10-K 1 d856078d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

(Mark One)

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

 

Commission File Number    Exact name of registrants as specified in their charters   

I.R.S. Employer

Identification Number

001-08489    DOMINION RESOURCES, INC.    54-1229715
000-55337    VIRGINIA ELECTRIC AND POWER COMPANY    54-0418825
000-55338    DOMINION GAS HOLDINGS, LLC    46-3639580
  

VIRGINIA

(State or other jurisdiction of incorporation or organization)

  
  

120 TREDEGAR STREET

RICHMOND, VIRGINIA

(Address of principal executive offices)

  

23219

(Zip Code)

    

(804) 819-2000

(Registrants’ telephone number)

    

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class

 

Name of Each Exchange

on Which Registered

DOMINION RESOURCES, INC.  
Common Stock, no par value   New York Stock Exchange
2013 Series A 6.125% Corporate Units   New York Stock Exchange
2013 Series B 6% Corporate Units   New York Stock Exchange
2014 Series A 6.375% Corporate Units   New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

VIRGINIA ELECTRIC AND POWER COMPANY

Common Stock, no par value

DOMINION GAS HOLDINGS, LLC

Limited Liability Company Membership Interests

 

 

Indicate by check mark whether the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.

Dominion Resources, Inc.    Yes  x    No  ¨        Virginia Electric and Power Company    Yes  x    No  ¨        Dominion Gas Holdings, LLC    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Dominion Resources, Inc.    Yes  ¨    No  x        Virginia Electric and Power Company    Yes  ¨    No  x        Dominion Gas Holdings, LLC    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Dominion Resources, Inc.    Yes  x    No  ¨        Virginia Electric and Power Company    Yes  x    No  ¨        Dominion Gas Holdings, LLC    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Dominion Resources, Inc.    Yes  x    No  ¨        Virginia Electric and Power Company    Yes  x    No  ¨        Dominion Gas Holdings, LLC    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Dominion Resources, Inc.    ¨            Virginia Electric and Power Company    x            Dominion Gas Holdings, LLC    x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Dominion Resources, Inc.

 

Large accelerated filer  x   Accelerated filer  ¨   Non-accelerated filer  ¨       Smaller reporting company  ¨

Virginia Electric and Power Company

 

Large accelerated filer  ¨   Accelerated filer  ¨   Non-accelerated filer  x       Smaller reporting company  ¨

Dominion Gas Holdings, LLC

 

Large accelerated filer  ¨   Accelerated filer  ¨   Non-accelerated filer  x       Smaller reporting company  ¨
   

(Do not check if a smaller

reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).

Dominion Resources, Inc.    Yes  ¨    No  x        Virginia Electric and Power Company    Yes  ¨    No  x        Dominion Gas Holdings, LLC    Yes  ¨    No  x

The aggregate market value of Dominion Resources, Inc. common stock held by non-affiliates of Dominion was approximately $41.1 billion based on the closing price of Dominion’s common stock as reported on the New York Stock Exchange as of the last day of Dominion’s most recently completed second fiscal quarter. Dominion is the sole holder of Virginia Electric and Power Company common stock. As of January 31, 2015, Dominion had 588,138,107 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding. Dominion Resources, Inc. holds all of the membership interests of Dominion Gas Holdings, LLC.

DOCUMENT INCORPORATED BY REFERENCE.

Portions of Dominion’s 2015 Proxy Statement are incorporated by reference in Part III.

This combined Form 10-K represents separate filings by Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Virginia Electric and Power Company and Dominion Gas Holdings, LLC make no representations as to the information relating to Dominion Resources, Inc.’s other operations.

VIRGINIA ELECTRIC AND POWER COMPANY AND DOMINION GAS HOLDINGS, LLC MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND ARE FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE FORMAT.

 

 

 


Table of Contents

Dominion Resources, Inc., Virginia Electric and

Power Company and Dominion Gas Holdings, LLC

 

 

 

Item

Number

         

 

Page

Number

  

  

  

Glossary of Terms

     3   

Part I

  

1.

  

Business

     8   

1A.

  

Risk Factors

     24   

1B.

  

Unresolved Staff Comments

     31   

2.

  

Properties

     31   

3.

  

Legal Proceedings

     35   

4.

  

Mine Safety Disclosures

     35   
  

Executive Officers of Dominion

     36   

Part II

  

5.

  

Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     37   

6.

  

Selected Financial Data

     38   

7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     39   

7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     54   

8.

  

Financial Statements and Supplementary Data

     56   

9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     155   

9A.

  

Controls and Procedures (Dominion)

     155   

9B.

  

Other Information

     158   

Part III

  

10.

  

Directors, Executive Officers and Corporate Governance

     158   

11.

  

Executive Compensation

     158   

12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     158   

13.

