Dominion Energy - 10-K annual report

Dominion has transitioned to a more regulated, less volatile earnings mix as evidenced by its capital investments in regulated infrastructure and infrastructure whose output is sold under long-term purchase agreements, as well as dispositions of certain merchant generation facilities during 2013 and the sale of the electric retail energy marketing business in March 2014. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and natural gas retail energy marketing operations. Dominion’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Gas.

Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a wholly-owned subsidiary of Dominion and 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” and primarily serves retail customers. 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 stock is owned by Dominion.

Dominion Gas, a limited liability company formed in September 2013, is a wholly-owned subsidiary of Dominion and a holding company. It serves as the intermediate parent company for the majority of Dominion’s regulated natural gas operating subsidiaries, which conduct business activities through a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution operations in Ohio, and gas gathering and processing activities primarily in West Virginia, Ohio and Pennsylvania. Dominion Gas’ wholly-owned subsidiaries are DTI, East Ohio and Dominion Iroquois. DTI is an interstate natural gas transmission pipeline company serving a broad mix of customers such as local gas distribution companies, marketers, interstate and intrastate pipelines, electric power generators and natural gas producers. The DTI system links to other major pipelines and markets in the mid-Atlantic, Northeast, and Midwest including Dominion’s Cove Point pipeline. DTI also operates one of the largest underground natural gas storage systems in the U.S. and is a producer and supplier of NGLs. East Ohio is a regulated natural gas distribution operation serving residential, commercial and industrial gas sales and transportation customers. Its service territory includes Cleveland, Akron, Canton, Youngstown and other eastern and western Ohio communities. Dominion Iroquois holds a 24.72% general partnership interest in a 416-mile FERC–regulated interstate natural gas pipeline extending from the U.S.-Canadian border at Waddington, New York through the state of Connecticut to South Commack, New York and Hunts Point, Bronx, New York. All of Dominion Gas’ membership interests are owned by Dominion.

Amounts and information disclosed for Dominion are inclusive of Virginia Power and/or Dominion Gas, where applicable.

for consideration of approximately $84 million. Dominion Gas’ consideration consisted of $17 million in cash proceeds and the extinguishment of affiliated current borrowings of $67 million and Dominion’s consideration consisted of cash proceeds of approximately $84 million.

In September 2013, DTI sold Line TL-388 to Blue Racer for approximately $75 million in cash proceeds.

In December 2012, East Ohio sold two pipeline systems to an affiliate for consideration of approximately $248 million. East Ohio’s consideration consisted of $61 million in cash proceeds and the extinguishment of affiliated long-term debt of $187 million and Dominion’s consideration consisted of a 50% interest in Blue Racer and cash proceeds of approximately $115 million.

See Note 9 to the Consolidated Financial Statements for additional information on sales of pipelines and pipeline systems.

ASSIGNMENTS OFMARCELLUS SHALE ACREAGE

In November 2014, DTI closed an agreement with a natural gas producer to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provides for payments to DTI, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas produced from the acreage.

In December 2013, DTI closed on agreements with two natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several natural gas storage fields. The agreements provide for payments to DTI, subject to customary adjustments, of approximately $200 million over a period of nine years, and overriding royalty interest in gas produced from that acreage.

See Note 10 to the Consolidated Financial Statements for additional information on these sales of Marcellus acreage.

SALE OF BRAYTON POINT, KINCAID AND EQUITY METHOD INVESTMENTIN ELWOOD

In August 2013, Dominion completed the sale of Brayton Point, Kincaid and its equity method investment in Elwood to Energy Capital Partners and received proceeds of approximately $465 million, net of transaction costs. The historical results of Brayton Point’s and Kincaid’s operations are included in the Corporate and Other segment and presented in discontinued operations. See Note 3 to the Consolidated Financial Statements for additional information.

SALE OF E&P PROPERTIES

In April 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations, including its rights to associated Marcellus acreage, to a subsidiary of CONSOL for approximately $3.5 billion.

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.

tribution (including customer service) operations, which serve approximately 2.5 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.

DVP announced its six-year investment plan, which includes spending approximately $8.9 billion from 2015 through 2020 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 customer growth and increases in electricity consumption by the typical consumer. In addition, data centers continue to contribute to anticipated demand growth.

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. Virginia Power continues to see improvement as SAIDI performance results, excluding major events, were 113 minutes at the end of 2014, down from the three-year average of 120 minutes. Virginia Power’s overall customer satisfaction improved year over year when compared to its 2013 score in the South Large segment of JD Power’s rankings. In the future, safety, electric service reliability and customer service will remain key focus areas for electric distribution.

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.

