.
Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion’s retiree healthcare plans. A one percentage point change in assumed healthcare cost trend rates would have had the following effects:
Defined Contribution Plans
In addition, Dominion sponsors defined contribution employee savings plans. During 2011, 2010 and 2009, Dominion recognized $38 million, $39 million and $42 million, respectively, as contributions to these plans.
VIRGINIA POWER
Virginia Power participates in the Dominion Pension Plan, a defined benefit pension plan sponsored by Dominion that provides benefits to multiple Dominion subsidiaries. Retirement benefits payable under this plan are based primarily on years of service, age and the employee’s compensation. As a participating employer, Virginia Power is subject to Dominion’s funding policy, which is to contribute annually an amount that is in accordance with the provisions of ERISA. During 2011, Virginia Power made no contributions to the plan and no contributions are currently expected in 2012. Virginia Power’s net periodic pension cost related to this pension plan was $50 million, $84 million and $48 million in 2011, 2010 and 2009, respectively. The 2010 net periodic pension cost includes the impact of a settlement and curtailment as well as a one-time special termination benefit for certain employees in connection with a workforce reduction program. Employee compensation is the basis for determining Virginia Power’s share of total pension costs.
Virginia Power also participates in the Dominion Retiree Health and Welfare Plan, a plan sponsored by Dominion that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Annual employee premiums are based on several factors such as age, retirement date and years of service. Virginia Power’s net periodic benefit cost related to this plan was $23 million, $59 million and $55 million in 2011, 2010 and 2009, respectively. Employee headcount is the basis for determining Virginia Power’s share of total other postretirement benefit costs.
Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power funds other postretirement benefit costs through a VEBA. Virginia Power’s contributions to the VEBA were $35 million and $34 million in 2010 and 2009, respectively. Virginia Power made no contributions to the VEBA in 2011 and does not expect to contribute to the VEBA in 2012.
Dominion holds investments in trusts to fund employee benefit payments for its pension and other postretirement benefit plans, in which Virginia Power’s employees participate. Any investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power will provide to Dominion for its share of employee benefit plan contributions.
Virginia Power also participates in Dominion-sponsored defined contribution employee savings plans that cover substantially all employees. Employer matching contributions of $14 million were incurred in each of 2011, 2010 and 2009.
NOTE 23. COMMITMENTS AND CONTINGENCIES
As a result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in legal proceedings before various courts and are periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss does not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on Dominion’s or Virginia Power’s financial position, liquidity or results of operations.
Environmental Matters
Dominion and Virginia Power are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
AIR
On December 21, 2011, the EPA issued MATS for coal and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance will be required by Spring 2015, with certain limited exceptions. In December 2011, Virginia Power recorded a $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain regulated coal units, primarily as a result of the issuance of the final MATS. Dominion continues to be governed by individual state mercury emission reduction regulations in Massachusetts and Illinois that are largely unaffected by this rule.
In July 2011, the EPA issued a final replacement rule for CAIR, called CSAPR, that requires 28 states to reduce power plant emissions that cross state lines. CSAPR establishes new SO2 and NOx emissions cap and trade programs that are completely independent of the current ARP. Specifically, CSAPR requires reductions in SO2 and NOx emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NOx emissions caps, NOx emissions caps during the ozone season (May 1 through September 30) and annual SO2 emission caps with differing requirements for two groups of affected states.
Prior to the issuance of CSAPR, Dominion and Virginia Power held $57 million and $43 million, respectively, of SO2 emissions allowances obtained for ARP and CAIR compliance. Due to CSAPR’s establishment of a new allowance program and the elimination of CAIR, Dominion and Virginia Power have more SO2 emissions allowances than needed for ARP compliance, which resulted in the impairment of these allowances in the third quarter of 2011. See Note 7 for further details of the impairments.
With respect to Dominion’s generation fleet, the cost to comply with the rule is not expected to be material. However, following numerous petitions for review and motions for stay, in December 2011, the U.S. Court of Appeals for the D.C. Circuit issued a ruling to stay CSAPR pending judicial review. Also, in the fourth quarter of 2011, the EPA proposed technical revisions to CSAPR. Accordingly, future outcomes of litigation and/or final action to modify the rule could affect this assessment. While the stay of CSAPR is in effect, the EPA will continue to administer CAIR.
The 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 Dominion’s and Virginia Power’s facilities are subject to the CAA’s permitting and other requirements.
In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, New Source Performance Standards, the Title V permit program and the stations’ respective State Implementation Plans. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the CAA.
Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The CAA authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. In addition to any such penalties that may be awarded, an adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time. Such expenditures could affect future
Combined Notes to Consolidated Financial Statements, Continued
results of operations, cash flows, and financial condition. Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.
In June 2010, the Conservation Law Foundation and Healthlink Inc. filed a Complaint in the District Court of Massachusetts against Dominion Energy New England, Inc. alleging that Salem Harbor units 1, 2, 3, and 4 have been and are in violation of visible emissions standards and monitoring requirements of the Massachusetts State Implementation Plan and the station’s state and federal operating permits. In February 2012, the court entered a consent decree among the parties, pursuant to which Dominion will retire Salem Harbor. The consent decree is not expected to have a material effect on Dominion’s operations, financial statements or cash flows.
WATER
The 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. Dominion and Virginia Power must comply with all aspects of the CWA programs at their operating facilities.
In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. Currently, Dominion is constructing the cooling towers and estimates the total cost to install these cooling towers at approximately $570 million, with remaining expenditures of approximately $65 million included in its planned capital expenditures through 2012.
In October 2007, the VSWCB issued a renewed VPDES permit for North Anna. BREDL, and other persons, appealed the VSWCB’s decision to the Richmond Circuit Court, challenging several permit provisions related to North Anna’s discharge of cooling water. In February 2009, the court ruled that the VSWCB was required to regulate the thermal discharge from North Anna into the waste heat treatment facility. Virginia Power filed a motion for reconsideration with the court in February 2009, which was denied. The final order was issued by the court in September 2009. The court’s order allowed North Anna to continue to operate pursuant to the currently issued VPDES permit. In October 2009, Virginia Power filed a Notice of Appeal of the court’s order with the Richmond Circuit Court, initiating the appeals process to the Virginia Court of Appeals. In June 2010, the Virginia Court of Appeals reversed the Richmond Circuit Court’s September 2009 order. The Virginia Court of Appeals held that the lower court had applied the wrong standard of review, and that the VSWCB’s determination not to regulate the station’s thermal discharge into the waste heat treatment facility was lawful. In July 2010, BREDL and the other original appellants filed a petition for appeal to the Supreme Court of Virginia requesting that it review the Court of Appeals’ decision. In December 2010, the Supreme Court of Virginia granted BREDL’s petition. In January 2012, the Supreme Court of Virginia upheld the Virginia Court of Appeals’ June 2010 ruling for Dominion and the VSWCB.
In September 2010, Millstone’s NPDES permit was reissued under the CWA. The conditions of the permit require an evalua-
tion of control technologies that could result in additional expenditures in the future, however, Dominion cannot currently predict the outcome of this evaluation. In October 2010, the permit issuance was appealed to the state court by a private plaintiff. The permit is expected to remain in effect during the appeal. Dominion is currently unable to make an estimate of the potential financial statement impacts related to this matter.
SOLID AND HAZARDOUS WASTE
The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be strictly, jointly and severally liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.
From time to time, Dominion or Virginia Power may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion or Virginia Power may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. Except as noted below, the Companies do not believe this will have a material effect on results of operations, financial condition and/or cash flows.
In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. In November 2011 Virginia Power and a number of other parties notified the EPA that they are declining to undertake the work set forth in the UAO.
The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO. Virginia Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter.
Dominion has determined that it is associated with 17 former manufactured gas plant sites. Studies conducted by other utilities
at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the 17 former sites with which Dominion is associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program and Dominion has not yet estimated the future remediation costs. Due to the uncertainty surrounding these sites, Dominion is unable to make an estimate of the potential financial statement impacts related to these sites.
CLIMATE CHANGE LEGISLATION AND REGULATION
Massachusetts, Rhode Island and Connecticut, among other states, have joined RGGI, a multi-state effort to reduce CO2 emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO2 emissions from power plants in participating states are required to be stabilized at current levels from 2009 to 2015. Further reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO2 emissions. During 2012, RGGI will undergo a program review which could impact regulations and implementation of RGGI. The impact of this program review on Dominion’s fossil fired generation operations in RGGI states is unknown at this time. Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.
Three of Dominion’s facilities, Brayton Point, Salem Harbor and Manchester Street, are subject to RGGI. Beginning with calendar year 2009, RGGI requires that Dominion cover each ton of CO2 direct stack emissions from these facilities with either an allowance or an offset. The allowances can be purchased through auction or through a secondary market. Dominion has participated in RGGI allowance auctions to date and has procured allowances to meet its estimated compliance requirements under RGGI for 2009 through 2013 and partially for 2014, therefore Dominion does not expect compliance with RGGI to have a material impact on its results of operations or financial condition. However, during June 2011, a lawsuit was filed in New York seeking to retroactively rescind RGGI participation by that state. Currently, a percentage of Dominion’s RGGI allowances have been acquired from New York. The allocated value of these allowances totaled approximately $38 million, of which the majority have been expensed as consumed. Dominion anticipates that it will surrender New York RGGI allowances for purposes of compliance prior to the issuance of a court decision in the lawsuit, should Dominion continue to hold New York allowances at such time that the court issues a decision that is adverse to New York, and RGGI does not exchange these allowances for other state allowances, replacement allowances would have to be purchased. Dominion cannot predict the outcome of the case and is currently unable to make an estimate of the potential financial statement impacts related to these matters.
Long-Term Purchase Agreements
At December 31, 2011, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:
(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, 2011, the present value of Virginia Power’s total commitment for capacity payments is $1.7 billion. Capacity payments totaled $338 million, $344 million, and $356 million, and energy payments totaled $275 million, $303 million, and $254 million for 2011, 2010 and 2009, respectively.
Lease Commitments
Dominion and Virginia Power lease various facilities, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2011 are as follows:
Rental expense for Dominion totaled $155 million, $171 million, and $172 million for 2011, 2010 and 2009, respectively. Rental expense for Virginia Power totaled $50 million, $50 million, and $49 million for 2011, 2010, and 2009, respectively. The majority of rental expense is reflected in other operations and maintenance expense.
Nuclear Operations
NUCLEAR DECOMMISSIONING-MINIMUM FINANCIAL ASSURANCE
The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 2011 calculation for the NRC minimum financial assurance amount, aggregated for Dominion’s and Virginia Power’s nuclear units, was $3.2 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2011 NRC minimum financial assurance amounts shown were calculated using preliminary December 31, 2011 U.S. Bureau of Labor Statistics indices. Dominion believes that the
Combined Notes to Consolidated Financial Statements, Continued
amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the units will not be decommissioned for decades. Dominion and Virginia Power will continue to monitor these trusts to ensure they meet the minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC.
NUCLEAR INSURANCE
The Price-Anderson Amendments Act of 1988 provides the public up to $12.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $118 million for each of their licensed reactors not to exceed $18 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.
The current level of property insurance coverage for Dominion’s and Virginia Power’s nuclear units is as follows:
(1) Surry and North Anna share a blanket property limit of $1 billion.
The Companies’ coverage exceeds the NRC 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. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $78 million and $40 million, respectively. Based on the severity of the incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance pro-
ceeds are not available because they must first be used for stabilization and decontamination.
Dominion and Virginia Power also purchase insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, the Companies are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $31 million and $19 million, respectively.
ODEC, a part owner of North Anna, and Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation, part owners of Millstone’s Unit 3, are responsible to Dominion and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.
SPENT NUCLEAR FUEL
Under provisions of the Nuclear Waste Policy Act of 1982, Dominion and Virginia Power entered into contracts 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 the Companies’ contracts with the DOE. In January 2004, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims against the DOE requesting damages in connection with its failure to commence accepting spent nuclear fuel. In October 2008, the court issued an opinion and order for Dominion in the amount of approximately $155 million, which includes approximately $112 million in damages incurred by Virginia Power for spent fuel-related costs at Surry and North Anna and approximately $43 million in damages incurred for spent nuclear fuel-related costs at Millstone through June 30, 2006. In December 2008, the government appealed the judgment to the U.S. Court of Appeals for the Federal Circuit. The government’s initial brief in the appeal was filed in June 2010. The issues raised by the government on appeal pertained to the damages awarded to Dominion for Millstone. The government did not take issue with the damages awarded to Virginia Power for Surry or North Anna. As a result, Virginia Power recognized a receivable in the amount of $174 million, largely offset against property, plant and equipment and regulatory assets and liabilities, representing certain spent nuclear fuel-related costs incurred through June 30, 2010.
In the second quarter of 2011, the Federal Appeals Court issued a decision affirming the trial court’s damages award. The government did not seek rehearing of the Federal Appeals Court decision or seek review by the U.S. Supreme Court. As a result, Dominion recognized a receivable in the amount of $64 million for certain Millstone spent nuclear fuel-related costs incurred through June 30, 2011 that were considered probable of recovery. Dominion recognized a pre-tax benefit of $24 million, with $17 million recorded in other operations and maintenance expense and $7 million recorded in depreciation, depletion and amortization expense during 2011, with the remainder largely offset against property, plant and equipment. Dominion received payment of the $155 million damages award, including $112 million of damages incurred by Virginia Power, during the third quarter of 2011.
A lawsuit was also filed for Kewaunee. In August 2010, Dominion and the federal government reached a settlement resolving Dominion’s claims for damages incurred at Kewaunee through December 31, 2008. The approximately $21 million settlement payment was received in September 2010.
The Companies continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. At December 31, 2011, Dominion’s and Virginia Power’s receivables for spent nuclear fuel-related costs totaled $102 million and $76 million, respectively. The Companies will continue to manage their spent fuel until it is accepted by the DOE.
Guarantees, Surety Bonds and Letters of Credit
DOMINION
At December 31, 2011, Dominion had issued $82 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2011, Dominion’s exposure under these guarantees was $49 million, primarily related to certain reserve requirements associated with non-recourse financing.
In addition to the above guarantees, Dominion and its partners, Shell and BP, may be required to make additional periodic equity contributions to NedPower and Fowler Ridge in connection with certain funding requirements associated with their respective non-recourse financings. As of December 31, 2011, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $123 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million.
Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion’s consolidated subsidiaries, that liability is included in Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.
At December 31, 2011, Dominion had issued the following subsidiary guarantees:
(1) Represents the estimated portion of the guarantee’s stated limit that is utilized as of December 31, 2011 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount.
(2) Guarantees of debt of certain DEI subsidiaries. In the event of default by the subsidiaries, Dominion would be obligated to repay such amounts.
(3) Guarantees related to energy trading and marketing activities and other commodity commitments of certain subsidiaries, including subsidiaries of Virginia Power and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion would be obligated to satisfy such obligation. Dominion and its subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits.
(4) Guarantees related to certain DEI subsidiaries’ potential retrospective premiums that could be assessed if there is a nuclear incident under Dominion’s nuclear insurance programs and guarantees for a DEI subsidiary’s and Virginia Power’s commitment to buy nuclear fuel. Excludes Dominion’s agreement to provide up to $150 million and $60 million to two DEI subsidiaries to pay the operating expenses of Millstone and Kewaunee, respectively, in the event of a prolonged outage, as part of satisfying certain NRC requirements concerned with ensuring adequate funding for the operations of nuclear power stations.
(5) Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower.
Additionally, as of December 31, 2011 Dominion had purchased $151 million of surety bonds and authorized the issuance of letters of credit by financial institutions of $36 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Dominion is obligated to indemnify the respective surety bond company for any amounts paid.
VIRGINIA POWER
As of December 31, 2011, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. Virginia Power had also purchased $62 million of surety bonds for various purposes, including providing workers’ compensation coverage, and authorized the issuance of letters of credit by financial institutions of $15 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Virginia Power is 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, Dominion and Virginia Power may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. Dominion and Virginia Power are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2011,
Dominion and Virginia Power believe future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.
Combined Notes to Consolidated Financial Statements, Continued
Workforce Reduction Program
In the first quarter of 2010, Dominion and Virginia Power announced a workforce reduction program that reduced their total workforces by approximately 9% and 11%, respectively, during 2010. The goal of the workforce reduction program was to reduce operations and maintenance expense growth and further improve the efficiency of the Companies. In the first quarter of 2010, Dominion recorded a $338 million ($206 million after-tax) charge, including $202 million ($123 million after-tax) at Virginia Power, primarily reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other benefits related to the workforce reduction program. During 2010, Dominion and Virginia Power paid $109 million and $104 million, respectively, of costs related to the program. The terms of the workforce reduction program were consistent with the Companies’ existing severance plan.
Merchant Generation Operations
Dominion continually reviews its portfolio of assets to determine which assets fit strategically and support its objectives to improve return on invested capital and shareholder value. If Dominion identifies assets that do not support its objectives and believes they may be of greater value to another owner, Dominion may consider such assets for divestiture. In connection with this effort, in the first quarter of 2011, Dominion decided to pursue the sale of Kewaunee. If these efforts are successful, Dominion may be required to present Kewaunee’s assets and liabilities that are subject to sale as held for sale in its Consolidated Balance Sheet and Kewaunee’s results of operations in discontinued operations in its Consolidated Statements of Income. Held for sale classification would require that amounts be recorded at the lower of book value or sale price less costs to sell and could result in the recording of an impairment charge. Any sale of Kewaunee would be subject to the approval of Dominion’s Board of Directors, as well as applicable state and federal approvals.
During the second quarter of 2011, Dominion announced that State Line would be retired by mid-2014, and that it would retire two of the four units at Salem Harbor by the end of 2011 and plans to retire the remaining units on June 1, 2014. In the second quarter of 2011, Dominion recorded a $17 million ($11 million after-tax) charge in other operations and maintenance expense for severance costs related to the expected closings of these merchant generation facilities. In August 2011, Dominion announced that State Line would be retired in the first quarter of 2012, given a continued decline in power prices and the expected cost to comply with CSAPR. During the third quarter of 2011, Dominion recorded a $15 million ($10 million after-tax) charge in other operations and maintenance expense related to the accelerated closure of State Line.
MF Global
Prior to October 31, 2011, certain of Dominion’s subsidiaries executed certain commodity transactions on exchanges using MF Global, an FCM registered with the CFTC. In order to secure its potential exposure on these commodity transactions, Dominion posted certain required margin collateral with MF Global. The parent company of MF Global, MF Global Holdings Ltd., filed for bankruptcy relief under Chapter 11 of the U.S. Bankruptcy Code on October 31, 2011. On the same date, the U.S. District Court for the Southern District of New York appointed a trustee to oversee the liquidation of MF Global pursuant to the Securities Investor Protection Act.
In accordance with court-approved procedures, Dominion transferred to other FCMs all open positions executed using MF Global. The initial margin posted for these open positions at October 31, 2011 was approximately $73 million. Dominion has received approximately $8 million of this amount through the liquidation process to date.
At this time, the MF Global trustee is determining the final amounts that will be recoverable and ultimately distributed to MF Global’s customers. As part of this process, the trustee has filed claims in the insolvency proceeding of MF Global affiliates in various foreign jurisdictions, including the United Kingdom, which claims are still pending. Due to the uncertainty surrounding the ultimate recovery on the claims filed by the MF Global trustee in the United Kingdom and elsewhere and the potential dilution of such recovered funds in the liquidation process, Dominion is unable to estimate the loss, if any, associated with its remaining margin claims.
NOTE 24. CREDIT RISK
Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.
Dominion and Virginia Power maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 2011 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
GENERAL
DOMINION
As a diversified energy company, Dominion transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.
Dominion’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include trading of energy-related commodities, marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account
contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2011, Dominion’s gross credit exposure totaled $534 million. After the application of collateral, credit exposure is reduced to $504 million. Of this amount, investment grade counterparties, including those internally rated, represented 80%. One counterparty exposure represents 10% of Dominion’s total exposure and is a large financial institution rated investment grade.
VIRGINIA POWER
Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2011, Virginia Power’s exposure to potential concentrations of credit risk was not considered material.
CREDIT-RELATED CONTINGENT PROVISIONS
The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 2011 and 2010, Dominion would have been required to post an additional $88 million of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion had posted $110 million in collateral, including $4 million of letters of credit at December 31, 2011 and $54 million in collateral, including $19 million of letters of credit at December 31, 2010, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 2011 and 2010 was $259 million and $210 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power were not material as of December 31, 2011 and 2010. See Note 8 for further information about derivative instruments.
NOTE 25. RELATED-PARTY TRANSACTIONS
Virginia Power engages in related-party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power is included in Dominion’s consolidated federal income tax return and participates in certain Dominion benefit plans. A discussion of significant related-party transactions follows.
Transactions with Affiliates
Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps and options, to manage commodity price risks associated with purchases of natural gas.
As of December 31, 2011 and 2010, Virginia Power’s derivative liabilities with affiliates were not material.
DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage. Presented below are significant transactions with DRS and other affiliates:
In the fourth quarter of 2011, a subsidiary of Virginia Power purchased nuclear fuel-related inventory from an affiliate for $39 million for future use at its nuclear generation stations.
The following table presents Virginia Power’s borrowings from Dominion under short-term arrangements:
Virginia Power’s interest charges related to its borrowings from Dominion were immaterial for the years ended December 31, 2011, 2010 and 2009.
In 2010 and 2009, Virginia Power issued 33,013 and 31,877 shares of its common stock to Dominion for approximately $1 billion in each year, for the purpose of retiring short-term demand note borrowings from Dominion. There were no such issuances of common stock in 2011.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 26. OPERATING SEGMENTS
Dominion and Virginia Power are organized primarily on the basis of products and services sold in the U.S. A description of the operations included in the Companies’ primary operating segments is as follows:
In addition to the operating segments above, the Companies also report a Corporate and Other segment.
The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of the operations and sale of Peoples, which is discussed in Note 4. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
DOMINION
In 2011, Dominion reported after-tax net expense of $346 million for specific items in the Corporate and Other segment, with $375 million of these net expenses attributable to its operating segments.
The net expenses for specific items in 2011 primarily related to the impact of the following items:

A $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units, attributable to Dominion Generation;

A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP;

A $66 million ($39 million after-tax) loss from the operations of Kewaunee, attributable to Dominion Generation. Kewaunee’s results of operations have been reflected in the Corporate and Other segment due to Dominion’s decision in the first quarter of 2011 to pursue the sale of Kewaunee;

A $55 million ($39 million after-tax) impairment charge related to State Line, attributable to Dominion Generation; and

A $57 million ($34 million after-tax) charge related to the impairment of SO2 emissions allowances not expected to be consumed due to CSAPR, attributable to Dominion Generation.
In 2010, Dominion reported after-tax net benefits of $837 million for specific items in the Corporate and Other segment, with $1 billion of these net benefits attributable to its operating segments.
The net benefits for specific items in 2010 primarily related to the impact of the following items:

A $2.5 billion ($1.4 billion after-tax) benefit resulting from the gain on the sale of substantially all of Dominion’s Appalachian E&P operations net of charges related to the divestiture, attributable to Dominion Energy; partially offset by

A $338 million ($206 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program, attributable to:

DVP ($67 million after-tax);

Dominion Energy ($24 million after-tax); and

Dominion Generation ($115 million after-tax);

A $134 million ($155 million after-tax) loss from the discontinued operations of Peoples primarily reflecting a net loss on the sale, attributable to the Corporate and Other segment; and

A $194 million ($127 million after-tax) impairment charge at certain merchant generation power stations, attributable to Dominion Generation.
In 2009, Dominion reported after-tax net expenses of $655 million for specific items in the Corporate and Other segment, with $688 million of these net expenses attributable to its operating segments.
The net expenses for specific items in 2009 primarily related to the impact of the following items:

A $455 million ($281 million after-tax) ceiling test impairment charge related to the carrying value of Dominion’s E&P properties, attributable to Dominion Energy; and

A $712 million ($435 million after-tax) charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings, attributable to:

Dominion Generation ($257 million after-tax); and

DVP ($178 million after-tax).
The following table presents segment information pertaining to Dominion’s operations:
At December 31, 2011, 2010, and 2009, none of Dominion’s long-lived assets and no significant percentage of its operating revenues were associated with international operations.
Combined Notes to Consolidated Financial Statements, Continued
VIRGINIA POWER
The majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s DVP and Dominion Generation segments.
In 2011, Virginia Power reported after-tax net expenses of $268 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2011 primarily related to the impact of the following:

A $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired generating units, attributable to Dominion Generation;

A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP;

A $43 million ($26 million after-tax) charge related to the impairment of SO2 emissions allowances not expected to be
consumed due to CSAPR, attributable to Dominion Generation.
In 2010, Virginia Power reported after-tax net expenses of $153 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2010 primarily related to the impact of the following:

A $202 million ($123 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program, attributable to:

DVP ($63 million after-tax); and

Dominion Generation ($60 million after-tax).
In 2009, Virginia Power reported after-tax net expenses of $430 million for specific items attributable to its operating segments in the Corporate and Other segment. The net expenses primarily related to a $700 million ($427 million after-tax) charge in connection with the settlement of the 2009 base rate case proceedings, attributable to Dominion Generation ($257 million after-tax) and DVP ($170 million after-tax).
The following table presents segment information pertaining to Virginia Power’s operations:
NOTE 27. QUARTERLY FINANCIAL AND COMMON STOCK DATA (UNAUDITED)
A summary of Dominion’s and Virginia Power’s quarterly results of operations for the years ended December 31, 2011 and 2010 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.
DOMINION
(1) Amounts attributable to Dominion’s common shareholders.
Dominion’s 2011 results include the impact of the following significant item:

Fourth quarter results include a $139 million after-tax charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units.
Dominion’s 2010 results include the impact of the following significant items:

First quarter results include a $206 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program and a $149 million after-tax loss from the discontinued operations of Peoples primarily reflecting a net loss on the sale.