  

Certain Relationships and Related Transactions, and Director Independence

     158   

14.

  

Principal Accountant Fees and Services

     158   

Part IV

  

15.

  

Exhibits and Financial Statement Schedules

     160   

 

2        

 


Table of Contents

Glossary of Terms

 

The following abbreviations or acronyms used in this Form 10-K are defined below:

 

Abbreviation or Acronym    Definition

2013 Biennial Review Order

  

Order issued by the Virginia Commission in November 2013 concluding the 2011—2012 biennial review of Virginia Power’s base rates, terms and conditions

2013 Equity Units

  

Dominion’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013

2014 Equity Units

  

Dominion’s 2014 Series A Equity Units issued in July 2014

2015 Proxy Statement

  

Dominion 2015 Proxy Statement, File No. 001-08489

ABO

  

Accumulated benefit obligation

AES

  

Alternative Energy Solutions

AFUDC

  

Allowance for funds used during construction

AIP

  

Annual Incentive Plan

Altavista

  

Altavista power station

AMI

  

Advanced Metering Infrastructure

AMR

  

Automated meter reading program deployed by East Ohio

AOCI

  

Accumulated other comprehensive income (loss)

AROs

  

Asset retirement obligations

ARP

  

Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the CAA

Atlantic Coast Pipeline

  

Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion, Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc.

Atlantic Coast Pipeline project

  

The approximately 550-mile natural gas pipeline running from West Virginia through Virginia to North Carolina which will be owned by Dominion, Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources and constructed and operated by DTI

BACT

  

Best available control technology

bcf

  

Billion cubic feet

Bear Garden

  

A 590 MW combined cycle, natural gas-fired power station in Buckingham County, Virginia

Blue Racer

  

Blue Racer Midstream, LLC, a joint venture with Caiman

BOEM

  

Bureau of Ocean Energy Management

BP

  

BP Wind Energy North America Inc.

Brayton Point

  

Brayton Point power station

BREDL

  

Blue Ridge Environmental Defense League

Bremo

  

Bremo power station

BRP

  

Dominion Retirement Benefit Restoration Plan

Brunswick County

  

A 1,358 MW combined cycle, natural gas-fired power station under construction in Brunswick County, Virginia

CAA

  

Clean Air Act

Caiman

  

Caiman Energy II, LLC

CAIR

  

Clean Air Interstate Rule

CAO

  

Chief Accounting Officer

CAP

  

IRS Compliance Assurance Process

CCR

  

Coal combustion residual

CD&A

  

Compensation Discussion and Analysis

CEA

  

Commodity Exchange Act

CEO

  

Chief Executive Officer

CERCLA

  

Comprehensive Environmental Response, Compensation and Liability Act of 1980

CFO

  

Chief Financial Officer

CFTC

  

Commodity Futures Trading Commission

CGN Committee

  

Compensation, Governance and Nominating Committee of Dominion’s Board of Directors

CGT

  

Carolina Gas Transmission Corporation

Chesapeake

  

Chesapeake power station

Clean Power Plan

  

Guidelines proposed by the EPA in June 2014 for states to follow in developing plans to reduce CO2 emissions from existing fossil fuel-fired electric generating units

CNG

  

Consolidated Natural Gas Company

CNO

  

Chief Nuclear Officer

CO2

  

Carbon dioxide

COL

  

Combined Construction Permit and Operating License

Companies

  

Dominion, Virginia Power and Dominion Gas, collectively

CONSOL

  

CONSOL Energy, Inc.

COO

  

Chief Operating Officer

Cooling degree days

  

Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day

Corporate Unit

  

A stock purchase contract and 1/20 interest in a RSN issued by Dominion

Cove Point

  

Dominion Cove Point LNG, LP

 

        3

 


Table of Contents

 

 

Abbreviation or Acronym    Definition

Cove Point Holdings

  

Cove Point GP Holding Company, LLC

CPCN

  

Certificate of Public Convenience and Necessity

Crayne interconnect

  

DTI’s interconnect with Texas Eastern Transmission, LP in Greene County, Pennsylvania

CSAPR

  

Cross State Air Pollution Rule

CWA

  

Clean Water Act

DEI

  

Dominion Energy, Inc.

D.C.

  

District of Columbia

Dodd-Frank Act

  

The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010

DOE

  

Department of Energy

Dominion

  

The legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries (other than Virginia Power or Dominion Gas) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries

Dominion Direct®

  

A dividend reinvestment and open enrollment direct stock purchase plan

Dominion Gas

  

The legal entity, Dominion Gas Holdings, LLC (a single member limited liability company), one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Gas Holdings, LLC and its consolidated subsidiaries

Dominion Gas 2013 Senior Notes

  

The $400 million 2013 Series A 1.05% Senior Notes due 2016, $400 million 2013 Series B 3.55% Senior Notes due 2023 and $400 million 2013 Series C 4.80% Senior Notes due 2043

Dominion Iroquois

  

Dominion Iroquois, Inc.