COMPETITION

DVP Operating Segment—Dominion and Virginia Power

There is no competition for electric distribution service within Virginia Power’s service territory in Virginia and North Carolina and no such competition is currently permitted. Historically, since its electric transmission facilities are integrated into PJM and electric transmission services are administered by PJM, there was no competition in relation to transmission service provided to customers within the PJM region. However, competition from non-incumbent PJM transmission owners for development, construction and ownership of certain transmission facilities in Virginia Power’s service territory is now permitted pursuant to FERC Order 1000, subject to state and local siting and permit-

owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.

Virginia legislation in 2014 provides for the recovery of costs, subject to approval by the Virginia Commission, for Virginia Power to move approximately 4,000 miles of electric distribution lines underground. The program, designed to reduce restoration outage time, has an annual investment cap of approximately $175 million, and is expected to be implemented over the next decade.

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.

SEASONALITY

DVP Operating Segment—Dominion and Virginia Power

DVP’s earnings vary seasonally as a result of the impact of changes in temperature, the impact of storms and other catastrophic weather events, 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.

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. The Dominion Generation Operating Segment of Dominion includes Virginia Power’s generation facilities and its related energy supply operations as well as the generation operations of Dominion’s merchant fleet and energy marketing and price risk management activities for these assets and Dominion’s nonregulated natural gas retail energy marketing operations.

Dominion Generation’s six-year electric utility investment plan includes spending approximately $9.7 billion from 2015 through 2020 to construct new generation capacity to meet growing electricity demand within its utility service territory. The most significant project currently under construction is Brunswick County, which is estimated to cost approximately $1.2 billion, excluding financing costs. See Properties for additional information on this and other utility projects.

In addition, Dominion’s merchant fleet has acquired and developed numerous renewable generation projects, which began operations in 2013 and 2014. The total cost of the projects is approximately $856 million, excluding financing costs, and includes a fuel cell generation facility in Connecticut and solar generation facilities in California, Indiana, Georgia, Tennessee and Connecticut. The output of these facilities is sold under long-term power purchase agreements with terms ranging from 15 to

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 nonrenewable merchant generation fleet is dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that provides for a rate of return on its capital investments. Dominion Generation’s recently acquired and developed renewable generation projects are not subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements lasting between 15 and 25 years. Competition for the nonrenewable 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 nonrenewable merchant assets 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 nonrenewable merchant units 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 nonrenewable merchant fleet is competitive compared to similar assets within the region.

Dominion’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas. 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

Dominion Generation Operating Segment—Dominion and Virginia Power

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

includes nuclear, natural gas, and renewables. Merchant nonrenewable generation facilities are located in Connecticut, Pennsylvania and Rhode Island, with a majority of that capacity concentrated in New England. Dominion’s merchant renewable generation facilities include a fuel cell generation facility in Connecticut, solar generation facilities in Indiana, Georgia, California, Tennessee and Connecticut, and wind generation facilities in Indiana and West Virginia. Additional solar projects under construction are as set forth below:

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 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 domestic 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 and Marcellus and Utica regions, 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 provides for reliable natural gas deliveries to its gas turbine fleet, while minimizing costs.

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 are placed into trusts and are 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 requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC.

The estimated cost to decommission Virginia Power’s four nuclear units is reflected in the table below and is primarily based upon site-specific studies completed in 2014. These cost studies are generally completed every four to five 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 2078.

Dominion Generation Operating Segment—Dominion

In addition to the four nuclear units discussed above, Dominion has two licensed, operating nuclear reactors at Millstone in Connecticut. A third Millstone unit ceased operations before Dominion acquired the power station. In May 2013, Dominion ceased operations at its single unit Kewaunee nuclear power station in Wisconsin and commenced decommissioning activities using the SAFSTOR methodology. The planned decommissioning completion date is 2073, which is within the NRC allowed 60 year window.

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 requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. The estimated cost to decommission Dominion’s eight units is reflected in the table below and is primarily based upon site-specific studies completed for Surry, North Anna and Millstone in 2014 and for Kewaunee in 2013.

Earnings for the Dominion Energy Operating Segment of Dominion Gas primarily result from rates established by FERC and the Ohio Commission. The profitability of these businesses is dependent on Dominion Gas’ 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 changes in 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.

Revenue from processing and fractionation operations largely results from the sale of commodities at market prices. For DTI’s processing plants, Dominion Gas purchases the wet gas product from producers and retains some or all of the extracted NGLs as compensation for its services. This exposes Dominion Gas to commodity price risk for the value of the spread between the NGL products and natural gas. In addition, Dominion Gas has volumetric risk since gas deliveries to DTI’s facilities are not under long-term contracts.

East Ohio utilizes a straight-fixed-variable rate design for a majority of its customers. 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.

