scale solar generation are expected to gather and process natural gas production from the Utica Shale formation,be a focus in eastern Ohio and western Pennsylvania, are being made by the Blue Racer joint venture.

meeting such environmental requirements, particularly in Virginia. In September 2013,2014, Dominion announced the formation of Dominion Gas, a first tier wholly-owned subsidiary holding company for the majority of Dominion’s regulatedAtlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately600-mile natural gas businesses. Specifically, Dominion transferred direct ownership of East Ohio, DTI and Dominion Iroquois, the latter of which holds a 24.72% general partnership interest in Iroquois,pipeline running from West Virginia through Virginia to Dominion Gas on September 30, 2013. Dominion Gas will be the primary financing entity for Dominion’s regulatedNorth Carolina, to increase natural gas businesses and expects to become an SEC registrantsupplies in 2014.

Also in September 2013, Dominion announced its plans to form an MLP in 2014 by contributing certain of its midstream natural gas assets to the MLP initially and over time. Dominion is currently considering the contribution to the MLP of natural gas business assets other than those owned by Dominion Gas, including interests in Cove Point and Dominion’s share of the Blue Racer joint venture.region.

Dominion has transitioned to a more regulated, less volatile earnings mix as evidenced by its capital investments in regulated infrastructure, including the Dominion Questar Combination, and in infrastructure whose output is sold under long-term purchase agreements as well as dispositionsthe sale of certain merchant generation facilities during 2012 and 2013 and the ongoing exit of natural gas trading and certainelectric retail energy marketing activities.business in March 2014. Dominion’s nonregulated

cial customers in their service territories as state regulations in Utah, Wyoming and Idaho for Questar Gas, and West Virginia doesfor Hope, do not allow customers to choose their provider in its retail natural gas markets at this time. SeeRegulation-State Regulations-GasState Regulationsin Regulation for additional information.

Cove Point’s gas transportation, LNG import and storage operations, as well as the Liquefaction Project’s capacity are contracted primarily under long-term fixed reservation fee agreements. However, in the future Cove Point may compete with other independent terminal operators as well as major oil and gas companies on the basis of terminal location, services provided and price. Competition from terminal operators primarily comes from refiners and distribution companies with marketing and trading arms.

Questar Pipeline’s and DCG’s pipeline systems generate a substantial portion of their revenue from long-term firm contracts for transportation services and are therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, Questar Pipeline’s pipeline system faces competitive pressures from similar facilities that serve the Rocky Mountain region and DCG’s pipeline system faces competitive pressures from similar facilities that serve the South Carolina and southeastern Georgia area in terms of location, rates, terms of service, and flexibility and reliability of service.

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 Energy’sEnergy Operating Segment—Dominion and Dominion Gas

Dominion Gas’ natural gas transmission pipeline,and storage and LNG operations are regulated primarily by FERC. Dominion Energy’sEast Ohio’s gas distribution service,operations, including the rates that it may charge to customers, isare regulated by the Ohio and West Virginia Commissions.Commission. SeeState Regulations andFederal Regulations inRegulation for more information.

Dominion Energy Operating Segment—Dominion

Cove Point’s, Questar Pipeline’s, and DCG’s operations are regulated primarily by FERC. Questar Gas’ distribution operations, including the rates it may charge customers, are regulated by the Utah, Wyoming and Idaho Commissions. Hope’s gas distribution operations, including the rates that it may charge customers, are regulated by the West Virginia Commission. SeeState Regulations andFederal Regulations inRegulation for more information.

PROPERTIESAND INVESTMENTS

For a description of Dominion’s and Dominion Gas’ existing facilities see Item 2.Properties.

Dominion Energy Operating Segment—Dominion and Dominion Gas

Dominion Energy’s gas distribution network is located inGas has the states of Ohio and West Virginia. This network involves approximately 21,900 miles of pipe, exclusive offollowing significant projects under construction or development to better serve customers or expand its service lines. The rights-offerings within its service territory.

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 tonon-free trade agreement countries.

In May 2014, DTI expectsthe FERC staff issued its EA for the Liquefaction Project. In the EA, the FERC staff addressed a variety of topics related to filethe 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 and operated safely with no significant impact to the environment. In September 2014, Cove Point received the FERC order authorizing the Liquefaction Project with certain conditions. The conditions regarding the Liquefaction Project set forth in the FERC order largely incorporate the mitigation measures proposed in the EA. In October 2014, Cove Point commenced construction of the Liquefaction Project, with anin-service date anticipated in late 2017 at a total estimated cost of approximately $4.0 billion, excluding financing costs. The Cove Point facility is authorized to export at a rate of 770 million cubic feet of natural gas per day for a period of 20 years.