Second quarter results include a $1.4 billion after-tax benefit resulting from the gain on the sale of substantially all of Dominion’s Appalachian E&P operations net of charges related to the divestiture and a $95 million after-tax impairment charge at State Line to reflect the estimated fair value of the power station.
Combined Notes to Consolidated Financial Statements, Continued
VIRGINIA POWER
Virginia Power’s quarterly results of operations were as follows:
Virginia Power’s 2011 results include the impact of the following significant item:

Fourth quarter results include a $139 million after-tax charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired power stations.
Virginia Power’s 2010 results include the impact of the following significant item:

First quarter results include a $123 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
DOMINION
Senior management, including Dominion’s CEO and CFO, evaluated the effectiveness of Dominion’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion’s CEO and CFO have concluded that Dominion’s disclosure controls and procedures are effective. There were no changes in Dominion’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion’s internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Dominion Resources, Inc. (Dominion) understands and accepts responsibility for Dominion’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion does throughout all aspects of its business.
Dominion maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.
The Audit Committee of the Board of Directors of Dominion, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.
SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion’s 2011 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2011, Dominion makes the following assertion:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Dominion’s internal control over financial reporting as of December 31, 2011. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management believes that Dominion maintained effective internal control over financial reporting as of December 31, 2011.
Dominion’s independent registered public accounting firm is engaged to express an opinion on Dominion’s internal control over financial reporting, as stated in their report which is included herein.
February 27, 2012
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the internal control over financial reporting of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Dominion’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s Board of Directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes
in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Dominion maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2011 of Dominion and our report dated February 27, 2012, expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 2012
VIRGINIA POWER
Senior management, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes in Virginia Power’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Power’s internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Virginia Electric and Power Company (Virginia Power) understands and accepts responsibility for Virginia Power’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Virginia Power continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.
Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.
The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.
SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s 2011 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2011, Virginia Power makes the following assertion:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Virginia Power’s internal control over financial reporting as of December 31, 2011. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2011.
This annual report does not include an attestation report of Virginia Power’s registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.
February 27, 2012
Item 9B. Other Information
None.
Part III
Item 10. Directors, Executive Officers and Corporate Governance
DOMINION
The following information for Dominion is incorporated by reference from the Dominion 2012 Proxy Statement, which will be filed on or around March 23, 2012:

Information regarding the directors required by this item is found under the heading Election of Directors.

Information regarding compliance with Section 16 of the Securities Exchange Act of 1934, as amended, required by this item is found under the heading Section 16(a) Beneficial Ownership Reporting Compliance.

Information regarding the Dominion Audit Committee Financial expert(s) required by this item is found under the headings Director Independence and Committees and Meeting Attendance.

Information regarding the Dominion Audit Committee required by this item is found under the headings The Audit Committee Report and Committees and Meeting Attendance.

Information regarding Dominion’s Code of Ethics required by this item is found under the heading Corporate Governance and Board Matters.
The information concerning the executive officers of Dominion required by this item is included in Part I of this Form 10-K under the caption Executive Officers of Dominion. Each executive officer of Dominion is elected annually.
VIRGINIA POWER
Information concerning directors of Virginia Power, each of whom is elected annually, is as follows:
(1) Any service listed for Dominion, DRS and CNG reflects service at a parent, subsidiary or affiliate. Virginia Power is a wholly-owned subsidiary of Dominion. DRS is an affiliate of Virginia Power and is also a subsidiary of Dominion. CNG is a former subsidiary of Dominion that merged with and into Dominion.
Executive Officers of Virginia Power
Information concerning the executive officers of Virginia Power, each of whom is elected annually, is as follows:
(1) Any service listed for Dominion, DRS and CNG reflects services at a parent, subsidiary or affiliate.
Section 16(a) Beneficial Ownership Reporting Compliance
To Virginia Power’s knowledge, for the fiscal year ended December 31, 2011, all Section 16(a) filing requirements applicable to its executive officers and directors were satisfied.
Audit Committee Financial Experts
Virginia Power is a wholly-owned subsidiary of Dominion. As permitted by SEC rules, its Board of Directors serves as Virginia Power’s Audit Committee and is comprised entirely of executive officers of Virginia Power or Dominion. Virginia Power’s Board of Directors has determined that Thomas F. Farrell II, Mark F. McGettrick and Steven A. Rogers are “audit committee financial experts” as defined by the SEC. As executive officers of Virginia Power and/or Dominion, Thomas F. Farrell II, Mark F. McGettrick and Steven A. Rogers are not deemed independent.
Code of Ethics
Virginia Power has adopted a Code of Ethics that applies to its principal executive, financial and accounting officers, as well as its employees. This Code of Ethics is the same as Dominion adopted and is available on the corporate governance section of Dominion’s website (www.dom.com). You may also request a copy of the Code of Ethics, free of charge, by writing or telephoning to: Corporate Secretary, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Any waivers or changes to Virginia Power’s Code of Ethics will be posted on the Dominion website.
Item 11. Executive Compensation
DOMINION
The following information about Dominion is contained in the 2012 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the headings Compensation Discussion and Analysis and Executive Compensation; the information regarding Compensation Committee interlocks contained under the heading Compensation Committee Interlocks and Insider Participation; the Compensation, Governance and Nominating Committee Report; and the information regarding director compensation contained under the heading Non-Employee Director Compensation.
VIRGINIA POWER
COMPENSATION COMMITTEE REPORT
In preparation for the filing of Virginia Power’s Annual Report on Form 10-K, Dominion’s CGN Committee reviewed and discussed the following CD&A with management and has recommended to the Board of Directors of Virginia Power that the CD&A be included in Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011.
Frank S. Royal, Chairman
John W. Harris
Robert S. Jepson, Jr.
Mark J. Kington
David A. Wollard
February 21, 2012
INTRODUCTION
Virginia Power is a wholly-owned subsidiary of Dominion. Virginia Power’s Board is comprised of Messrs. Farrell, McGettrick and Rogers. As executive officers of Virginia Power, Messrs. Farrell and McGettrick are not independent. Mr. Rogers is not considered to be independent because he is an officer of Dominion. Because Virginia Power’s Board is not independent, there is not a separate compensation committee at the Virginia Power level. Instead, Virginia Power’s Board depends on the advice and recommendations of Dominion’s CGN Committee which is comprised of independent directors. Virginia Power’s Board approves all compensation paid to Virginia Power’s executive officers based on Dominion’s CGN Committee recommendations.
None of Virginia Power’s directors receive any compensation for services they provide as directors. No executive officer of Dominion or Virginia Power serves as a member of another compensation committee or on the Board of Directors of any company of which a member of Dominion’s CGN Committee, Dominion’s Board of Directors or Virginia Power’s Board of Directors serves as an executive officer.
Because the CGN Committee effectively administers one compensation program for all of Dominion, the following discussion and analysis is based on Dominion’s overall compensation program.
COMPENSATION DISCUSSION AND ANALYSIS
This CD&A provides a detailed explanation of the objectives and principles that underlie Dominion’s executive compensation program, its elements and the way performance is measured, evaluated and rewarded. It also describes Dominion’s compensation decision-making process. Dominion’s executive compensation program is designed to pay for performance and played an important role in the company’s success in 2011 by linking a significant amount of compensation to the achievement of performance goals.
The program and processes generally apply to all officers, but this discussion and analysis focuses primarily on compensation for the NEOs of Virginia Power. During 2011, Virginia Power’s NEOs were:

Thomas F. Farrell II, Chairman, President and CEO

Mark F. McGettrick, Executive Vice President and CFO

Paul D. Koonce, Executive Vice President and COO - DVP

David A. Christian, Executive Vice President and COO -Generation

David A. Heacock, President and CNO
The CGN Committee determines the compensation payable to officers of Dominion and its wholly-owned subsidiaries on an aggregate basis, taking into account all services performed by the officers, whether for Dominion or one or more of its subsidiaries. All of Virginia Power’s NEOs, except for Mr. Heacock, are NEOs of Dominion. For the NEOs included in Dominion’s annual proxy statement, these aggregate amounts are reported in the Summary Compensation Table and related executive compensation tables. For purposes of reporting each NEO’s compensation from Virginia Power in the Summary Compensation Table (and
related tables that follow) in this Item 11, the aggregate compensation for each NEO is pro-rated based on the ratio of services performed by the NEO for Virginia Power to the NEO’s total services performed for all of Dominion. For officers who are NEOs of both Virginia Power and Dominion, the amounts reported in the tables below are part of, and not in addition to the aggregate compensation amounts that are reported for these NEOs in Dominion’s 2012 Proxy Statement. The CD&A below discusses the CGN Committee’s decisions with respect to each NEO’s aggregate compensation for all services performed for all of Dominion, not just the pro-rated portion attributable to the NEO’s services for Virginia Power.
OBJECTIVES OF DOMINION’S EXECUTIVE COMPENSATION PROGRAM AND THE COMPENSATION DECISION-MAKING PROCESS
Objectives
Dominion’s executive compensation philosophy is to provide a competitive total compensation program tied to performance and aligned with the interests of Dominion shareholders, employees and customers.
The major objectives of Dominion’s compensation program are to:

Attract, develop and retain an experienced and highly qualified management team;

Motivate and reward superior performance that supports Dominion’s business and strategic plans and contributes to the long-term success of the company;

Align the interests of management with those of Dominion’s shareholders by placing a substantial portion of pay at risk through performance goals that, if achieved, are expected to increase TSR;