In addition to the operations of Dominion Gas, the Dominion Energy Operating Segment of Dominion also includes LNG operations and Hope’s gas distribution operations in West Virginia, as well as Dominion’s investments in the Blue Racer joint venture, Atlantic Coast Pipeline and Dominion Midstream. See Properties and Investments below for additional information regarding the Atlantic Coast Pipeline investment. 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. Dominion has received DOE and FERC approval to export LNG from Cove Point and has begun construction on a bi-directional facility, which will be able to import LNG, and vaporize it as natural gas, and liquefy natural gas and export it as LNG. See Note 22 to the Consolidated Financial Statements for more information.

In 2014, Dominion formed Dominion Midstream, an MLP initially consisting of a preferred equity interest in Cove Point. See General above for more information. Also see Note 3 to the Consolidated Financial Statements for a description of Dominion’s acquisition of CGT, which Dominion expects to contribute to Dominion Midstream in the first half of 2015.

The Blue Racer joint venture concentrates on building new gathering, processing, fractionation and NGL transportation assets as the development of the Utica Shale formation increases. Dominion has contributed or sold various assets to the joint venture. See Note 9 to the Consolidated Financial Statements for more information.

Dominion Energy’s six-year investment plan includes spending approximately $8.9 billion from 2015 through 2020 to upgrade existing infrastructure or add new pipelines to meet growing energy needs within its service territory and maintain reliability. This plan includes spending for the Atlantic Coast Pipeline project and approximately $2.6 billion, exclusive of financing costs, for the Liquefaction Project.

Regulation-State Regulations-Gas for additional information.

Cove Point’s LNG operations are not subject to significant competition due to the long-term nature of their contracts.

REGULATION

Dominion Energy Operating Segment—Dominion and Dominion Gas

Dominion Gas’ natural gas transmission, storage, processing and gathering operations are regulated primarily by FERC. East Ohio’s gas distribution operations, including the rates that it may charge to customers, are regulated by the Ohio Commission. See State Regulations and Federal Regulations inRegulation for more information.

Dominion Energy Operating Segment—Dominion

Dominion’s LNG operations are regulated primarily by FERC. Hope’s gas distribution operations, including the rates that it may charge customers, are regulated by the West Virginia Commission. See State Regulations and Federal Regulations in Regulation for more information.

PROPERTIES AND INVESTMENTS

Dominion Energy Operating Segment—Dominion and Dominion Gas

East Ohio’s gas distribution network is located in Ohio. This network involves approximately 18,800 miles of pipe, exclusive of service lines. The rights-of-way grants for many natural gas pipelines have been obtained from the actual owners 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 Gas has approximately 7,700 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Gas owns gas processing and fractionation facilities in West Virginia with a total processing capacity of 270,000 mcf per day and fractionation capacity of 580,000 Gals per day. Dominion Gas also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with approximately 2,000 storage wells and approximately 399,000 acres of operated leaseholds.

The total designed capacity of the underground storage fields operated by Dominion Gas is approximately 947 bcf. Certain storage fields are jointly-owned and operated by Dominion Gas. The capacity of those fields owned by Dominion Gas’ partners totals about 242 bcf.

In December 2013, DTI closed on agreements with two natural gas producers to convey approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. In September 2014, DTI closed on an agreement with a natural gas producer to convey approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. In November 2014, DTI closed on an agreement with a natural gas producer to convey approximately 11,000 acres of Marcellus Shale development rights underneath

FERC authorization to construct and operate the project facilities, which are expected to be in service in the fourth quarter of 2016.

In November 2014, DTI placed into service its $42 million Natrium-to-Market project. The project is designed to provide 185,000 Dths per day of firm transportation from an interconnect between DTI and the Natrium facility to the Crayne interconnect. Four customers have entered into binding precedent agreements for the full project capacity under 8-year and 13-year terms.

In September 2013, DTI executed binding precedent agreements with several local distribution company customers for the New Market Project. The project is expected to cost approximately $159 million and provide 112,000 Dths per day of firm transportation service from Leidy, Pennsylvania to interconnects with Iroquois and Niagara Mohawk Power Corporation’s distribution system in the Albany, New York market. In June 2014, DTI filed an application to request FERC authorization to construct and operate the project facilities, which are expected to be in service in the fourth quarter of 2016.

In October 2013, DTI executed a binding precedent agreement with CNX Gas Company LLC for the Clarington Project. The project is expected to cost approximately $78 million and provide 250,000 Dths per day of firm transportation service from central West Virginia to Clarington, Ohio. In June 2014, DTI filed an application to request FERC authorization to construct and operate the project facilities, which are expected to be in service in the fourth quarter of 2016.

In November 2014, DTI placed into service its $112 million Allegheny Storage Project, which provides approximately 7.5 bcf of incremental storage service and 125,000 Dths per day of associated year-round firm transportation service to three local distribution companies under 15-year contracts.

