EMPLOYEES

As of December 31, 2010,2012, Dominion had approximately 15,80015,500 full-time employees, of which approximately 5,9005,800 employees are subject to collective bargaining agreements. As of December 31, 2010,2012, Virginia Power had approximately 6,800 full-time employees, of which approximately 3,0003,100 employees are subject to collective bargaining agreements. See Note 23 for discussion of the Companies’ workforce reduction program.

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 DOMINIONAND 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.

ACQUISITIONSANDDISPOSITIONS

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.

SALEOF 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 43 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.

In 2006, Dominion received approximately $393 million of proceeds from sales of certain gas and oil properties, primarily resulting from the sale of certain properties located in Texas and New Mexico.

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 54 to the Consolidated Financial Statements.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 2.5 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.

In December 2010, Virginia PowerDVP has announced its five-year investment plan, which includes spending approximately $4$4.5 billion from 2013 through 2017 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 populationcustomer 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. ChangesVariability in revenue areearnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation. Variabilityconservation, in earnings results from changes in rates, weather, the economy, customer growth andaddition 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

PROPERTIES

Virginia Power has approximately 6,1006,300 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 December 2012, Virginia Power is involved in twocompleted construction of the major construction projectsHayes-to-Yorktown line at a total project cost of $79 million. This previously authorized in 2006, which arePJM project was designed to improve the reliability of service to customers and the region—Meadow Brook-to-Loudoun and Carson-to-Suffolk.

In October 2008,region. Previously approved PJM-authorized reliability projects such as the Virginia Commission authorized construction ofWaxpool-Brambleton-BECO line ($49 million), the Meadow Brook-to-LoudounHarrisonburg-to-Endless Caverns line and affirmed($66 million) the 65-mile route proposed for the line which is adjacent to, or within, existing transmission line rights-of-way. The Virginia Commission’s approval of the Meadow Brook-to-Loudoun line was conditioned on the respective state commission approvals of both the West Virginia and Pennsylvania portions of the transmission line. The West Virginia Commission’s approval of Trans-Allegheny Interstate Line Company’s application became effective in February 2009Radnor Heights Project ($81 million), and the Pennsylvania Commission granted approval in December 2008. On appeal by the ECCP, the Pennsylvania Commonwealth Court affirmed in May 2010 the Pennsylvania Commission’s approvalDooms-to-Bremo line ($65 million) continue to progress and subsequently denied a request for reargument by the ECCP in June 2010. The Meadow

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. This sustained decline in power prices in conjunction with Dominion’s regular strategic review of its portfolio of assets has led to its decision to pursue the sale or retirement of certain merchant generation assets, which is discussed in more detail below. 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. SeeRegulation—State Regulations—ElectricRegulation-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 fromthe majority of which expire between December 31, 2012 to Augustand December 31, 2017,2013, and is therefore largely unaffected by price competition during the termterms of these contracts. Following expirationIt was announced during the third quarter of 2012 that Dominion would pursue the sale of these contracts, earnings couldMidwest assets, excluding its wind facilities. In the fourth quarter of 2012, Dominion announced that Kewaunee is expected to be adversely impacted if prevailing prices for energy, capacity and ancillary services are lower than the levels currently received under these contracts.decommissioned beginning in 2013.

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

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 became effective in December 2012 and did not 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 Surry and North Anna 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’sNRC 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 billionreflected in 2010 dollarsthe table below and is primarily based upon site-specific studies completed in 2009. These cost studies are generally completed every four years. 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.

Also see Note 14 and Note 22 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.operations and its investment in the Blue Racer joint venture. 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. SeeFuture Issues and Other Matters in MD&A for more information. The Blue Racer joint venture will concentrate on building new gathering, processing, fractionation and NGL transportation assets as the development of the Utica Shale formation increases. Dominion will contribute to the joint venture a network of wet gas gathering assets, the Natrium extraction plant and other assets.

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, transportation and transportationgathering service 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

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 262,000349,000 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 123133 compressor stations with more than 768,000832,000 installed compressor horsepower.

In July 2008, East Ohio launched the PIR program to replace approximately 20% of its 21,000-mile pipeline system. The project, which is anticipated to cost approximately $2.6 billion, primarily involves the replacement of East Ohio’s bare steel, cast iron, wrought iron and copper pipe over a 25-year period. As part of this program, East Ohio will assume ownership of curb-to-meter service lines and will be responsible for line repairs or replacement. In October 2008, the Ohio Commission approved cost recovery for an initial five-year period of the PIR program.