Promote internal pay equity; and

Reinforce Dominion’s four core values of safety, ethics, excellence and One Dominion - Dominion’s term for teamwork.
These objectives provide the framework for the compensation decisions. To determine if Dominion is meeting the objectives of its compensation program, the CGN Committee reviews and compares Dominion’s actual performance to its short-term and long-term goals, strategies, and peer companies’ performance.
Dominion’s 2011 performance indicates that the design of Dominion’s compensation program is meeting these objectives. The NEOs have service with Dominion ranging from 13 to 35 years. Dominion has attracted, motivated and maintained a superior leadership team with skills, industry knowledge and institutional experience that strengthen their ability to act as sound stewards of Dominion’s shareholder dollars. Dominion is performing well relative to internal goals and as compared to its peers.
In 2011, Dominion shareholders voted on the executive compensation program (also known as “Say on Pay”) for the first time and approved it by 94%. The CGN Committee considered the very strong shareholder endorsement of the CGN Committee’s decisions and policies and Dominion’s overall executive compensation program in continuing the pay-for-performance program that is currently in place without any specific changes for 2012 based on the vote.
The Process for Setting Compensation
The CGN Committee is responsible for reviewing and approving NEO compensation and the overall executive compensation program. Each year, the CGN Committee reviews and considers a comprehensive assessment and analysis of the executive compensation program, including the elements of each NEO’s compensation, with input from management and the independent compensation consultant. As part of its assessment, the CGN Committee reviews the performance of the CEO and other executive officers, meets at least annually with the CEO to discuss succession planning for his position and the positions of senior officers, reviews the share ownership guidelines and executive officer compliance with the guidelines, and establishes compensation programs designed to achieve Dominion’s objectives.
THE ROLE OF THE INDEPENDENT COMPENSATION CONSULTANT
The CGN Committee’s practice has been to retain an independent compensation consultant, PM&P, to advise the committee on executive and director compensation matters. PM&P does not provide any services to Dominion other than its consulting services to the CGN Committee related to executive and director compensation. The PM&P consultant participates in meetings with the CGN Committee, either in person or by teleconference, and communicates directly with the chairman of the committee outside of the committee meetings as requested by the chairman of the committee. PM&P also reviewed meeting materials for the CGN Committee and provided the following services related to the 2011 executive compensation program:

Provided independent advice to the CGN Committee regarding the appropriateness of Dominion’s peer group;

Participated in CGN Committee executive sessions without management present to discuss CEO compensation and any other relevant matters, including the appropriate relationship between pay and performance and emerging trends, to answer technical questions, and to review and comment on management proposals and analyses of peer group compensation data; and

Generally reviewed and offered advice as requested by or on behalf of the CGN Committee regarding other aspects of the executive compensation program, including best practices and other matters.
MANAGEMENT’S ROLE IN DOMINION’S PROCESS
Although the CGN Committee has the responsibility to approve and monitor all compensation for the NEOs, management plays an important role in determining executive compensation. Under the direction of the Corporate Secretary, internal compensation specialists provide the CGN Committee with data, analysis and counsel regarding the executive compensation program, including an ongoing assessment of the effectiveness of the program, peer practices, and executive compensation trends and best practices. The CEO, CFO and Corporate Secretary, along with the internal compensation and financial specialists, assist in the design of the incentive compensation plans, including performance target recommendations consistent with strategic goals, and recommendations for establishing the peer group.
Management also works with the Chairman of the CGN Committee to establish the agenda and prepare meeting information for each CGN Committee meeting.
On an annual basis, the CEO is responsible for reviewing Dominion’s succession plans for his own position and for Dominion’s senior officers with the CGN Committee. He is also responsible for reviewing the performance of his senior officers, including the other NEOs, with the CGN Committee at least annually. He makes recommendations on the compensation and benefits for the NEOs (other than himself) to the CGN Committee and provides other information and counsel as appropriate or as requested by the CGN Committee, but all decisions are ultimately made by the CGN Committee.
THE PEER GROUP AND PEER GROUP COMPARISONS
Each year, the CGN Committee approves a peer group of companies. In selecting the peer group, Dominion uses a methodology recommended by PM&P to identify companies in the industry that compete for customers, executive talent and investment capital. Dominion screens this group based on size and usually eliminates companies that are much smaller or larger than Dominion’s size in revenues, assets and market capitalization. Dominion also considers the geographic locations and the regulatory environment in which potential peer companies operate.
Dominion’s peer group is generally consistent from year to year, with merger and acquisition activity being the primary reason for any changes. With the announced mergers of Duke Energy Corporation with Progress Energy, Inc. and Exelon Corporation with Constellation Energy Group, Inc. two companies were added to Dominion’s 2011 peer group: CMS Energy Corporation and Xcel Energy Inc. The members of Dominion’s peer group are as follows:
Ameren Corporation
American Electric Power Company, Inc.
CMS Energy Corporation
Constellation Energy Group, Inc.
DTE Energy Company
Duke Energy Corporation
Entergy Corporation
Exelon Corporation
FirstEnergy Corp.
NextEra Energy, Inc. (formerly FPL
Group, Inc.)
NiSource, Inc.
PPL Corporation
Progress Energy, Inc.
Public Service Enterprise Group Inc.
Southern Company
Xcel Energy Inc.
The CGN Committee, PM&P and management use peer company data to: (i) compare Dominion’s stock and financial performance against its peers using a number of different metrics and time periods to evaluate how Dominion is performing as compared to its peers; (ii) analyze compensation practices within the industry; (iii) evaluate peer company practices and determine peer median and 75th percentile ranges for base pay, annual incentive pay, long-term incentive pay and total direct compensation, both generally and for specific positions; and (iv) compare Employment Continuity Agreements and other benefits. In setting the levels for base pay, annual incentive pay, long-term incentive pay and total direct compensation, the CGN Committee also takes into consideration Dominion’s larger size compared with the median of the peer group.
SURVEY DATA
Dominion did not benchmark or otherwise use broad-based market data as the basis for compensation decisions for the NEOs and other senior officers. Survey compensation data is used only to provide a general understanding of compensation practices and trends. The CGN Committee takes into account individual and company specific factors, including internal pay equity, along with peer company data in establishing compensation opportunities. The CGN Committee believes that this emphasis better reflects Dominion’s specific needs in its distinct competitive market and with respect to its size and complexity versus its peers.
COMPENSATION DESIGN AND RISK
Dominion’s management, including Dominion’s chief risk officer and other executives, annually reviews the overall structure of Dominion’s executive compensation program and policies to ensure they are consistent with effective management of enterprise key risks and that they do not encourage executives to take unnecessary or excessive risks that could threaten the value of the enterprise. With respect to the programs and policies that apply to the NEOs, this review includes:

Analysis of how different elements of the compensation programs may increase or mitigate risk-taking;

Analysis of performance metrics used for short-term and long-term incentive programs and the relation of such incentives to the objectives of Dominion;

Analysis of whether the performance measurement periods for short-term and long-term incentive compensation are appropriate; and

Analysis of the overall structure of compensation programs as related to business risks.
Among the factors considered in management’s assessment are: the balance of the overall program design, including the mix of cash and equity compensation; the mix of fixed and variable compensation; the balance of short-term and long-term objectives of incentive compensation; the performance metrics, performance
targets, threshold performance requirements and capped payouts related to incentive compensation; the clawback provision on incentive compensation; Dominion’s share ownership guidelines, including share ownership levels and retention practices; prohibitions on hedging, pledging, and other derivative transactions related to Dominion stock; and internal controls and oversight structures in place at Dominion.
Management reviewed and provided the results of this assessment to the CGN Committee. Based on this review, the CGN Committee believes that Dominion’s well-balanced mix of salary and short-term and long-term incentives, as well as the performance metrics that are included in the incentive programs, are appropriate and consistent with Dominion’s risk management practices and overall strategies.
OTHER TOOLS
The CGN Committee uses a number of tools in its annual review of the compensation of Dominion’s NEOs, including charts illustrating the total range of payouts for each performance-based compensation element under a number of different scenarios; spreadsheets showing the cumulative dollar impact on total direct compensation that could result from implementing proposals on any single element of compensation; graphs showing the relationship between the CEO’s pay and that of the next highest-paid officer and Dominion’s NEOs as a group; and other information the CGN Committee may request in its discretion. Management’s internal compensation specialists provide the CGN Committee with detailed comparisons of the design and features of Dominion’s long-term incentive and other executive benefit programs with available information regarding similar programs at the peer companies. These tools are used as part of the overall process to ensure that the program results in appropriate pay relationships as compared to Dominion’s peer companies and internally among Dominion’s NEOs, and that an appropriate balance of at-risk, performance-based compensation is maintained to support the program’s core objectives. No material adjustments were made to Dominion’s NEO’s compensation as a result of using these tools.
ELEMENTS OF DOMINION’S COMPENSATION PROGRAM
The executive compensation program consists of four basic elements:
Factors in Setting Compensation
As part of the process of setting compensation targets, approving payouts and designing future programs, the CGN Committee evaluates Dominion’s overall performance versus its business plans and strategies, its short-term and long-term goals and the performance of its peer companies. In addition to considering Dominion’s overall performance for the year, the CGN Committee takes into consideration several individual factors that are not given any specific weighting in setting each element of compensation for each NEO, including:

An officer’s experience and job performance;

The scope, complexity and significance of responsibility for a position, including any differences from peer company positions;

Internal pay equity considerations, such as the relative importance of a particular position or individual officer to Dominion’s strategy and success, and comparability to other officer positions at Dominion;

Retention and market competitive concerns; and

The officer’s role in any succession plan for other key positions.
The CGN Committee generally evaluates each NEO’s base salary, total cash and total direct compensation opportunities against peer group data, both at peer group median and the 75th percentile, to ensure the compensation levels are appropriately competitive, but with the exception of base salary, does not target these compensation levels at a particular percentile or range of the peer group data. Base salary is generally targeted at or slightly above the peer group 50th percentile (median). For Mr. Heacock, the same evaluation process is performed using the Towers Watson Energy Services data instead of peer group data. See Exhibit 99 of this Form 10-K for a listing of the companies included in the survey. Compensation decisions are based on what the
CGN Committee deems appropriate, taking into consideration a number of factors, including those discussed above. However, actual compensation targets may range from below peer median to at or above the 75th percentile based on a number of factors, including experience, tenure and internal pay equity considerations. As part of this analysis, the CGN Committee also takes into account Dominion’s larger size and complexity compared to its peer companies.
In setting compensation for 2011, due to continued economic uncertainty, Dominion provided a modest increase in base salary for all officers, generally, and made adjustments to performance-based compensation target levels for certain officers. Based on the review of peer company compensation data, each NEO’s job performance, recent promotions and internal pay equity considerations such as scope and complexity of the position relative to other positions at Dominion, the CGN Committee determined it was appropriate to increase the target levels under the LTIP for Messrs. McGettrick, Christian and Heacock as described below in Long-Term Incentive Program.
CEO Compensation Relative to Other NEOs
Mr. Farrell participates in the same compensation programs and receives compensation based on the same philosophy and factors as other NEOs. Application of the same philosophy and factors to Mr. Farrell’s position results in overall CEO compensation that is significantly higher than the compensation of the other NEOs. His compensation is commensurate with his greater responsibilities and decision-making authority, broader scope of duties encompassing the entirety of Dominion (as compared to the other NEOs who are responsible for significant but distinct areas within the company) and his overall responsibility for corporate strategy. His compensation also reflects his role as the principal corporate representative to investors, customers, regulators, analysts, legislators, industry and the media.
Dominion considers CEO compensation trends as compared to the next highest-paid officer, as well as to other executive officers as a group, over a multi-year period to monitor the ratio of Mr. Farrell’s pay relative to the pay of other executive officers based on (i) salary only and (ii) total direct compensation. Dominion also compares its ratios to that of its peers to confirm that its ratios are consistent with practices at the peer companies. There is no particular targeted ratio or goal, but instead the CGN Committee considers year-to-year trends and comparisons with peer companies. The CGN Committee did not make any adjustments to the compensation of any NEOs based on this review in 2011.
Allocation of Total Direct Compensation in 2011
Consistent with Dominion’s objective to reward strong performance based on the achievement of short-term and long-term goals, a significant portion of total cash and total direct compensation is at risk. Approximately 88% of Mr. Farrell’s targeted 2011 total direct compensation is performance-based, tied to pre-approved performance metrics, including relative TSR and ROIC, or tied to the performance of Dominion’s stock. For the other NEOs, performance-based and stock-based compensation ranges from 65% to 80% of targeted 2011 total direct compensation. This compares to an average of approximately 54% of targeted compensation at risk for most officers at the vice president level and an average of approximately 12% of total pay at risk for non-officer employees.
The charts below illustrate the elements of total direct compensation opportunities in 2011 for Mr. Farrell and the other NEOs as a group and the allocation of such compensation among base salary, targeted 2011 AIP award and targeted 2011 long-term incentive compensation.
Base Salary
Base salary compensates officers, along with the rest of the workforce, for committing significant time to working on Dominion’s behalf. Annual salary reviews achieve two primary purposes: (i) an annual adjustment, as appropriate, to keep salaries in line and competitive with the peer group and to reflect changes in responsibility, including promotions; and (ii) a motivational tool to acknowledge and reward excellent individual performance, special skills, experience, the strategic impact of a position relative to other Dominion executives and other relevant considerations.
The primary goal is to compensate its officers at a level that best achieves its objectives and reflects the considerations discussed above. Dominion believes that an overall goal of targeting base salary at or slightly above the peer group median is a conservative but appropriate target for base pay. However, an individual’s compensation may be below or above Dominion’s target range based on a number of factors such as performance, tenure, and other factors explained above in Factors in Setting Compensation. In addition to being ranked above the peer group median in 2011 in terms of revenues, assets and market capitalization, the scope of Dominion’s business operations is complex and unique in its industry. Successfully managing such a broad and complex business requires a skilled and experienced management team. Dominion believes it would not be able to successfully recruit and retain such a team if the base pay for officers was generally below the peer group median. Although individual and company performance would have supported merit increases, most officers, including all NEOs, have received modest or no increases in their base salaries since 2009 due to the uncertain market conditions and economic climate. For 2011, the CGN Committee approved a 2% base salary increase for all NEOs, except for Mr. Heacock. Mr. Heacock’s base salary was increased by 10% due to his continued transition to the President and CNO position which he assumed in June 2009. The 2011 merit increase was Mr. Farrell’s first increase in base salary since 2008.
Annual Incentive Plan
OVERVIEW
The AIP plays an important role in meeting Dominion’s overall objective of rewarding strong performance. The AIP is a cash-based program focused on short-term goal accomplishments and is designed to:

Tie interests of shareholders, customers and employees closely together;

Focus the workforce on company, operating group, team and individual goals that ultimately influence operational and financial results;

Reward corporate and operating unit earnings performance;

Reward safety and other operating and stewardship goal success;

Emphasize teamwork by focusing on common goals;

Appropriately balance risk and reward; and

Provide a competitive total compensation opportunity.
TARGET AWARDS
An NEO’s compensation opportunity under the AIP is based on a target award. Target awards are determined as a percentage of a participant’s base salary (for example, 85% of base salary). The
target award is the amount of cash that will be paid if a participant achieves a score of 100% for the goals established at the beginning of the year and the plan is funded at the full funding target set for the year. Participants who retire during the plan year are eligible to receive a prorated payment of their AIP award after the end of the plan year based on final funding and goal achievement. Participants who voluntarily terminate employment during the plan year and who are not eligible to retire (before attainment of age 55) forfeit their AIP award.
AIP target award levels are established based on a number of factors, including historical practice, individual and company performance and internal pay equity considerations, and are compared against peer group data to ensure the appropriate competitiveness of an NEO’s total cash compensation opportunity. However, as discussed above, AIP target award levels were not targeted at a specific percentile or range of the peer group data, nor was survey data used in setting AIP target award levels for 2011. Annual incentive target award levels are also consistent with Dominion’s intent to have a significant portion of NEO compensation at risk. The 2011 AIP targets for all NEOs were the same as the 2010 AIP targets and are shown below.
* As a % of base salary
FUNDING OF THE 2011 AIP
Funding of the 2011 AIP was based solely on consolidated operating earnings per share, with potential funding ranging from 0% to 200% of the target funding. Consolidated operating earnings are Dominion’s reported earnings determined in accordance with GAAP, adjusted for certain items. Dominion believes that by placing a focus on pre-established consolidated operating earnings per share targets, it increases employee awareness of the company’s financial objectives and encourages behavior and performance that will help achieve these objectives.
The 2011 AIP had a full funding target of $3.05 consolidated operating earnings per share, which was at the lower end of the 2011 earnings guidance announced in January 2011 and the revised earnings guidance that was announced in October 2011. Funding is based on a formula where funding begins for all eligible employees, including all of the NEOs, when Dominion is able to report $3.05 consolidated operating earnings per share, exclusive of AIP funding expense. Additional earnings are then used to fund the AIP up to a 100% funding level. Once operating earnings support $3.05 consolidated operating earnings per share with all employees’ AIP funded at 100%, then any additional consolidated operating earnings above the full funding target of $3.05 operating earnings per share are shared equally between AIP participants and shareholders, up to the maximum AIP funding level of 200% at $3.16 operating earnings per share.
Full funding means that the AIP is 100% funded and participants can receive their full targeted AIP payout if they achieve a
score of 100% for their particular goal package, as described below in How AIP Payouts are Determined. At the maximum plan funding level of 200%, participants can earn up to two times their targeted AIP payout, subject to achievement of their individual goal packages.
Dominion’s consolidated operating earnings for the year ended December 31, 2011 were $1.75 billion, or $3.05 per share, as compared to its consolidated reported earnings in accordance with GAAP of $1.41 billion or $2.45 per share.* This resulted in 75% funding for the 2011 AIP.
*Reconciliation of 2011 Consolidated Operating Earnings to Reported Earnings. The following items, which are after-tax, are included in Dominion’s 2011 reported earnings, but are excluded from consolidated operating earnings: $178 million impairment charge related to certain utility and merchant coal-fired power stations; $59 million of restoration costs associated with Hurricane Irene; $39 million net loss from operations at Kewaunee, which is being marketed for sale; $34 million impairment of excess emission allowances resulting from a new EPA air pollution rule; $21 million of severance costs and other charges resulting from expected closings of Salem Harbor and State Line; $19 million net charge in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2009-2010 test years; $13 million of earthquake related costs, largely related to inspections following the safe shutdown of reactors at North Anna; $14 million benefit related to litigation with the DOE for spent nuclear fuel-related costs at Millstone and $3 million net benefit related to other items.
HOW AIP PAYOUTS ARE DETERMINED
For most officers other than Dominion’s NEOs, payout of their funded AIP awards for 2011 was subject to the accomplishment of business unit financial and operating and stewardship goals, including a safety goal. The percentage allocated to each category of goals represents the percentage of the funded award subject to the performance of that goal. Officer goals are weighted according to their responsibilities. The overall score cannot exceed 100%.
Business unit financial goals provide a line-of-sight performance target for officers within a business unit and, on a combined basis, support the consolidated operating earnings target for Dominion. Operating and stewardship goals provide line-of-sight performance targets that may not be financial and that can be customized for each individual or by segments of each business unit. Operating and stewardship goals promote Dominion’s core values of safety, ethics, excellence and teamwork, which in turn contribute to Dominion’s financial success.
The AIP is designed so that AIP payouts earned by Dominion’s NEOs will qualify as tax deductible “performance-based” compensation under Section 162(m) of the IRC. To preserve the tax deduction for payouts made to the NEOs whose compensation is subject to IRC Section 162(m), their payout, if any, is contingent solely on the achievement of the consolidated financial goal (weighted 100%). If the consolidated financial goal is met, the CGN Committee has the authority to exercise negative discretion to lower payouts if additional discretionary goals are adopted and these discretionary goals are not achieved.
For the 2011 AIP, all of the NEOs adopted a discretionary safety goal. Messrs. Koonce, Christian and Heacock also adopted discretionary business unit financial goals and Mr. Heacock also adopted discretionary operating and stewardship goals. These goals are described under 2011 AIP Payouts. The following table shows the goal weightings applied to the NEOs’ discretionary goals.
* 5% goal weighting is for safety goal. Mr. Heacock had other non-safety operating and stewardship goals as described below.
2011 AIP PAYOUTS
The formula for calculating an award is:
The 2011 discretionary business unit financial goals and accomplishment levels for Mr. Koonce (DVP) and Messrs. Christian and Heacock (Dominion Generation) were as follows:
For 2011, amounts for the AIP expense were not included in all business units’ budgets and are not reflected in the goal threshold and goal for 100% payout amounts shown above. The CGN Committee considered each business unit’s net income amount, including and excluding the expense for the AIP, and determined it was appropriate to approve 100% accomplishment of the business unit financial goals.
Both Messrs. Farrell and McGettrick met their target safety goal of four or less OSHA recordable incidents with an incident rate of 0.15 or less for the DRS business unit. For Mr. Koonce, DVP’s OSHA incident rate and lost time/restricted duty rate exceeded the target rates of 1.24 and 0.75, respectively, which resulted in a 52% accomplishment of his safety goal. Mr. Christian met his target safety goal of an OSHA incident rate ranging from 0.23 to 2.0 for certain operating units and recordable incident of 1 or less for another operating unit in the Dominion Generation business unit. Mr. Heacock met his target safety goal of total OSHA recordable injuries of ten or less (weighted 6%) and total station clock resets of six or less for the Dominion Nuclear fleet (weighted 8%).
In addition to his safety goal, Mr. Heacock had discretionary operating and stewardship goals in three other categories: environmental compliance (weighted 5%); radiation exposure (weighted 4%); and fleet capacity factor (weighted 7%). Mr. Heacock met his environmental compliance and radiation exposure goals, but missed his fleet capacity factor goal. Mr. Heacock earned five extra credit points for safety by exceeding his overall safety goal and was able to apply the extra credit to his missed fleet capacity factor goal in accordance with the AIP guidelines. As a result, Mr. Heacock’s total payout score was 100%.
Amounts earned under the 2011 AIP by NEOs are shown below and are reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power for the year presented.
Mr. Koonce’s payout score was calculated as follows:
Long-Term Incentive Program
OVERVIEW
Dominion’s LTIP focuses on Dominion’s longer-term strategic goals and retention of its executives. Since 2006, 50% of Dominion’s long-term incentives have been full value equity awards in the form of restricted stock with time-based vesting and the other 50% have been performance-based awards. Dominion believes restricted stock serves as a strong retention tool and also creates a focus on Dominion’s stock price to further align the interests of officers with the interests of its shareholders and customers. For those officers who have made substantial progress toward their share ownership guidelines, 50% of their long-term award is in the form of a cash performance grant. Officers who have not achieved 50% of their targeted share ownership guideline receive goal-based stock performance grants instead of a cash performance grant. Dividend equivalents are not paid on any performance-based grants. Because officers are expected to retain ownership of shares upon vesting of restricted stock awards, as explained in Share Ownership Guidelines, the long-term cash performance grant balances the program and allows a portion of the long-term incentive award to be accessible to the NEOs during the course of their employment.
The CGN Committee approves long-term incentive awards in January each year with a grant date established in early February. This process ensures incentive-based awards are made at the beginning of the performance period and shortly after the public disclosure of Dominion’s earnings for the prior year. Like the AIP target award levels discussed above, long-term incentive target award levels are established based on a number of factors, including historical practice, individual and company performance, and internal pay equity considerations, and are compared against peer group data to ensure the appropriate competitiveness of an NEO’s total direct compensation opportunity. However, as discussed above, long-term incentive target award levels are not targeted at a specific percentile or range of the peer group data, nor was market survey data a factor in setting long-term incentive target award levels for 2011.
For 2011, the CGN Committee approved increases to Messrs. McGettrick, Christian and Heacock’s target long-term incentive awards as discussed below.
MCGETTRICK. Among the factors considered by the CGN Committee in determining the amount of Mr. McGettrick’s award were Mr. McGettrick’s long tenure with Dominion, his performance as CFO and his increased responsibilities as a result of his promotion from CEO of the Dominion Generation business unit to CFO of Dominion in 2009. The CGN Committee determined it was appropriate to approve an 11% increase in Mr. McGettrick’s target long-term incentive award, which resulted in a 7% increase in target total direct compensation.
CHRISTIAN. For Mr. Christian, the CGN Committee considered, among other factors, Mr. Christian’s long tenure with Dominion, his performance as CEO of the Dominion Generation business unit and Mr. Christian’s increased responsibility as a result of his promotion from President and CNO of the Dominion Nuclear unit in 2009 to his current position. The CGN Committee also considered the size of the Dominion Generation business unit, which is the largest of Dominion’s three business units, relative to Dominion’s other business units in
determining his long-term incentive target award and the continued transition of Mr. Christian’s compensation to a business unit CEO level. The CGN Committee determined it was appropriate to approve a 32% increase in Mr. Christian’s target long-term incentive award, which resulted in a 16% increase in target total direct compensation.
HEACOCK. Among the factors considered by the CGN Committee in determining the amount of Mr. Heacock’s award were his long tenure with Dominion, his performance as President and CNO of the Dominion Nuclear unit and his increased responsibilities related to that position and the complexity of the nuclear industry. The CGN Committee determined it was appropriate to approve an 11% increase in Mr. Heacock’s long-term incentive award, which resulted in a 10.5% increase in target total direct compensation.
Information regarding the fair value of the 2011 restricted stock grants and target cash performance grants for the NEOs is provided in the Grants of Plan-Based Awards table.
2011 RESTRICTED STOCK GRANTS
All officers received a restricted stock grant on February 1, 2011 based on a stated dollar value. The number of shares awarded was determined by dividing the stated dollar value by the closing price of Dominion’s common stock on January 31, 2011. The grants have a three-year vesting term, with cliff vesting at the end of the restricted period on February 1, 2014. Dividends are paid to officers during the restricted period. The grant date fair value and vesting terms of the 2011 restricted stock grant awards made to the NEOs are disclosed in the Grants of Plan-Based Awards table and related footnotes.
2011 PERFORMANCE GRANTS
Most officers, including the NEOs, received cash performance grants on February 1, 2011. The performance period commenced on January 1, 2011 and will end on December 31, 2012. The 2011 grants are denominated as a target award, with potential payouts ranging from 0-200% of the target based on Dominion’s TSR relative to the peer group of companies selected by the CGN Committee and ROIC, weighted equally. The CGN Committee regularly reviews the design of the LTIP. As part of its annual review of the compensation peer group, the CGN Committee also considers the relevance of the compensation peer group for measuring relative TSR under performance-based awards.
The TSR metric was selected to focus officers on long-term shareholder value when developing and implementing their strategic plans and in turn, reward management based on the achievement of TSR levels as measured relative to Dominion’s peer companies. The ROIC metric was selected to reward officers for the achievement of expected levels of return on Dominion’s investments. Dominion believes an ROIC measure encourages management to choose the right investments, and with those investments, to achieve the highest returns possible through prudent decisions, management and control of costs. The target award and vesting terms of 2011 performance grants made to the NEOs are disclosed in the Grants of Plan-Based Awards table and related footnotes.
PAYOUT UNDER 2010 PERFORMANCE GRANTS
In February 2012, final payouts were made to officers who received 2010 performance grants, including the NEOs. The 2010 performance grants were based on two goals: TSR for the two-year period ended December 31, 2011 relative to Dominion’s peer group of companies (weighted 50%) and ROIC for the same two-year period (weighted 50%).