Dominion Midstream

  

The legal entity, Dominion Midstream Partners, LP, its consolidated subsidiary Cove Point Holdings, or the entirety of Dominion Midstream Partners, LP, and its consolidated subsidiary

Dominion NGL Pipelines, LLC

  

The initial owner of the 58-mile G-150 pipeline project, which is designed to transport approximately 27,000 barrels per day of NGLs from Natrium to an interconnect with the Appalachia to Texas Express ethane line of Enterprise Product Partners, L.P. near Follansbee, West Virginia

DRS

  

Dominion Resources Services, Inc.

DSM

  

Demand-side management

Dth

  

Dekatherm

DTI

  

Dominion Transmission, Inc.

DVP

  

Dominion Virginia Power operating segment

E&P

  

Exploration & production

EA

  

Environmental assessment

East Ohio

  

The East Ohio Gas Company, doing business as Dominion East Ohio

EGWP

  

Employer Group Waiver Plan

Elwood

  

Elwood power station

EPA

  

Environmental Protection Agency

EPACT

  

Energy Policy Act of 2005

EPC

  

Engineering, procurement and construction

EPCRA

  

Emergency Planning and Community Right-to-Know Act

EPS

  

Earnings per share

ERISA

  

The Employee Retirement Income Security Act of 1974

ERM

  

Enterprise Risk Management

ERO

  

Electric Reliability Organization

ESBWR

  

General Electric-Hitachi’s Economic Simplified Boiling Water Reactor

ESRP

  

Dominion Executive Supplemental Retirement Plan

Excess Tax Benefits

  

Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation

Fairless

  

Fairless power station

FASB

  

Financial Accounting Standards Board

FCM

  

Futures Commission Merchant

FERC

  

Federal Energy Regulatory Commission

Fitch

  

Fitch Ratings Ltd.

Fowler Ridge

  

First phase of a wind-turbine facility joint venture with BP in Benton County, Indiana

Frozen Deferred Compensation Plan

  

Dominion Resources, Inc. Executives’ Deferred Compensation Plan

Frozen DSOP

  

Dominion Resources, Inc. Security Option Plan

FTRs

  

Financial transmission rights

GAAP

  

U.S. generally accepted accounting principles

Gal

  

Gallon

GHG

  

Greenhouse gas

Green Mountain

  

Green Mountain Power Corporation

Hastings

  

A natural gas processing and fractionation facility located near Pine Grove, West Virginia

HATFA of 2014

  

Highway and Transportation Funding Act of 2014

Heating degree days

  

Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day

Hope

  

Hope Gas, Inc., doing business as Dominion Hope

House Bill 95

  

Ohio utility reform legislation effective September 2011

 

4        

 


Table of Contents

 

 

Abbreviation or Acronym    Definition

Illinois Gas Contracts

  

A Dominion Retail, Inc. natural gas book of business consisting of residential and commercial customers in Illinois

INPO

  

Institute of Nuclear Power Operations

IRCA

  

Intercompany revolving credit agreement

Iroquois

  

Iroquois Gas Transmission System L.P.

IRS

  

Internal Revenue Service

ISO

  

Independent system operator

ISO-NE

  

ISO New England

JD Power

  

J.D. Power and Associates

Joint Committee

  

U.S. Congressional Joint Committee on Taxation

June 2006 hybrids

  

2006 Series A Enhanced Junior Subordinated Notes due 2066

June 2009 hybrids

  

2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to extensions no later than 2079

Juniper

  

Juniper Capital L.P.

Kewaunee

  

Kewaunee nuclear power station

Kincaid

  

Kincaid power station

kV

  

Kilovolt

Liability Management Exercise

  

Dominion exercise in 2014 to redeem certain debt and preferred securities

LIBOR

  

London Interbank Offered Rate

LIFO

  

Last-in-first-out inventory method

Line TPL-2A

  

An approximately 11-mile, 30-inch gathering pipeline extending from Tuscarawas County, Ohio to Harrison County, Ohio

Line TL-388

  

A 37-mile, 24-inch gathering pipeline extending from Texas Eastern, LP in Noble County, Ohio to its terminus at Dominion’s Gilmore Station in Tuscarawas County, Ohio

Line TL-404

  

An approximately 26-mile, 24- and 30- inch gas gathering pipeline that extends from Wetzel County, West Virginia to Monroe County, Ohio

Liquefaction Project

  

A natural gas export/liquefaction facility currently under construction by Cove Point

LNG

  

Liquefied natural gas

LTIP

  

Long-term incentive program

MAP 21 Act

  

Moving Ahead for Progress in the 21st Century Act

Maryland Commission

  

Maryland Public Service Commission

Massachusetts Municipal

  

Massachusetts Municipal Wholesale Electric Company

MATS

  

Utility Mercury and Air Toxics Standard Rule

mcf

  

thousand cubic feet

MD&A

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Medicare Act

  

The Medicare Prescription Drug, Improvement and Modernization Act of 2003

Medicare Part D

  

Prescription drug benefit introduced in the Medicare Act

mgd

  

Million gallons a day

Millstone

  

Millstone nuclear power station

MISO

  

Midwest Independent Transmission System Operators, Inc.