In 2006, FERC approved the proposed expansion of Dominion’s Cove Point terminal and2012, DTI pipeline and the commencement of construction of the project. The expansion project included the installation of two new LNG storage tanks at Dominion’s Cove Point terminal, each capable of storing 160,000 cubic meters of LNG, pumps, gas-turbine generators, and vaporization capacity to increase the terminal send-out by 800,000 dekatherms per day. Dominion installed 48 miles of 36-inch pipeline to increase the terminal take-away capacity to approximately 1,800,000 dekatherms per day. In addition, Dominion’s DTI gas pipeline and storage system was expanded by building approximately 120 miles of pipeline, two new compressor stations in Pennsylvania and upgrades to other compressor stations in West Virginia and New York. The DTI facilities associated with the Cove Point expansion project were placed into service in December 2008, the Cove Point LNG terminal expansion was placed into service in January 2009 and the remainder of the expanded Cove Point facilities were placed into commercial service in March 2009.

In March 2010, Dominion commenced construction of the Cove Point Pier Reinforcement Project. The $50 million project is intended 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 what can currently be accommodated (no larger than 148,000 cubic meters). The project commenced with the south berth being taken temporarily out of service to accommodate construction activities. In October 2010, Dominion requested and received FERC authorization to re-commence service from the south berth of the pier for vessels with cargo capacities of no greater than 148,000 cubic meters. When the south berth was returned to service, construction commenced on the north berth, which was taken out of service. In December 2010, Dominion

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,March; however implementation of the straight fixed variablestraight-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 Peoplesoperations that are expected to be and certain DCI operations,are currently discontinued, which

The Virginia Commission denied additional funding for the Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs. As a result, Virginia Power plansbegan winding down these programs in the second quarter of 2012. These two programs are no longer available in Virginia.

In August 2012, Virginia Power filed an application for approval to seekextend two residential DSM programs (the Air Conditioner Cycling program and the Low Income program) beyond April 30, 2013 for periods of five years and two years, respectively. Virginia CommissionPower also filed for approval of the redesigned distributed generationupdated rate adjustment clauses for DSM program cost recovery, and several other DSM programs in 2011.for Electric Vehicle Pilot Program cost recovery. This case is pending.

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 listed above,initially approved in Virginia in 2010, as well as the redesigned distributed generation program. In February 2011, the North Carolina Commission approved the five DSM programs listed above.approved in Virginia, and Virginia Power subsequently launched the residential lighting program in May 2011 and the remainder of the approved Virginia DSM programs in June 2011. The Residential Lighting Program ended in North Carolina on December 31, 2011. In a separate order issued in September of 2011, the North Carolina Commission will make a decision regarding the appropriate rate making treatment for the programs in a separate proceeding.denied approval of Virginia Power’s proposed distributed generation program.

In August 2011, Virginia Power expects to launchfiled with the North Carolina Commission an application for approval and its updated request for cost recovery of the five DSM programs within itsapproved in North Carolina, service territory inas well as the second quarter ofthen-pending distributed generation program. In December 2011, subject to cost recovery approval by the North Carolina Commission.Commission approved updated cost recovery for the five DSM programs, as Virginia Power withdrew its cost recovery request for the distributed generation program. In a separate order issued in August 2012, the North Carolina Commission approved Virginia Power’s request for approval ofto suspend the redesigned distributed generation program remains pending beforeCommercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs which had been wound down and closed in Virginia.

In August 2012, Virginia Power filed with the North Carolina Commission.Commission an application for approval and its updated request for cost recovery for the five DSM programs approved in North Carolina, as well as cost recovery for projected costs of Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs on a North Carolina-only basis. In December 2012, the North Carolina Commission approved updated cost recovery for the five DSM programs, and requested an additional filing on whether the Commercial Lighting and the

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. One component of thePowering Virginia program involves consideration of the extent to which Virginia Power can reduce the carbon intensity of its generation fleet by developing generation facilities with zero CO₂ and low CO₂ emissions, as well as economically viable facilities that can be equipped for CO₂ capture and storage. There are six generally recognized GHGs including CO₂, methane, nitrous oxide, sulfur hexafluoride, hydrofluorocarbons, and perfluorocarbons. The focus is on new generation because there is no current economically viable technological solution to retro-fit existing fossil-fueled technology to capture and store GHG emissions. Given that new generation units have useful lives of up to 55 years, Virginia Power will consider CO₂ and other GHG emissions when making these long-term decisions. SeeDominion Generation—Properties for more information.