In 2008, East Ohio began PIR, aimed at replacing approximately 4,100 miles of its pipeline system at a cost of $2.7 billion. In 2011, approval was obtained to include an additional 1,450 miles and to increase annual capital investment to meet the program goal. The program will replace approximately 25% of the pipeline system and is anticipated to take place over a total of 25 years.

Dominion Energy Operating Segment—Dominion

In addition to the assets held by Dominion Gas detailed above, see Item 1. Business, General for further information regarding pipeline and storage capacity owned by Dominion. Dominion also has about 15 bcf of above-ground storage capacity at Cove Point. Dominion has 142 compressor stations with approximately 869,000 installed compressor horsepower.

Cove Point—Dominion is pursuing the Liquefaction Project, which would enable Cove Point to liquefy domestically-produced natural gas for export as LNG. The DOE previously authorized Dominion to export LNG to countries with free trade agreements. In September 2013, the DOE authorized Dominion to export LNG from Cove Point to non-free trade agreement countries.

In May 2014, the FERC staff issued its EA for the Liquefaction Project. In the EA, the FERC staff addressed a variety of topics related to the proposed construction and development of the Liquefaction Project and its potential impact to the environment, and determined that with the implementation of appropriate mitigation measures, the Liquefaction Project can be built

Dominion Energy Equity Method Investments—In September 2014, Dominion, along with Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc., announced the formation of Atlantic Coast Pipeline. The members, which are subsidiaries of the above-referenced parent companies, hold the following membership interests: Dominion, 45%; Duke Energy Corporation, 40%; Piedmont Natural Gas Company, Inc., 10%; and AGL Resources Inc., 5%. Atlantic Coast Pipeline is focused on constructing an approximately 550-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, which has a total expected cost of $4.5 billion to $5.0 billion, excluding financing costs. In October 2014, Atlantic Coast Pipeline requested approval from FERC to utilize the pre-filing process under which environmental review for the natural gas pipeline project will commence. It expects to file its FERC application in the third quarter of 2015, receive the FERC certificate in the summer of 2016, and begin construction shortly thereafter. The project is subject to FERC, state and other federal approvals. See Note 9 to the Consolidated Financial Statements for further information about Dominion’s equity method investment in Atlantic Coast Pipeline.

In December 2012, Dominion formed Blue Racer with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. Blue Racer is an equal partnership between Dominion and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital. Midstream services offered by Blue Racer include gathering, processing, fractionation, and natural gas liquids transportation and marketing. Blue Racer is expected to leverage Dominion’s existing presence in the Utica region with significant additional new capacity designed to meet producer needs as the development of the Utica Shale formation increases. See Note 9 to the Consolidated Financial Statements for further information about Dominion’s equity method investment in Blue Racer.

SOURCES OF ENERGY SUPPLY

Dominion Energy Operating Segment—Dominion and Dominion Gas

Dominion’s and Dominion Gas’ 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 and Dominion Gas’ large underground natural gas storage network and the location of their pipeline systems are a significant link between the country’s major interstate gas pipelines and large markets in the Northeast and mid-Atlantic regions. Dominion’s and Dominion Gas’ 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 and Dominion Gas’ 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.

Environmental Compliance

The Companies remain committed to compliance with applicable environmental laws, regulations and rules related to their operations. As part of their commitment to compliance with such laws, Dominion and Virginia Power have sold or closed a number of coal-fired generation units over the past several years, and have plans to close additional units in the future. Additional information related to these and other of the Companies’ environmental compliance matters can be found in Item 1. Operating Segments and Future Issues and Other Matters in Item 7. MD&A and in Notes 3, 6 and 22 to the Consolidated Financial Statements.

Conservation and Load Management

Conservation and load management play a significant role in meeting the growing demand for electricity. The Regulation Act provides incentives for energy conservation and sets a voluntary goal for Virginia to reduce electricity consumption by retail customers in 2022 by 10% of the electric energy consumed in 2006 through the implementation of conservation programs. Additional legislation in 2009 added definitions of peak-shaving and energy efficiency programs, and allowed for a margin on operating expenses and recovery of revenue reductions related to energy efficiency programs.

Virginia Power’s DSM programs, implemented with Virginia Commission approval, provide important incremental steps toward achieving the voluntary 10% energy conservation goal through activities such as energy audits and incentives for customers to upgrade or install certain energy efficient measures and/or systems. The DSM programs began in Virginia in 2010 and in North Carolina in 2011. Currently, there are 22 total DSM programs active in the two states. Virginia Power continues to evaluate opportunities to redesign current DSM programs and develop new DSM initiatives in Virginia and North Carolina.

In Ohio, East Ohio offers three DSM programs, approved by the Ohio Commission, designed to help customers reduce their energy consumption.