Relative TSR (50% weighting). TSR is the difference between the value of a share of common stock at the beginning and end of the two-year performance period, plus dividends paid as if reinvested in stock. For this metric, Dominion’s TSR is compared to TSR levels at its peer companies for the same two-year period. The peer group for the TSR metric for the 2010 performance grant is the same group of companies described above in The Peer Group and Peer Group Comparisons, excluding CMS Energy Corporation and Xcel Energy Inc. The relative TSR targets and corresponding payout scores are as follows:
* TSR weighting is interpolated between the top and bottom of the percentages within a quartile. A minimum payment of 25% of the TSR percentage will be made if the TSR performance is at least 10% on a compounded annual basis for the performance period, regardless of relative performance.
Actual relative TSR performance for the 2010-2011 period was in the top quartile.

ROIC (50% weighting). ROIC reflects Dominion’s total return divided by average invested capital for the performance period. The ROIC goal at target is consistent with the strategic plan/annual business plan as approved by Dominion’s Board. For this purpose, total return is Dominion’s consolidated operating earnings plus its after-tax interest and related charges, plus preferred dividends. Dominion designed its 2010 ROIC goals to provide 100% payout if it achieved an average ROIC of 8.00% over the two-year performance period. The ROIC performance targets and corresponding payout scores are as follows:
* ROIC percentage payout is interpolated between the top and bottom of the percentages for any range.
Actual ROIC performance for the 2010-2011 period was 8.18%.
Based on the achievement of the performance criteria, the CGN Committee approved a 175.7% payout for the 2010 performance grants. The following table summarizes the achievement of the 2010 performance criteria:
The resulting payout amounts for the NEOs for the 2010 performance grants are shown below and are also reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power for the year presented.
Employee and Executive Benefits
Benefit plans and limited perquisites compose the fourth element of the compensation program. These benefits serve as a retention tool and reward long-term employment.
RETIREMENT PLANS
Dominion sponsors two types of tax-qualified retirement plans for eligible non-union employees, including the NEOs: a defined benefit pension plan and a defined contribution 401(k) savings plan. The NEOs, as employees hired before 2008, are eligible for a pension benefit upon attainment of retirement age based on a formula that takes into account final compensation and years of service. They also receive a cash retirement benefit under which Dominion contributes 2% of each participant’s compensation to a special retirement account, which may be paid in a lump sum or added to the annuity benefit upon retirement. Dominion began funding the special retirement account for eligible employees in January 2001. The formula for the DPP is explained in the narrative following the Pension Benefits table. The change in DPP value for 2011 for the NEOs is included in the Summary Compensation Table.
Officers whose matching contributions under the 401(k) Plan are limited by the IRC receive a cash payment to make them whole for the company match lost as a result of these limits. These cash payments are currently taxable. The company matching contributions to the 401(k) Plan and the cash payments of company matching contributions above IRC limits for the NEOs are included in the All Other Compensation column of the Summary Compensation Table and detailed in the footnote for that column.
Dominion also maintains two nonqualified retirement plans for its executives, the BRP and the ESRP. Unlike the DPP and 401(k) Plan, these plans are unfunded, unsecured obligations of Dominion. These plans keep Dominion competitive in attracting and retaining officers. Due to IRC limits on pension plan benefits and because a more substantial portion of total compensation for officers is paid as incentive compensation than for other employees, the DPP and 401(k) Plan alone will produce a lower percentage of replacement income in retirement for officers than these plans will for other employees. The BRP restores benefits that will not be paid under the DPP due to the IRC limits. The ESRP provides a benefit that covers a portion (25%) of final base salary and target annual incentive compensation to partially make up for this gap in retirement income. The BRP and ESRP do not include long-term incentive compensation in benefit calculations and, therefore, a significant portion of the potential compensation for the officers is excluded from calculation in any retirement plan benefit. As consideration for the benefits earned under the BRP and ESRP, all officers agree to comply with confidentiality and one-year non-competition requirements set forth in the plan documents following their retirement or other termination of employment. The present value of accumulated benefits under these retirement plans is disclosed in the Pension Benefits table and the terms of the plans are fully explained in the narrative following that table.
In individual situations and primarily for mid-career changes or retention purposes, the CGN Committee has granted certain officers additional years of credited age and service for purposes of calculating benefits under the BRP. Age and service credits granted to the NEOs are described in Dominion Retirement Benefit Restoration Plan under Pension Benefits. Additional age and service may also be earned under the terms of an officer’s Employee Continuity Agreement in the event of a change in control, as described in Change in Control under Potential Payments Upon Termination or Change in Control. No additional years of credit were granted to the NEOs during 2011.
OTHER BENEFIT PROGRAMS
Dominion’s officers participate in all of the benefit programs available to other Dominion employees. The core benefit programs generally include medical, dental and vision benefit plans, a health savings account, health and dependent care flexible spending accounts, group-term life insurance, travel accident coverage, long-term disability coverage and a paid time off program.
Dominion also maintains an executive life insurance program for officers to replace a former company-wide retiree life insurance program that was discontinued in 2003. The plan is fully insured by individual policies that provide death benefits at a fixed amount depending on an officer’s salary tier. This life insurance coverage is in addition to the group-term insurance that is provided to all employees. The officer is the owner of the policy and Dominion makes premium payments until the later of 10 years from enrollment date or the date the officer attains age 64. Officers are taxed on the premiums paid by Dominion. The premiums for these policies are included in the All Other Compensation column of the Summary Compensation Table.
PERQUISITES
Dominion provides a limited number of perquisites for officers to enable them to perform their duties and responsibilities as efficiently as possible and to minimize distractions. The CGN Committee annually reviews the perquisites to ensure they are an effective and efficient use of corporate resources. Dominion believes the benefits it receives from offering these perquisites outweigh the costs of providing them. In addition to incidental perquisites associated with maintaining an office, Dominion offers the following perquisites to all officers:

An allowance of up to $9,500 a year to be used for health club memberships and wellness programs, comprehensive executive physical exams and financial and estate planning. Dominion wants officers to be proactive with preventive healthcare and also wants executives to use professional, independent financial and estate planning consultants to ensure proper tax reporting of company-provided compensation and to help officers optimize their use of Dominion’s retirement and other employee benefit programs.

A vehicle leased by Dominion, up to an established lease-payment limit (if the lease payment exceeds the allowance, the officer pays for the excess amount on the vehicle). The costs of insurance, fuel and maintenance for company-leased vehicles are paid by Dominion.

