Regulation-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 not subject to significant competition due tocontracted primarily under long-term fixed reservation fee agreements. However, in the long-term naturefuture 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 Operating Segment—Dominion and Dominion Gas

Dominion Gas’ natural gas transmission storage, processing and gatheringstorage 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. SeeState Regulations andFederal Regulations inRegulation for more information.

Dominion Energy Operating Segment—Dominion

Dominion’s LNGCove 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

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 producersfollowing significant projects under construction or development to convey approximately 100,000 acres of Marcellus Shale development rights underneath several ofbetter serve customers or expand 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 ofservice offerings within 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 underneathservice territory.

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.project. The project is expected to cost approximately $159$180 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,April 2016, DTI filed an application to requestreceived FERC authorization to construct, operate and operatemaintain the project facilities, which are expected to be in service in the fourth quarter of 2016.late 2017.

In October 2013, DTIMarch 2016, East Ohio executed a binding precedent agreement with CNX Gas Company LLCa power generator for the ClaringtonLordstown Project. The project is expected to cost approximately $78 million and provide 250,000 Dths per dayIn January 2017, East Ohio commenced construction 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 arewith an in-service date expected to be in service in the fourththird quarter of 2016.

In November 2014, DTI placed into service its $112 million Allegheny Storage Project, which provides2017 at a total estimated cost of 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.$35 million.

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. In March 2015, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years and to increase the annual capital investment, with corresponding increases in the annual rate-increase caps. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to settle East Ohio’s pending application. As requested, the PIR Program and associated cost recovery will continue for another five-year term, calendar years 2017 through 2021, and East Ohio will be permitted to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio. Costs associated with calendar year 2016 investment will be recovered under the existing terms.

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.the following significant projects under construction or development.

Cove PointPoint——Dominion is pursuing the Liquefaction Project, which would enable Cove Point to liquefy domestically-produced

Dominion Energy Equity Method InvestmentsInvestments——In September 2015, Dominion, through Dominion Midstream, acquired an additional 25.93% interest in Iroquois. Dominion Gas holds a 24.07% interest with TransCanada holding a 50% interest. Iroquois owns and operates a416-mile FERC regulated interstate natural gas pipeline providing service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, through interconnecting pipelines and exchanges. Iroquois’ pipeline extends from the U.S.-Canadian border at Waddington, New York through the state of Connecticut to South Commack, Long Island, New York and continuing on from Northport, Long Island, New York through the Long Island Sound to Hunts Point, Bronx, New York. See Note 9 to the Consolidated Financial Statements for further information about Dominion’s equity method investment in Iroquois.

In September 2014, Dominion, along with Duke Energy Corporation, Piedmont Naturaland Southern Company Gas Company, Inc. and(formerly known as AGL Resources Inc.), announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. In October 2016, Dominion purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million. The members, which are subsidiaries of the above-referenced parent companies, hold the following membership interests: Dominion, 45%48%; Duke, Energy Corporation, 40%; Piedmont Natural Gas Company, Inc., 10%47%; and Southern Company Gas (formerly known as AGL Resources Inc.), 5%. Atlantic Coast Pipeline is focused on constructing an approximately 550-mile600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, which has a total expected cost of $4.5$5.0 billion

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 andFuture 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 state commissions of Virginia, Commission, North Carolina, Commission, Ohio, Commission, West Virginia, Commission,Utah, Wyoming and Idaho, 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 and transfers of certain facilities andfacilities. The Virginia Commission also regulates 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.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 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

See Note 13 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 CommissionConsolidated Financial Statements for additional findings of fact in light of a 2013 opinion issued after the North Carolina Commission’s order. This caseinformation, which is pending.incorporated herein by reference.

GAS

Dominion Questar’s natural gas development, production, transportation, and distribution services, including the rates it may charge its customers, are regulated by the state commissions of Utah, Wyoming and Idaho. 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.

gram.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, 2014,2016, 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 providers in the retail

Dominion and Dominion Gas operatesoperate 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 makesmake 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 isare 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 located in areas of high-density population. Dominion and Dominion Gas hashave evaluated itstheir 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.