Virginia Power continues to upgrade meters to AMI, also referred to as smart meters, in portions of Virginia. The AMI meter upgrades are part of an ongoing project that will help Virginia Power further evaluate the effectiveness of AMI meters in achieving voltage conservation, remotely turning off and on electric service, power outage and restoration detection and reporting, remote daily meter readings and offering dynamic rates.

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% of base year electric energy sales from renewable power sources by 2022, and 15% by 2025, and North Carolina’s RPS of 12.5% by 2021.

See Item 1. Business, Operating Segments and Item 2. Properties for additional information, including Dominion’s merchant solar properties.

Improvements in Other Energy Infrastructure

Virginia Power’s six-year investment plan includes significant capital expenditures to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing

Dominion also developed a comprehensive GHG inventory for calendar year 2013. For Dominion Generation, Dominion’s and Virginia Power’s direct CO₂ equivalent emissions, based on equity share (ownership), were approximately 33.9 million metric tons and 30.2 million metric tons, respectively, in 2013, compared to 36.2 million metric tons and 24.4 million metric tons, respectively, in 2012. The overall decrease in emissions from the Dominion fleet from 2012 to 2013 is largely due to Dominion’s divestiture of three power stations (Brayton Point in Massachusetts, and Elwood and Kincaid in Illinois), whereas the increase in emissions for the Virginia Power fleet was due to an increase in power generation after mild weather in 2012, which includes increased usage of coal, natural gas and oil. For the DVP operating segment’s electric transmission and distribution operations, direct CO₂ equivalent emissions for 2013 were 46,446 metric tons, representing a slight decrease from 2012. For 2013, DTI’s (including Cove Point) direct CO₂ equivalent emissions were approximately 1.0 million metric tons, and Hope’s and East Ohio’s direct CO₂ equivalent emissions were approximately 1.0 million metric tons, both similar to 2012. Dominion’s GHG inventory follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98 for calculating emissions.

Alternative Energy Initiatives

AES 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. AES has also conducted a number of studies to evaluate potential transmission solutions for delivering offshore wind resources to its customers. In addition, AES has developed EDGE^®, a conservation voltage management solution enabling utilities to deploy incremental grid-side energy management, and that requires no behavioral changes or purchases by end customers.

REGULATION

The Companies are subject to regulation by various federal, state and local authorities, including the Virginia Commission, North Carolina Commission, Ohio Commission, West Virginia Commission, SEC, FERC, EPA, DOE, NRC, Army Corps of Engineers, and the Department of Transportation.

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 CPCNs 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.

the authorized ROE in determining whether a utility’s earned ROE is either insufficient or excessive beginning with the biennial review for 2013-2014 to be filed in 2015. Additionally, if a utility is deemed to have over-earned, the customer refund share of excess earnings increases to 70% from the previous 60% level beginning with the biennial review for 2013-2014 to be filed in 2015.

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, such decisions may adversely affect Virginia Power’s results of operations, financial condition and cash flows.

See Note 13 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 authorized ROE 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’s transmission service rates in North Carolina are regulated by the North Carolina Commission as part of Virginia Power’s bundled retail service to North Carolina customers. In March 2012, Virginia Power filed an application with the North Carolina Commission to increase base non-fuel revenues with January 1, 2013 as the proposed effective date for the permanent rate revision. In December 2012, the North Carolina Commission approved a $36 million increase in Virginia Power’s annual non-fuel base revenues based on an authorized ROE of 10.2%, and a $14 million decrease in annual base fuel revenues for a combined total base revenue increase of $22 million. These rate changes became effective on January 1, 2013 and were appealed to the North Carolina Supreme Court by multiple parties. In June 2014, the North Carolina Supreme Court issued an opinion reversing the portion of the North Carolina Commission’s December 2012 order from Virginia Power’s 2012 base rate case approving a 10.2% ROE for Virginia Power, and remanding the case to the North Carolina Commission for additional findings of fact in light of a 2013 opinion issued after the North Carolina Commission’s order. This case is pending.

GAS

East Ohio’s natural gas distribution services, including the rates it may charge its customers, are regulated by the Ohio Commission. Hope’s natural gas distribution services are regulated by the West Virginia Commission.

Gas Regulation in Ohio

East Ohio is subject to regulation of rates and other aspects of its business by the Ohio Commission. When necessary, East Ohio

gram. Starting in April 2009, East Ohio buys natural gas under the Standard Service Offer program only 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.

In January 2013, the Ohio Commission granted East Ohio’s motion to fully exit the merchant function for its nonresidential customers, beginning in April 2013, which requires those customers to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2014, approximately 1.0 million of Dominion Gas’ 1.2 million Ohio customers were participating in the Energy Choice program. 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 allowing 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.

Federal Regulations

FEDERALENERGY 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.