In limited circumstances, use of company aircraft for personal travel by executive officers. For security and other reasons, the Board has directed Mr. Farrell to use the aircraft for all travel, including personal travel, whenever it is feasible to do so. His family and guests may accompany Mr. Farrell on any personal trips. The use of company aircraft for personal travel by other executive officers is limited and usually related to (i) travel with the CEO or (ii) personal travel to accommodate business demands on an executive’s schedule. With the exception of Mr. Farrell, personal use of aircraft is not available when there is a company need for the aircraft. Use of company aircraft saves substantial time and allows Dominion to have better access to the executives for business purposes. During 2011, 97% of the use of Dominion’s aircraft was for business purposes. Other than Mr. Farrell, none of the NEOs or other executive officers used company aircraft for personal travel in 2011.
Other than costs associated with comprehensive executive physical exams (which are exempt from taxation under the IRC), these perquisites are fully taxable to officers. There is no tax gross-up for imputed income on any perquisites.
EMPLOYMENT CONTINUITY AGREEMENTS
Dominion has entered into Employment Continuity Agreements with all officers to ensure continuity in the event of a change in control at Dominion. 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 of Dominion. In a time of transition, it is critical to protect shareholder value by retaining and continuing to motivate the company’s core management team. In a change in control situation, workloads typically increase dramatically, outside competitors are more likely to attempt to recruit top performers away
from the company, and officers and other key employees may consider other opportunities when faced with uncertainties at their own company. Therefore, the Employment Continuity Agreements provide security and protection to officers in such circumstances for the long-term benefit of Dominion and its shareholders.
In determining the appropriate multiples of compensation and benefits payable upon a change in control, Dominion evaluated peer group and general practices and considered the levels of protection necessary to retain officers in such situations. The Employment Continuity Agreements are double-trigger agreements that require both a change in control and a qualifying termination of employment to trigger a benefit. The specific terms of the Employment Continuity Agreements are discussed in Potential Payments Upon Termination or Change in Control.
OTHER AGREEMENTS
Dominion does not have comprehensive employment agreements or severance agreements for its NEOs. Although the CGN Committee believes the compensation and benefit programs described in this CD&A are appropriate, Dominion, as one of the nation’s largest producers and transporters of energy, is part of a constantly changing and increasingly competitive environment. In recognition of their valuable knowledge and experience and to secure and retain their services, Dominion has entered into letter agreements with certain of its NEOs to provide certain benefit enhancements or other protections, as described in Dominion Executive Supplemental Retirement Plan and Potential Payments Upon Termination or Change in Control.
OTHER RELEVANT COMPENSATION PRACTICES
Share Ownership Guidelines
Dominion requires officers to own and retain significant amounts of Dominion stock during their careers to align their interests with those of Dominion’s shareholders by promoting a long-term focus through long-term share ownership. The guidelines ensure that management maintains a personal stake in the company through significant equity investment in Dominion. Targeted ownership levels are the lesser of the following value or number of shares:
The levels of ownership reflect the increasing level of responsibility for that officer’s position. Shares owned by an officer and his or her immediate family members as well as shares held under company benefit plans contribute to the ownership targets. Restricted stock, goal-based stock and shares underlying stock options do not contribute to the ownership targets until the shares vest or the options are exercised. Dominion prohibits certain types of transactions related to Dominion stock, including owning derivative securities, hedging transactions, using margin accounts and pledging shares as collateral.
With limited exceptions, officers are expected to retain ownership of their Dominion stock, including restricted stock and goal-based shares that have vested, as long as they remain employed by the company. Dominion refers to shares held by an officer that are more than 15% above his or her ownership target as Qualifying Excess Shares. Officers may sell up to 50% of their Qualifying Excess Shares at any time, subject to insider trading rules and other policy provisions, and may sell all Qualifying Excess Shares during the one-year period preceding retirement. Qualifying Excess Shares may also be gifted to a charitable organization or put into a trust outside of the officer’s control for estate planning purposes at any time.
At least annually, the CGN Committee reviews the share ownership guidelines and monitors compliance by executive officers, both individually and by the officer group as a whole. The NEOs’ ownership is shown in
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
DOMINION
The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the headings Share Ownership-Director and Officer Share Ownership and Significant Shareholders in the 2012 Proxy Statement is incorporated by reference.
The information regarding equity securities of Dominion that are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation-Equity Compensation Plans in the 2012 Proxy Statement is incorporated by reference.
VIRGINIA POWER
The table below sets forth as of February 15, 2012, the number of shares of Dominion common stock owned by directors and by the executive officers of Virginia Power named on the Summary Compensation Table. Dominion owns all of the outstanding common stock of Virginia Power. None of the executive officers or directors own any of the outstanding preferred stock of Virginia Power.
(1) Includes shares as to which voting and/or investment power is shared with or controlled by another person as follows: Mr. Rogers, 643 (shares held in joint tenancy); all directors and executive officers as a group, 16,112.
(2) Neither any individual director or executive officer, nor all of the directors and executive officers as a group, own more than one percent of Dominion common shares outstanding as of February 15, 2012.
Item 13. Certain Relationships and Related Transactions, and Director Independence
DOMINION
The information regarding related party transactions required by this item found under the heading Related Party Transactions, and information regarding director independence found under the heading Director Independence, in the 2012 Proxy Statement is incorporated by reference.
VIRGINIA POWER
Related Party Transactions
Virginia Power’s Board of Directors has adopted the Related Party Guidelines also approved by Dominion’s Board of Direc-
tors. These guidelines were adopted for the purpose of identifying potential conflicts of interest arising out of financial transactions, arrangements and relations between Virginia Power and any related persons. Under the guidelines, a related person is a director, executive officer, director nominee, a beneficial owner of more than 5% of Dominion’s common stock, or any immediate family member of one of the foregoing persons. A related party transaction is any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships in excess of $120,000 in which Virginia Power (and/or any of its consolidated subsidiaries) is a party and in which the related person has or will have a direct or indirect material interest.
In determining whether a direct or indirect interest is material, the significance of the information to investors in light of all circumstances is considered. The importance of the interest to the person having the interest, the relationship of the parties to the transaction with each other and the amount involved are also among the factors considered in determining the significance of the information to the investors.
Dominion’s CGN Committee has reviewed certain categories of transactions and determined that transactions between Dominion and a related person that fall within such categories will not result in the related person receiving a direct or indirect material interest. Under the guidelines, such transactions are not deemed related party transactions and therefore not subject to review by the CGN Committee. The categories of excluded transactions include, among other items, compensation and expense reimbursement paid to directors and executive officers in the ordinary course of performing their duties; transactions with other companies where the related party’s only relationship is as an employee, if the aggregate amount involved does not exceed the greater of $1 million or 2% of that company’s gross revenues; and charitable contributions which are less than the greater of $1 million or 2% of the charity’s annual receipts. The full text of the guidelines can be found on Dominion’s website at www.dom.com/investors/corporate-governance/pdf/related_party_guidelines.pdf.
Virginia Power collects information about potential related party transactions in its annual questionnaires completed by directors and executive officers. Management reviews the potential related party transactions and assesses whether any of the identified transactions constitute a related party transaction. Any identified related party transactions are then reported to Dominion’s CGN Committee. Dominion’s CGN Committee reviews and considers relevant facts and circumstances and determines whether to ratify or approve the related party transactions identified. Dominion’s CGN Committee may only approve or ratify related party transactions that are in, or are not inconsistent with, the best interests of Dominion and its shareholders and are in compliance with Virginia Power’s Code of Ethics.
Since January 1, 2011 there have been no related party transactions involving Virginia Power that were required either to be approved under Virginia Power’s policies or reported under the SEC related party transactions rules.
Director Independence
Under NYSE listing standards, Messrs. Farrell, McGettrick and Rogers are not independent as they are executive officers of Virginia Power or of its parent company, Dominion. All of Virginia Power’s outstanding common stock is owned by Dominion and therefore, Virginia Power is a “controlled” company under the rules of the NYSE. Because Virginia Power meets the definition of a “controlled company” and has only preferred stock listed on the NYSE, it is exempt under Section 303A of the NYSE Rules from the provisions relating to board committees and the requirement to have a majority of its board be independent.
Item 14. Principal Accountant Fees and Services
DOMINION
The information concerning principal accountant fees and services contained under the heading Auditors-Fees and Pre-Approval Policy in the 2012 Proxy Statement is incorporated by reference.
VIRGINIA POWER
The following table presents fees paid to Deloitte & Touche LLP for the fiscal years ended December 31, 2011 and 2010.
Audit Fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power’s annual consolidated financial statements, the review of financial statements included in Virginia Power’s quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC.
Audit-Related Fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Virginia Power’s consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and attest services not required by statute or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.
Virginia Power’s Board of Directors has adopted the Dominion Audit Committee pre-approval policy for its independent auditor’s services and fees and has delegated the execution of this policy to the Dominion Audit Committee. In accordance with this delegation, each year the Dominion Audit Committee pre-approves a schedule that details the services to be provided for the following year and an estimated charge for such services. At its December 2011 and January 2012 meetings, the Dominion Audit Committee approved Virginia Power’s schedule of services and fees for 2012. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Audit Committee or a member of the Dominion Audit Committee.
Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.
1. Financial Statements
See Index on page 53.
2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.
3. Exhibits (incorporated by reference unless otherwise noted)
Exhibit
Number
Description
Dominion
Virginia
Power
Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1, Form 8-K filed March 15, 2010, File No. 1-8489).
X
3.1.a
Dominion Resources, Inc. Articles of Incorporation as amended and restated effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).
X
3.1.b
Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on March 3, 2011 (Exhibit 3.1b, Form 10-Q for the quarter ended March 30, 2011 filed April 29, 2011, File No. 1-2255).
X
3.2.a
Dominion Resources, Inc. Amended and Restated Bylaws, effective December 15, 2011 (Exhibit 3.1, Form 8-K filed December 14, 2011, File No. 1-8489).
X
3.2.b
Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).
X
Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.
X
X
4.1.a
See Exhibit 3.1.a above.
X
4.1.b
See Exhibit 3.1.b above.
X
4.2
Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255).
X
X
4.3
Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of First Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Eleventh Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255); Forms of Twelfth and Thirteenth Supplemental Indentures, dated January 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Forms of Sixteenth and Seventeenth Supplemental Indentures, dated November 1, 2007 (Exhibits 4.2 and 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008
X
X
Exhibit
Number
Description
Dominion
Virginia
Power
(Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255).
4.4
Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a First Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement filed April 22, 1998, File No. 333-50653); Forms of Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits 4.6 and 4.13, Form 8-K filed January 12, 2001, File No. 1-8489).
X
4.5
Indenture, dated May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012); Fifteenth Supplemental Indenture, dated October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651); Seventeenth Supplemental Indenture, dated August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Eighteenth Supplemental Indenture, dated December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Nineteenth Supplemental Indenture, dated January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Twentieth Supplemental Indenture, dated March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-3196); Twenty-First Supplemental Indenture, dated June 27, 2007 (Exhibit 4.2, Form 8-K filed July 3, 2007, File No. 1-8489).
X
4.6
Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2, Form 8-A filed April 21, 1995, File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2, Form 8-A filed December 12, 1996, File No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2, Form 8-A filed October 22, 1998, File No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004); Second Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.4, Form 8-K filed July 3, 2007, File No. 1-8489).
X
4.7
Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K filed June 22, 2000, File No. 1-8489); Forms of Second and Third Supplemental Indentures, dated July 1, 2000 (Exhibits 4.2 and 4.3, Form 8-K filed July 11, 2000, File No. 1-8489); Fourth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.2, Form 8-K filed September 8, 2000, File No. 1-8489); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K filed September 11, 2000, File No. 1-8489); Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K
X
Exhibit
Number
Description
Dominion
Virginia
Power
filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Forms of Seventeenth and Eighteenth Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489); Forms of Twentieth and Twenty-First Supplemental Indentures, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Third Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011 (Exhibit 4.3, Form 8-K filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K filed March 7, 2011, File No. 1-8489); Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K filed August 15, 2011, File No. 1-8489).
4.8
Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K filed April 12, 2001, File No. 1-3196); Forms of Second and Third Supplemental Indentures, dated October 25, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed October 23, 2001, File No. 1-3196); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K filed May 22, 2002, File No. 1-3196); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196); Seventh Supplemental Indenture, dated June 27, 2007 (Exhibit 4.6, Form 8-K filed July 3, 2007, File No. 1-8489).
X
4.9
Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489).
X
Exhibit
Number
Description
Dominion
Virginia
Power
4.10
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489).
X
4.11
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489 and File No. 1-2255).
X
4.12
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489 and File No. 1-2255).
X
10.1
DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (filed herewith).
X
10.2
DRS Services Agreement, dated January 1, 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (filed herewith).
X
X
10.3
Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489).
X
X
10.4
$3.0 billion Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, JP Morgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., Barclays Capital, The Royal Bank of Scotland plc, and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein. (Exhibit 10.1, Form 8-K filed September 28, 2010, File Nos. 1-8489 and 1-2255), as amended October 1, 2011 (Exhibit 10.1, Form 8-K filed October 3, 2011, File Nos. 1-8489 and 1-2255).
X
X
10.5
$500 million Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, Keybank National Association, as Administrative Agent, Bayerische Landesbank, New York Branch, and U.S. Bank National Association, as Syndication Agents, and other lenders named therein. (Exhibit 10.2, Form 8-K filed September 28, 2010, File Nos. 1-8489 and 1-2255), as amended October 1, 2011 (Exhibit 10.2, Form 8-K filed October 3, 2011, File Nos. 1-8489 and 1-2255).
X
X
10.6
Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003, File No. 1-8489).
X
X
10.7
Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489).
X
X
10.8
Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489), as amended June 20, 2007 (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489 and Exhibit 10.5, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-2255).
X
X
10.9
Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489).
X
X
10.10
Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489).