Improvements in Other Energy Infrastructure

In December 2010, Virginia Power announced itsPower’s five-year investment plan which includes spending approximately $4 billionsignificant 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

EPA Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98. Dominion’s GHG inventory now follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98 for calculating emissions.

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 2011, 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 29% and 18%, respectively. During such time period, the capacity of Dominion and Virginia Power’s electric generation fleet has grown. The Companies do not yet have final 2012 emissions data.

Alternative Energy Initiatives

The AES department conducts research in the renewable and alternative energy technologies sector and supports strategic investments to advance Dominion’s degree 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 December 2012, Virginia Power was selected by the DOE to begin negotiations for initial engineering, design and permitting work for a wind turbine demonstration facility approximately 24 miles off the coast of Virginia. The proposed 12 MW grid-connected facility would generate power via two turbines mounted on foundations driven into the ocean floor. In March 2011, Dominion issued a report evaluating high-voltage underwater transmission lines 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.

In 2012, Dominion continued to enhance and refine its EDGE^® grid-side efficiency product suite. EDGE^® is a modular and adaptive conservation voltage management solution enabling utilities to deploy incremental grid-side energy management that requires no behavioral changes or purchases by end customers. In February 2013, Dominion was awarded a patent relating to the EDGE^® technology.

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.

Costs of fuel used for the generation of electricity, along with customers.

costs of purchased power, are recovered from customers through an annually approved fuel rider, as provided under a separate section of the Virginia Power previously filed withCode. Decisions of the Virginia Commission an application for approval and cost recovery of eleven DSM programs, including one peak-shaving program and ten energy efficiency programs. Virginia Power plans to use DSM, along with its traditional and renewable supply-side resources, to meet its projected load growth over the next 15 years. The DSM programs provide the first steps toward achieving Virginia’s goal of reducing, by 2022, the electric energy consumption of Virginia Power’s retail customers by ten percent of what was consumed in 2006. In March 2010, the Virginia Commission approved the recovery of approximately $28 million for five of the DSM programs through initiation of Riders C1 and C2, effective May 1, 2010. With respectmay be appealed to the other six DSM programs for which approval was sought, the Virginia Commission made a finding that they were not in the public interest at that time, but allowed Virginia Power the opportunity for further evaluationSupreme Court of similar programs. In July 2010, Virginia Power submitted its annual update filing for Riders C1 and C2 with respect to the five approved DSM programs. The proposed revenue requirements for Riders C1 and C2 were approximately $6 million and $18 million, respectively, which together represent a decrease of approximately $5 million compared to the Riders C1 and C2 revenue requirements included in customer rates currently in effect. In February 2011, an evidentiary hearing was held by the Virginia Commission on Virginia Power’s update of Riders C1 and C2. The Virginia Commission is required to issue its order by March 30, 2011. Virginia Power plans to seek Virginia Commission approval for several DSM programs in 2011. SeeEnvironmental Strategy for a description of Virginia Power’s DSM programs.

In connection with the Bear Garden and Virginia City Hybrid Energy Center projects, in June 2010, Virginia Power filed annual updates for Riders R and S, respectively, with the Virginia Commission. Initially, Virginia Power proposed an approximately $86 million revenue requirement for Rider R for the April 1, 2011 to March 31, 2012 rate year. Due to the application of accelerated tax depreciation provisions in the Small Business Jobs Act of 2010, passed in September 2010, Virginia Power revised the requested revenue requirement for Rider R in November 2010 from $86 million to $78 million. The adjusted $78 million revenue requirement represents an increase of approximately $14 million over the revenue requirement associated with the Rider R customer rates currently in effect. The proposed Rider S revenue requirement, effective April 1, 2011, for the rate year ending March 31, 2012 is approximately $200 million, which represents an increase of $46 million over the revenue requirement associated with the Rider S customer rates currently in effect. The ROE included in both rider filings is 12.3%, which is consistent with the terms of the Virginia Settlement Approval Order. In July 2010, the Virginia Commission issued orders with respect to Riders R and S, which adopted a placeholder ROE of 11.3% (not including the 100 basis point statutory enhancement) for use until the ROE is determined in the context of Virginia Power’s upcoming biennial review. Evidentiary hearings were held by the Virginia Commission on Riders R and S in December and November 2010, respectively.

capital expenditures relating to environmental compliance required to be discussed in this Item, seeEnvironmental MattersinFuture Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 2322 to the Consolidated Financial Statements.