Dominion Gas operates in compliance with FERC standards of conduct, which prohibit the sharing of certain non-public transmission information or customer specific data by its interstate gas transmission and storage companies with non-transmission function employees. Pursuant to these standards of conduct, Dominion Gas also makes certain informational postings available on Dominion’s website.

See Note 13 to the Consolidated Financial Statements for additional information.

Safety Regulations

Dominion Gas 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 Gas 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.

The Companies are subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. The Companies have an internal safety, health and security program designed to monitor and enforce compliance with worker safety requirements, which is routinely reviewed and considered for improvement. The Companies believe that they are in material compliance with all applicable laws and regulations related to worker health and safety. Notwithstanding these preventive measures, incidents may occur that are outside of the Companies’ control.

Environmental Regulations

Each of the Companies’ 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 businesses) or market prices (in unregulated businesses), those costs could adversely affect future results of operations and cash flows. The Companies 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 Item 7. MD&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 22 to the Consolidated Financial Statements, which information is incorporated herein by reference.

GLOBAL CLIMATE CHANGE

The national and international attention in recent years on GHG emissions and their relationship to climate change has resulted in

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.

The Companies’ results of operations can be affected by changes in the weather. Fluctuations in weather can affect demand for the Companies’ services. For example, milder than normal weather can reduce demand for electricity and gas transmission and distribution services. In addition, severe weather, including hurricanes, winter storms, earthquakes, floods and other natural disasters can disrupt operation of the Companies’ facilities and cause service outages, production delays and property damage that require incurring additional expenses. Changes in weather conditions can result in reduced water levels or changes in water temperatures 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 or sea temperatures.

The rates of Dominion’s and Dominion Gas’ gas transmission and distribution operations and Virginia Power’s electric transmission, distribution and generation operations are subject to regulatory review. Revenue provided by Virginia Power’s electric transmission, distribution and generation operations and Dominion’s and Dominion Gas’ gas transmission and distribution operations is based primarily on rates approved by state and federal 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 rates 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 to reflect Virginia Power’s actual electric transmission costs incurred. 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 and Dominion Gas’ gas transmission businesses are subject to review by FERC. Pursuant to FERC’s February 2014 approval of DTI’s uncontested settlement offer, DTI’s base rates for storage and transportation services are subject to a moratorium through the end of 2016. In addition, the rates of Dominion’s and Dominion Gas’ gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate. A failure by us to support these rates could result in rate decreases from current rate levels, which could adversely affect our results of operations, cash flows and financial condition.

Virginia Power’s base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission on a biennial basis in a

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 or its interpretation of market rules, 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. In addition, there have been changes to the interpretation and application of FERC’s market manipulation rules. A failure to comply with these rules could lead to civil and criminal penalties.

The Companies’ infrastructure build and expansion plans often require regulatory approval before construction can commence. The Companies may not complete facility construction, pipeline, conversion or other infrastructure 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 facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects have been announced and additional projects may be considered in the future. Dominion Gas competes for projects with companies of varying size and financial capabilities, including some that may have advantages competing for natural gas and liquid gas supplies. Commencing construction on announced and future projects may require approvals from applicable state and federal agencies. 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 counterparties or vendors, or other factors beyond the Companies’ control. Even if facility construction, pipeline, expansion, electric transmission line, conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations. Start-up and operational issues can arise in connection with the commencement of commercial operations at our facilities, including but not limited to commencement of commercial operations at our power generation facilities following expansions and fuel type conversions to natural gas and biomass. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, the Companies 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

Dominion is dependent on its contractors for the successful and timely completion of the Liquefaction Project. There is limited recent industry experience in the U.S. regarding the construction or operation of large liquefaction projects. The construction is expected to take several years, will be confined within a limited geographic area and could be subject to delays, cost overruns, labor disputes and other factors that could cause the total cost of the project to exceed the anticipated amount and adversely affect Dominion’s financial performance and/or impair Dominion’s ability to execute the business plan for the project as scheduled.

The terminal service agreements are subject to certain conditions precedent, including maintenance of certain regulatory approvals. Because the project will have only two customers, the financial performance of the project is highly dependent on those two counterparties, whose ability to perform their obligations under the contracts is subject to factors outside Dominion’s control. Dominion will also be exposed to counterparty credit risk. While the counterparties’ obligations are supported by parental guarantees and letters of credit, there is no assurance that such credit support would be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under either agreement resulting in a judgment in Dominion’s favor, Dominion may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process.

Atlantic Coast Pipeline Project—The Atlantic Coast Pipeline project, which will be constructed by DTI, is expected to have a total cost of approximately $4.5 to $5 billion, excluding financing costs, and will involve significant permitting and construction risks. The project requires the approval of FERC and other federal and state agencies, which could be delayed or withheld. Dominion expects opposition from certain landowners and stakeholder groups, which could impede the acquisition of rights-of-way and other land rights on a timely basis or on acceptable terms.