X
X
10.11*
Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489).
X
X
Exhibit
Number
Description
Dominion
Virginia
Power
10.12*
Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489), amended January 19, 2006 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2005 filed March 2, 2006, File No. 1-8489), as amended December 1, 2006 and further amended January 1, 2007 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2006, filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489).
X
X
10.13*
Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489), as amended January 1, 2007 (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255), as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255).
X
X
10.14*
Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489).
X
10.15*
Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).
X
10.16*
Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489).
X
10.17*
Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489).
X
10.18*
Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489 and File No. 1-2255).
X
X
10.19*
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011 (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 2010 filed February 28, 2011, File No. 1-8489).
X
10.20*
Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489).
X
X
10.21*
Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).
X
10.22*
Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489).
X
Exhibit
Number
Description
Dominion
Virginia
Power
10.23*
Supplemental retirement agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255).
X
10.24*
Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255).
X
10.25*
Letter Agreement between Consolidated Natural Gas Company and George A. Davidson, Jr. dated December 22, 1998, related letter dated January 8, 1999 and Amendment to Letter Agreement dated February 26, 2008 (Exhibit 10.37, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489).
X
10.26*
Form of Restricted Stock Grant under 2007 Long-Term Compensation Program approved March 30, 2007 (Exhibit 10.1, Form 8-K filed April 5, 2007, File No. 1-8489).
X
X
10.27*
Form of Restricted Stock Award Agreement under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.1, Form 8-K filed April 2, 2008, File No. 1-8489).
X
X
10.28*
2008 Performance Grant Plan under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.2, Form 8-K filed April 2, 2008, File No. 1-8489).
X
X
10.29*
Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255).
X
X
10.30*
2009 Performance Grant Plan under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.1, Form 8-K filed January 29, 2009, File No. 1-8489).
X
X
10.31*
Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489).
X
X
10.32*
Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective December 20, 2011 (filed herewith).
X
X
10.33*
2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489).
X
X
10.34*
Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489).
X
X
10.35*
Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010
(Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489).
X
X
10.36*
2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489).
X
X
10.37*
Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489).
X
X
10.38*
Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010
(Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489).
X
X
10.39*
Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).
X
10.40*
Non-employee directors’ annual compensation for Dominion Resources, Inc. (filed herewith).
X
10.41*
Restricted Stock Award Agreement for Gary L. Sypolt approved September 24, 2010 (Exhibit 10.46, Form 10-K for the fiscal year ended December 31, 2010 filed February 28, 2011, File No. 1-8489).
X
10.42*
2012 Performance Grant Plan under the 2012 Long-term Incentive Program approved January 19, 2012 (Exhibit 10.1, Form 8-K filed January 20, 2012, File No. 1-8489).
X
X
10.43*
Form Restricted Stock Award Agreement under the 2012 Long-term Incentive Program approved
January 19, 2012 (Exhibit 10.2, Form 8-K filed January 20, 2012. File No. 1-8489).
X
X
Exhibit
Number
Description
Dominion
Virginia
Power
12.a
Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).
X
12.b
Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).
X
12.c
Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).
X
Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith).
X
X
Consent of Deloitte & Touche LLP (filed herewith).
X
X
31.a
Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
31.b
Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
31.c
Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
31.d
Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
32.a
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
X
32.b
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
X
Towers Watson Energy Services Survey participants (filed herewith).
X
101^
The following financial statements from Dominion Resources, Inc. and Virginia Electric and Power Company Annual Report on Form 10-K for the year ended December 31, 2011, filed on February 28, 2012, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.
X
X
* Indicates management contract or compensatory plan or arrangement
^ This exhibit will not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 (15 U.S.C. 78r), or otherwise subject to the liability of that section. Such exhibit will not be deemed to be incorporated by reference into any filing under the Securities Act or Securities Exchange Act, except to the extent that one of the Companies specifically incorporates it by reference.
Signatures
DOMINION
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DOMINION RESOURCES, INC.
By:
/S/ THOMAS F. FARRELL II
(Thomas F. Farrell II, Chairman, President and Chief Executive Officer)
Date: February 28, 2012
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, 2012.
Signature
Title
/S/ THOMAS F. FARRELL II
Thomas F. Farrell II
Chairman of the Board of Directors, President and Chief
Executive Officer
/S/ WILLIAM P. BARR
William P. Barr
Director
/S/ PETER W. BROWN
Peter W. Brown
Director
/S/ GEORGE A. DAVIDSON, JR.
George A. Davidson, Jr.
Director
/S/ HELEN E. DRAGAS
Helen E. Dragas
Director
/S/ JOHN W. HARRIS
John W. Harris
Director
/S/ ROBERT S. JEPSON, JR.
Robert S. Jepson, Jr.
Director
/S/ MARK J. KINGTON
Mark J. Kington
Director
/S/ MARGARET A. MCKENNA
Margaret A. McKenna
Director
/S/ FRANK S. ROYAL
Frank S. Royal
Director
/S/ ROBERT H. SPILMAN, JR.
Robert H. Spilman, Jr.
Director
/S/ DAVID A. WOLLARD
David A. Wollard
Director
/S/ MARK F. MCGETTRICK
Mark F. McGettrick
Executive Vice President and Chief Financial Officer
/S/ ASHWINI SAWHNEY
Ashwini Sawhney
Vice President-Accounting and Controller (Chief Accounting Officer)
VIRGINIA POWER
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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, 2012
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, 2012.
Signature
Title
/S/ THOMAS F. FARRELL II
Thomas F. Farrell II
Chairman of the Board of Directors and Chief Executive Officer
/S/ MARK F. MCGETTRICK
Mark F. McGettrick
Director, Executive Vice President and Chief Financial Officer
/S/ ASHWINI SAWHNEY
Ashwini Sawhney
Vice President-Accounting (Chief Accounting Officer)
/S/ STEVEN A. ROGERS
Steven A. Rogers
Director
Exhibit Index
Exhibit
Number
Description
Dominion
Virginia
Power
Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1, Form 8-K filed March 15, 2010, File No. 1-8489).
X
3.1.a
Dominion Resources, Inc. Articles of Incorporation as amended and restated effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).
X
3.1.b
Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on March 3, 2011 (Exhibit 3.1b, Form 10-Q for the quarter ended March 30, 2011 filed April 29, 2011, File No. 1-2255).
X
3.2.a
Dominion Resources, Inc. Amended and Restated Bylaws, effective December 15, 2011 (Exhibit 3.1, Form 8-K filed December 14, 2011, File No. 1-8489).
X
3.2.b
Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).
X
Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.
X
X
4.1.a
See Exhibit 3.1.a above.
X
4.1.b
See Exhibit 3.1.b above.
X
4.2
Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255).
X
X
4.3
Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of First Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Eleventh Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255); Forms of Twelfth and Thirteenth Supplemental Indentures, dated January 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Forms of Sixteenth and Seventeenth Supplemental Indentures, dated November 1, 2007 (Exhibits 4.2 and 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255).
X
X
Exhibit
Number
Description
Dominion
Virginia
Power
4.4
Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a First Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement filed April 22, 1998, File No. 333-50653); Forms of Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits 4.6 and 4.13, Form 8-K filed January 12, 2001, File No. 1-8489).
X
4.5
Indenture, dated May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012); Fifteenth Supplemental Indenture, dated October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651); Seventeenth Supplemental Indenture, dated August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Eighteenth Supplemental Indenture, dated December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Nineteenth Supplemental Indenture, dated January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Twentieth Supplemental Indenture, dated March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-3196); Twenty-First Supplemental Indenture, dated June 27, 2007 (Exhibit 4.2, Form 8-K filed July 3, 2007, File No. 1-8489).
X
4.6
Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2, Form 8-A filed April 21, 1995, File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2, Form 8-A filed December 12, 1996, File No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2, Form 8-A filed October 22, 1998, File No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004); Second Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.4, Form 8-K filed July 3, 2007, File No. 1-8489).
X
4.7
Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K filed June 22, 2000, File No. 1-8489); Forms of Second and Third Supplemental Indentures, dated July 1, 2000 (Exhibits 4.2 and 4.3, Form 8-K filed July 11, 2000, File No. 1-8489); Fourth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.2, Form 8-K filed September 8, 2000, File No. 1-8489); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K filed September 11, 2000, File No. 1-8489); Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Forms of Seventeenth and Eighteenth Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed
X
Exhibit
Number
Description
Dominion
Virginia
Power
February 11, 2003, File No. 1-8489); Forms of Twentieth and Twenty-First Supplemental Indentures, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Third Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011 (Exhibit 4.3, Form 8-K filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K filed March 7, 2011, File No. 1-8489); Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K filed August 15, 2011, File No. 1-8489).
4.8
Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K filed April 12, 2001, File No. 1-3196); Forms of Second and Third Supplemental Indentures, dated October 25, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed October 23, 2001, File No. 1-3196); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K filed May 22, 2002, File No. 1-3196); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196); Seventh Supplemental Indenture, dated June 27, 2007 (Exhibit 4.6, Form 8-K filed July 3, 2007, File No. 1-8489).
X
4.9
Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489).
X
4.10
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489).
X
4.11
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489 and File No. 1-2255).
X
4.12
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489 and File No. 1-2255).
X
Exhibit
Number
Description
Dominion
Virginia
Power
10.1
DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (filed herewith).
X
10.2
DRS Services Agreement, dated January 1, 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (filed herewith).
X
X
10.3
Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489).
X
X
10.4
$3.0 billion Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, JP Morgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., Barclays Capital, The Royal Bank of Scotland plc, and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein. (Exhibit 10.1, Form 8-K filed September 28, 2010, File Nos. 1-8489 and 1-2255), as amended October 1, 2011 (Exhibit 10.1, Form 8-K filed October 3, 2011, File Nos. 1-8489 and 1-2255).
X
X
10.5
$500 million Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, Keybank National Association, as Administrative Agent, Bayerische Landesbank, New York Branch, and U.S. Bank National Association, as Syndication Agents, and other lenders named therein. (Exhibit 10.2, Form 8-K filed September 28, 2010, File Nos. 1-8489 and 1-2255), as amended October 1, 2011 (Exhibit 10.2, Form 8-K filed October 3, 2011, File Nos. 1-8489 and 1-2255).
X
X
10.6
Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003, File No. 1-8489).
X
X
10.7
Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489).
X
X
10.8
Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489), as amended June 20, 2007 (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489 and Exhibit 10.5, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-2255).
X
X
10.9
Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489).
X
X
10.10
Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489).
X
X
10.11*
Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489).
X
X
10.12*
Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489), amended January 19, 2006 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2005 filed March 2, 2006, File No. 1-8489), as amended December 1, 2006 and further amended January 1, 2007 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2006, filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489).
X
X
10.13*
Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489), as amended January 1, 2007 (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.2, Form 10-Q for the
X
X
Exhibit
Number
Description
Dominion
Virginia
Power
quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255), as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255).
10.14*
Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489).
X
10.15*
Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).
X
10.16*
Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489).
X
10.17*
Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489).
X
10.18*
Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489 and File No. 1-2255).
X
X
10.19*
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011 (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 2010 filed February 28, 2011, File No. 1-8489).
X
10.20*
Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489).
X
X
10.21*
Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).
X
10.22*
Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489).
X
10.23*
Supplemental retirement agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255).
X
10.24*
Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255).
X
10.25*
Letter Agreement between Consolidated Natural Gas Company and George A. Davidson, Jr. dated December 22, 1998, related letter dated January 8, 1999 and Amendment to Letter Agreement dated February 26, 2008 (Exhibit 10.37, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489).
X
10.26*
Form of Restricted Stock Grant under 2007 Long-Term Compensation Program approved March 30, 2007 (Exhibit 10.1, Form 8-K filed April 5, 2007, File No. 1-8489).
X
X
Exhibit
Number
Description
Dominion
Virginia
Power
10.27*
Form of Restricted Stock Award Agreement under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.1, Form 8-K filed April 2, 2008, File No. 1-8489).
X
X
10.28*
2008 Performance Grant Plan under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.2, Form 8-K filed April 2, 2008, File No. 1-8489).
X
X
10.29*
Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255).
X
X
10.30*
2009 Performance Grant Plan under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.1, Form 8-K filed January 29, 2009, File No. 1-8489).
X
X
10.31*
Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489).
X
X
10.32*
Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective December 20, 2011 (filed herewith).
X
X
10.33*
2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489).
X
X
10.34*
Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489).
X
X
10.35*
Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010
(Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489).
X
X
10.36*
2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489).
X
X
10.37*
Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489).
X
X
10.38*
Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010
(Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489).
X
X
10.39*
Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).
X
10.40*
Non-employee directors’ annual compensation for Dominion Resources, Inc. (filed herewith).
X
10.41*
Restricted Stock Award Agreement for Gary L. Sypolt approved September 24, 2010 (Exhibit 10.46, Form 10-K for the fiscal year ended December 31, 2010 filed February 28, 2011, File No. 1-8489).
X
10.42*
2012 Performance Grant Plan under the 2012 Long-term Incentive Program approved January 19, 2012 (Exhibit 10.1, Form 8-K filed January 20, 2012, File No. 1-8489).
X
X
10.43*
Form Restricted Stock Award Agreement under the 2012 Long-term Incentive Program approved January 19, 2012 (Exhibit 10.2, Form 8-K filed January 20, 2012. File No. 1-8489).
X
X
12.a
Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).
X
12.b
Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).
X
12.c
Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).
X
Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith).
X
X
Consent of Deloitte & Touche LLP (filed herewith).
X
X
31.a
Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
31.b
Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
Exhibit
Number
Description
Dominion
Virginia
Power
31.c
Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
31.d
Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
X
32.a
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
X
32.b
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
X
Towers Watson Energy Services Survey participants (filed herewith).
X
101^
The following financial statements from Dominion Resources, Inc. and Virginia Electric and Power Company Annual Report on Form 10-K for the year ended December 31, 2011, filed on February 28, 2012, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.
X
X
* Indicates management contract or compensatory plan or arrangement
^ This exhibit will not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 (15 U.S.C. 78r), or otherwise subject to the liability of that section. Such exhibit will not be deemed to be incorporated by reference into any filing under the Securities Act or Securities Exchange Act, except to the extent that one of the Companies specifically incorporates it by reference.