GLOBAL CLIMATE CHANGE

General

In recent years there has been increasedThe national and international attention toin recent years on GHG emissions and their relationship to climate change which has resulted in federal, regional and state legislative or regulatory action in this area. Dominion and Virginia Power support national climate change legislation tothat 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.

Dominion has developed a comprehensive GHG inventory for calendar year 2009. For Dominion Generation, Dominion’s SeeEnvironmental Strategyabove, Environmental Matters inFuture Issues and Virginia Power’s direct CO₂ equivalent emissions, based on equity share (ownership), were approximately 54 million metric tonnesOther Mattersin Item 7. MD&A and 33 million metric tonnes, respectively, in 2009. 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 2.5 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 2010 emissions data, they do not expect a significant variance in emissions from 2009 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 wasThe 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 wasGreenhouse Gas Emission Estimation Guidelines for NaturalGas Transmission and Storage, Volume 1-GHG EstimationMethodologies and Procedures-Revision 2, September 28, 2005 developed by the Interstate Natural Gas Association of America.

Power was required to discontinue deferral accounting for certain existing rate adjustment clauses as of December 1, 2011. As a result, Virginia Power may potentially not fully recover costs associated with these existing rate adjustment clauses.

Virginia Power’s retail electric base rates for bundled generation, transmission, and distribution services to customers 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. 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 through base rates, on a timely basis, of costs incurred in providing service, Virginia Power’s future earnings could be negatively impacted.

Dominion and Virginia Power are subject to complex governmental regulation that could adversely affect their results of operations.operations and subject the Companies to monetary penalties.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 theirthe business is conducted in accordance with applicable laws. However, newThe Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if either Dominion or Virginia Power is found not to be in compliance, including mandatory reliability standards and interaction in the wholesale markets. 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’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 depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs 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.

Dominion and Virginia Power couldinfrastructure build plans often require regulatory approval before construction can commence. 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 subjectable to penaltiesachieve 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

If additional federal and/or state requirements are imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements, suchrequirements may result in compliancecosts that alone or in combinationcombination could make some of Dominion’s or Virginia Power’s electric generationgeneration units or natural gas facilities uneconomical to maintain or operate.The U.S. Congress,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 federal legislation and/or additional EPA regulation,regulations, and possibly additional state legislation and/or regulation,regulations, may passbe 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 andor 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 hasand 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,

tracted 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.

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, then 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.market, including as a result of market supply shortages. 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.

Energy conservation could negatively impact Dominion’s merchant powerand 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.

Exposure to counterparty performance may be negatively affectedadversely 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 possible FERC actions that could weaken competition incustomers, suppliers or other third parties may adversely affect the wholesale markets or affect pricing rules in the RTO markets.Dominion’s merchant generation stations operating in PJM, MISO and ISO-NE sell capacity, energy and ancillary services into wholesale elec-Companies’ financial results.

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, counterpartyprice volatility, credit strength of the Companies’ counterparties and price volatility.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 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. Final rules for the over-the-counter derivatives-relatedderivative-related provisions of the Dodd-Frank Act including the clearing, exchange trading and capital and margin requirements, will continue to be established through the CFTC’songoing rulemaking process which is required to be completed by July 2011.of the applicable regulators. 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.requirements, for their derivative activities. In addition, implementation of, and compliance with, the over-the-counter derivativesderivative provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in increased costs related to the Companies’ derivative activities.

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. Management anticipates that they will be required to seek additional financing in the future to fund current and future plant construction and expansion projects and may not be able to secure such financing on favorable terms. In addition, 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

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.

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. An aging workforce in the energy industry necessitates recruiting, retaining and developing the next generation of leadership.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

As of December 31, 2010,2012, 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.