The large diameter of the pipeline and difficult terrain of certain portions of the proposed pipeline route aggravate the typical construction risks with which DTI is familiar. In-service delays could lead to cost overruns and potential customer termination rights.

Dominion owns a 45% membership interest in Atlantic Coast Pipeline. Dominion’s lack of a controlling interest means that it has limited influence over this business. If another member were unable or otherwise failed to perform its obligations to provide capital and credit support for this business, it could have an adverse effect on Dominion’s financial results.

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 the Companies’ 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 requir-

future. Certain facilities have become uneconomical to operate and have been shut down, converted to new fuel types or sold. These types of events could occur again in the future.

Existing environmental laws and regulations may be revised and/or new laws may be adopted or become applicable to the Companies. Risks relating to expected regulation of GHG emissions from existing fossil fuel-fired electric generating units are discussed below. In addition, further regulation of air quality and GHG emissions under the CAA may be imposed on the natural gas sector, including rules to limit methane leakage. The Companies are also subject to recently finalized federal water and waste regulations, including regulations concerning cooling water intake structures, coal combustion by-product handling and disposal practices, and the potential further regulation of polychlorinated biphenyls.

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’ facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect the Companies’ results of operations, financial performance or liquidity.

Virginia Power is subject to risks associated with the disposal and storage of coal ash. Virginia Power historically produced and continues to produce coal ash as a by-product of its coal-fired generation operations. The ash is stored and managed in impoundments (ash ponds) and landfills located at eight different facilities.

Virginia Power may face litigation regarding alleged CWA violations at Possum Point and Chesapeake and could incur settlement expenses and other costs, depending on the outcome of any such litigation, including costs associated with closing, corrective action and ongoing monitoring of certain ash ponds. In addition, the federal government recently signed final regulations concerning the management and storage of CCRs and Virginia and West Virginia may impose additional regulations which would apply to the facilities identified above. Such regulations could require Virginia Power to make additional capital expenditures, increase its operating and maintenance expenses or even cause it to close certain facilities.

Further, while Virginia Power operates its ash ponds and landfills in compliance with applicable state safety regulations, a release of coal ash with a significant environmental impact, such as the Dan River ash basin release by a neighboring utility, could result in remediation costs, civil and/or criminal penalties, claims, litigation, increased regulation and compliance costs, and reputational damage, and could impact the financial condition of Virginia Power.

The Companies’ operations are subject to operational hazards, equipment failures, supply chain disruptions and personnel issues which could negatively affect the Companies. Operation of the Companies’ facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply, pipeline integrity or transportation disruptions, accidents, labor disputes or work stoppages

Dominion’s and Virginia Power’s decommissioning trust funds are insufficient, and they 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.

Dominion and Dominion Gas depend on third parties to produce the natural gas they gather and process, and to provide NGLs they separate into marketable products. A reduction in these quantities could reduce Dominion’s and Dominion Gas’ revenues. Dominion and Dominion Gas obtain their supply of natural gas and NGLs from numerous third-party producers. Most producers are under no obligation to deliver a specific quantity of natural gas or NGLs to Dominion’s and Dominion Gas’ facilities. A number of factors could reduce the volumes of natural gas and NGLs available to Dominion’s and Dominion Gas’ pipelines and other assets. Increased regulation of energy extraction activities or a decrease in natural gas prices or the availability of drilling equipment could result in reductions in drilling for new natural gas wells, which could decrease the volumes of natural gas supplied to Dominion and Dominion Gas. Producers could shift their production activities to regions outside Dominion’s and Dominion Gas’ footprint. In addition, the extent of natural gas reserves and the rate of production from such reserves may be less than anticipated. If producers were to decrease the supply of natural gas or NGLs to Dominion’s and Dominion Gas’ systems and facilities for any reason, Dominion and Dominion Gas could experience lower revenues to the extent they are unable to replace the lost volumes on similar terms.

Dominion’s merchant power business operates 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 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

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. Defaults by customers, suppliers, joint venture partners or other third parties may adversely affect the Companies’ financial results.

In addition, in an economic downturn, individual customers of East Ohio may have increased amounts of bad debt. While rate riders have been obtained so that those losses will, for the most part, be recovered by future rates, such recovery will be over a period of time, while the cost is incurred earlier by East Ohio.

Market performance and other changes may decrease the value of Dominion’s decommissioning trust funds and Dominion’s and Dominion Gas’ benefit plan assets or increase Dominion’s and Dominion Gas’ 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 Dominion’s and Dominion Gas’ pension and other postretirement benefit plans. Dominion and Dominion Gas have 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 and Dominion Gas’ pension and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates will affect the liabilities under Dominion’s and Dominion Gas’ 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 mortality 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 and Dominion Gas’ results of operations, financial condition and/or cash flows could be negatively affected.