In April 2013, Dominion announced it had fully subscribed the capacity of the project with20-year terminal service agreements. ST Cove Point, LLC, a joint venture of Sumitomo Corporation, a Japanese corporation that is one of the world’s leading trading companies, and Tokyo Gas Co., Ltd., a Japanese corporation that is the largest natural gas utility in Japan, and GAIL Global (USA) LNG LLC, a wholly-owned indirect U.S. subsidiary of GAIL (India) Ltd., have each contracted for half of the capacity. Following completion of thefront-end engineering and design work, Dominion also announced it had awarded its engineering, procurement and construction contract for new liquefaction facilities to IHI/Kiewit Cove Point, a joint venture between IHI E&C International Corporation and Kiewit Energy Company.

Cove Point has historically operated as an LNG import facility under various long-term import contracts. Since 2010, Dominion has renegotiated certain existing LNG import contracts in a manner that will result in a significant reduction in pipeline and storage capacity utilization and associated anticipated revenues during the period from 2017 through 2028. Such amendments created the opportunity for Dominion to explore the Liquefaction Project, which, assuming it becomes operational, will extend the economic life of Cove Point and contribute to Dominion’s overall growth plan. In total, these renegotiations reduced Cove Point’s expected annual revenues from the import-related contracts by approximately $150 million from 2017 through 2028, partially offset by approximately $50 million of additional revenues in the years 2013 through 2017.

In October 2015, Cove Point received FERC authorization to construct the approximately $40 million Keys Energy Project. Construction on the project commenced in December 2015, and the project facilities are expected to be placed into service in March 2017.

In November 2016, Cove Point filed an application to request FERC authorization to construct the approximately $150 million Eastern Market Access Project. Construction on the project is expected to begin in the fourth quarter of 2017, and the project facilities are expected to be placed into service in late 2018.

to $5.5 billion, excluding financing costs. In October 2014, Atlantic Coast Pipeline requested approval from FERC to utilize thepre-filing process under which environmental review for the outlet of newnatural gas processing facilitiespipeline project will commence. Atlantic Coast Pipeline filed its FERC application in September 2015 and expects to be in service in late 2019. 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 to interconnectionsand portions of Pennsylvania. Blue Racer is an equal partnership between Dominion and Caiman, with multiple interstate pipelines. The Western Access Project would provide system enhancements to facilitate the movement of processedDominion contributing midstream assets and Caiman contributing private equity capital. Midstream services offered by Blue Racer include gathering, processing, fractionation, and natural gas over East Ohio’s systemliquids transportation and marketing. Blue Racer is expected to be completed by November 2014, and cost approximately $90 million.develop 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.

SOURCESOF ENERGY SUPPLY

Dominion’s and Dominion Energy’sGas’ natural gas supply is obtained from various sources including purchases from major and independent producers in theMid-Continent and Gulf Coast regions, local producers in the Appalachian area, gas marketers and, for Questar Gas specifically, from Wexpro and other producers in the Rocky Mountain region. Wexpro’s gas marketers.development and production operations serve the majority of Questar Gas’ gas supply requirements in accordance with the Wexpro Agreement and the Wexpro II Agreement, comprehensive agreements with the states of Utah and Wyoming. Dominion’s and Dominion Gas’ large underground natural gas storage network and the location of itstheir pipeline systemsystems are a significant link between the country’s major interstate gas pipelines and large markets in the Northeast,mid-Atlantic and mid-AtlanticRocky Mountain 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, Midwest and Midwest

environmental compliance, conservation and energy efficiency programs and renewable energy programs;programs, and it provides for enhanced returns on capital expenditures on specific new generation projects. The Regulation Act also continuescontains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.

Legislation enacted inIn February 2013 amended2015, the Regulation Act prospectively, including elimination of the 50 basis points RPS ROE incentive.Virginia Governor signed legislation into law which will keep Virginia Power’s base rates unchanged until at least December 1, 2022. In addition, ROE incentives for newly proposed generation projects were eliminated, except for nuclear and offshore wind projects, which were reduced from the previous 200 basis points ROE incentive to 100 basis points. In addition, through the 2013 amendments,no biennial reviews will be conducted by the Virginia Commission hasfor the discretionfive successive12-month test periods beginning January 1, 2015, and ending December 31, 2019. The legislation states that Virginia Power’s 2015 biennial review, filed in March 2015, would proceed for the sole purpose of reviewing and determining whether any refunds are due to increase or decrease a utility’s authorized ROEcustomers based on earnings performance for generation and distribution services during the 2013 and 2014 test periods. In addition the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility’s performance consistentROE for use in connection with Virginia Commission precedent that existed priorrate adjustment clauses and requires utilities to 2007. The legislation included changes to the earnings test parameters defined by the Regulation Act to allow for a wider band of 70 basis points above and below 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.file integrated resource plans annually rather than biennially.

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 decisionsit may adversely affect Virginia Power’sits results of operations, financial condition and cash flows.

See Note 13 to the Consolidated Financial Statements for additional information.information, which is incorporated herein by reference.