The use of derivative instruments could result in financial losses and liquidity constraints. The Companies use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity and financial market risks. In addition, Dominion and Dominion Gas purchase and sell commodity-based contracts for hedging purposes.

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

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.

Potential changes in accounting practices may adversely affect the Companies’ financial results. The Companies 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 earnings or could increase liabilities.

War, acts and threats of terrorism, natural disasters and other significant events could adversely affect the Companies’ operations. The Companies 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, the Companies’ infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. For example, a physical attack on a critical substation in California resulted in serious impacts to the power grid. Furthermore, the physical compromise of the Companies’ facilities could adversely affect the Companies’ ability to manage these facilities effectively. Instability in financial markets 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.

Hostile cyber intrusions could severely impair the Companies’ operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on the Companies’ 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. There appears to be an increasing level of activity, sophistication and maturity of threat actors, in particular nation state actors, that wish to disrupt the U.S. bulk power system and the U.S. gas transmission or distribution system. Such parties could view the Companies’ computer systems, software or networks as attractive targets for cyber attack. For example, malware has been designed to target software that runs the nation’s critical infrastructure such as power transmission grids and gas pipelines. In addition, the Companies’ businesses require that they and their vendors collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

Item 2. Properties

As of December 31, 2014, 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 and Dominion Gas share Dominion’s 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, 2014; however, by leaving the indenture open, Virginia Power expects to retain the flexibility to issue mortgage bonds in the future. Certain of Dominion’s merchant generation facilities are also subject to liens.

DOMINION ENERGY

Dominion Energy’s Cove Point LNG facility has an operational peak regasification daily send-out capacity of approximately 1.8 bcf and an aggregate LNG storage capacity of approximately 14.6 bcf. In addition, Cove Point has a liquefier that has the potential to create approximately 0.01 bcf of LNG per day.

The Cove Point Pipeline is a 36-inch diameter underground, interstate natural gas pipeline that extends approximately 88 miles from Cove Point to interconnections with Transcontinental Gas Pipe Line Company, LLC in Fairfax County, Virginia, and with Columbia Gas Transmission LLC and DTI in Loudoun County, Virginia. In 2009, the original pipeline was expanded to include a 36-inch diameter expansion that extends approximately 48 miles, roughly 75% of which is parallel to the original pipeline.

Dominion Gas also owns NGL processing plants capable of processing over 270,000 mcf per day of natural gas. Hastings is the largest plant and is capable of processing over 180,000 mcf per day of natural gas. Hastings can also fractionate over 580,000 Gals per day of NGLs into marketable products, including propane, isobutane, butane, and natural gasoline. NGL operations have storage capacity of 1,226,500 Gals of propane, 109,000 Gals of isobutane, 442,000 Gals of butane, 2,000,000 Gals of natural gasoline, and 1,012,500 Gals of mixed NGLs.

See Item 1. Business, General and Item 1. Dominion Energy, Properties and Investments for details regarding Dominion Energy’s pipeline and storage capacity.

DOMINION GENERATION

Dominion and Virginia Power generate electricity for sale on a wholesale and a retail level. Dominion and Virginia Power supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2014, Dominion Generation’s total utility and merchant generating capacity was approximately 24,600 MW.

legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.

ASSET RETIREMENT OBLIGATIONS

Dominion recognizes 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, Dominion estimates the fair value of its AROs using present value techniques, in which it makes 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 Dominion revises any assumptions used to calculate the fair value of existing AROs, it adjusts the carrying amount of both the ARO liability and the related long-lived asset for assets that are in service; for assets that have ceased operations, Dominion adjusts the carrying amount of the ARO liability with such changes recognized in income. Dominion accretes the ARO liability to reflect the passage of time.

In 2014, 2013 and 2012, Dominion recognized $81 million, $86 million and $77 million, respectively, of accretion, and expects to recognize $86 million in 2015. Dominion records accretion and depreciation associated with utility nuclear decommissioning AROs as an adjustment to the regulatory liability related to its nuclear decommissioning trust.

A significant portion of Dominion’s AROs relates to the future decommissioning of its merchant and utility nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2014, Dominion’s nuclear decommissioning AROs totaled $1.4 billion, representing approximately 84% 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 Dominion’s nuclear decommissioning obligations.

Dominion obtains 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 its 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, Dominion’s cost estimates include cost escalation rates that are applied to the base year costs. Dominion determines 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 critical assumptions.

Primarily as a result of a shift of the delayed planned date on which the DOE is expected to begin accepting spent nuclear fuel, in 2014 Dominion recorded an increase of $95 million to the nuclear decommissioning AROs.