Electric Regulation in North Carolina

Virginia Power’s retail electric base rates in North Carolina are regulated on acost-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

Gas Regulation in West Virginia

Hope is subject to regulation of rates and other aspects of its business by the West Virginia Commission. When necessary, Hope seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. Base rates for Hope are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges.

In addition to general rate increases, Hope makes routine separate filings with the West Virginia Commission to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover a prospective twelve-month period. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

Legislation was passed in West Virginia authorizing a stand-alone cost recovery mechanism to recover specified costs and a return for infrastructure upgrades, replacements and expansions between general base rate cases.

Status of Competitive Retail Gas Services

BothThe states of the statesOhio and West Virginia, in which Dominion hasand Dominion Gas have gas distribution operations, have considered legislation regarding a competitive deregulation of natural gas sales at the retail level.

Ohio-Since—Since October 2000, East Ohio has offered the Energy Choice program, under which residential and commercial customers are encouraged to purchase gas directly from retail suppliers or through a community aggregation program. In October 2006, East Ohio restructured its commodity service by entering into gas purchase contracts with selected suppliers at a fixed price above the NYMEX New York Mercantile Exchangemonth-end settlement and passing that gas cost to customers under the Standard Service Offer program. 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, 2013,2016, approximately 1.0 million of Dominion’sDominion 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 to allowallowing customers to choose providers in the retail

cybersecurity programs as well as efforts to ensure appropriate facility ratings for Virginia Power’s transmission lines. In October 2010, NERC issued an industry alert identifying possible discrepancies between the design and actual field conditions of transmission facilities as a potential reliability issue. The alert recommends that entities review their current facilities rating methodology to verify that the methodology is based on actual field conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power is evaluating its transmission facilities for any discrepancies between design and actual field conditions.programs. In addition, NERC has requested the industry to increaseredefined critical assets which expanded the number of assets subject to NERC reliability standards, that are designated as critical assets, including cybersecurity assets. NERC continues to develop additional requirements specifically regarding supply chain standards and control centers that impact the bulk electric system. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.

In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.

Gas

FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate natural gas company subsidiaries, includingQuestar Pipeline, DTI, DCG, Iroquois and certain services performed by Cove Point. FERC also has jurisdiction over siting,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. The design, construction and operation of Cove Point’s LNG facility, including associated natural gas pipelines, the Liquefaction Project and the import and export facilitiesof LNG are also regulated by FERC.

Dominion’s and interstate natural gas pipeline and storage facilities.

Dominion’sDominion Gas’ interstate gas transmission and storage activities are conducted on an open access basis, in accordance with certificates, tariffs and service agreements on file with FERC.FERC and FERC regulations.

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

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

Safety Regulations

Dominion and Dominion Gas are also subject to the Pipeline Safety ActsImprovement Act of 2002 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which mandate inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those

environment and address climate change while meeting the futuregrowing 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. SeeEnvironmental Strategyabovebelow, Environmental Matters inFuture Issues and Other Mattersin Item 7. MD&A and Note 22 to the Consolidated Financial Statements for information on climate change legislation and regulation, which information is incorporated herein by reference.

WATER

The CWA is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of effluent into surface waters and require permits to be obtained from the EPA or the analogous state agency to discharge into state waters or waters of the U.S. Containment berms and similar structures may be required to help prevent accidental releases. Dominion must comply with applicable aspects of the CWA programs at its current and former operating facilities. From time to time, Dominion’s projects and operations may impact tidal and non-tidal wetlands. In these instances, Dominion must obtain authorization from the appropriate federal, state and local agencies prior to impacting a subject wetland. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for such impacts to wetlands.

GASAND OIL WELLS

All wells drilled in tight-gas-sand and shale reservoirs require hydraulic-fracture stimulation to achieve economic production rates and recoverable reserves. The majority of Wexpro’s current and future production and reserve potential is derived from reservoirs that require hydraulic-fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic-fracture stimulation and management and disposal of hydraulic fracturing fluids, are regulated by federal and state agencies that review and approve all aspects of gas- and oil-well design and operation. New environmental initiatives, proposed federal and state legislation, and rule-making pertaining to hydraulic fracture stimulation could increase Wexpro’s costs, restrict its access to natural gas reserves and impose additional permitting and reporting requirements. These potential restrictions on the use of hydraulic-fracture stimulation could materially affect Dominion’s ability to develop gas and oil reserves.

OTHER REGULATIONS

Other significant environmental regulations to which the Companies are subject include the CERCLA (providing for immediate response and removal actions, and contamination clean up, in the event of releases of hazardous substances into the environment), the Endangered Species Act (prohibiting activities that can result in harm to specific species of plants and animals), and federal and state laws protecting graves, sacred sites and cultural resources, including those of Native American populations. These regulations can result in compliance costs and potential adverse effects