MLP

  

Master limited partnership, also known as publicly traded partnership

Moody’s

  

Moody’s Investors Service

MW

  

Megawatt

MWh

  

Megawatt hour

NAAQS

  

National Ambient Air Quality Standards

Natrium

  

A natural gas and fractionation facility located in Natrium, West Virginia, owned by Blue Racer

NAV

  

Net asset value

NCEMC

  

North Carolina Electric Membership Corporation

NedPower

  

A wind-turbine facility joint venture with Shell in Grant County, West Virginia

NEIL

  

Nuclear Electric Insurance Limited

NEOs

  

Named executive officers

NERC

  

North American Electric Reliability Corporation

NGLs

  

Natural gas liquids

NO2

  

Nitrogen dioxide

Non-Employee Directors Plan

  

Non-Employee Directors Compensation Plan

North Anna

  

North Anna nuclear power station

North Carolina Commission

  

North Carolina Utilities Commission

Northern System

  

Collection of approximately 131 miles of various diameter natural gas pipelines in Ohio

NOX

  

Nitrogen oxide

NPDES

  

National Pollutant Discharge Elimination System

NRC

  

Nuclear Regulatory Commission

NSPS

  

New Source Performance Standards

NYMEX

  

New York Mercantile Exchange

NYSE

  

New York Stock Exchange

 

        5

 


Table of Contents

 

 

Abbreviation or Acronym    Definition

October 2014 hybrids

  

2014 Series A Enhanced Junior Subordinated Notes due 2054

ODEC

  

Old Dominion Electric Cooperative

Ohio Commission

  

Public Utilities Commission of Ohio

Order 1000

  

Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development

OSHA

  

Occupational Safety and Health Administration

PBGC

  

Pension Benefit Guaranty Corporation

Peoples

  

The Peoples Natural Gas Company

Philadelphia Utility Index

  

Philadelphia Stock Exchange Utility Index

Pipeline Safety Act

  

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011

PIPP

  

Percentage of Income Payment Plan deployed by East Ohio

PIR

  

Pipeline Infrastructure Replacement program deployed by East Ohio

PJM

  

PJM Interconnection, L.L.C.

PM&P

  

Pearl Meyer & Partners

PNG Companies LLC

  

An indirect subsidiary of Steel River Infrastructure Fund North America

ppb

  

Parts-per-billion

PSD

  

Prevention of significant deterioration

RCCs

  

Replacement Capital Covenants

RCRA

  

Resource Conservation and Recovery Act

Regulation Act

  

Legislation effective July 1, 2007, that amended the Virginia Electric Utility Restructuring Act and fuel factor statute, which legislation is also known as the Virginia Electric Utility Regulation Act, as amended in 2015

REIT

  

Real estate investment trust

RGGI

  

Regional Greenhouse Gas Initiative

Rider B

  

A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Power’s coal-fired power stations to biomass

Rider BW

  

A rate adjustment clause associated with the recovery of costs related to Brunswick County

Rider R

  

A rate adjustment clause associated with the recovery of costs related to Bear Garden

Rider S

  

A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center

Rider T1

  

A rate adjustment clause to recover the difference between revenues produced from transmission rates included in base rates, and the new total revenue requirement developed annually for the rate years effective September 1

Rider U

  

A rate adjustment clause associated with the recovery of costs of new underground distribution facilities

Rider US-1

  

A rate adjustment clause associated with the recovery of costs related to Remington Solar Facility

Rider W

  

A rate adjustment clause associated with the recovery of costs related to Warren County

Riders C1A and C2A

  

Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in DSM cases

ROE

  

Return on equity

ROIC

  

Return on invested capital

RPS

  

Renewable Portfolio Standard

RSN

  

Remarketable subordinated note

RTEP

  

Regional transmission expansion plan

RTO

  

Regional transmission organization

SAFSTOR

  

A method of nuclear decommissioning, as defined by the NRC, in which a nuclear facility is placed and maintained in a condition that allows the facility to be safely stored and subsequently decontaminated to levels that permit release for unrestricted use

SAIDI

  

System Average Interruption Duration Index, metric used to measure electric service reliability

Salem Harbor

  

Salem Harbor power station

SEC

  

Securities and Exchange Commission

SELC

  

Southern Environmental Law Center

September 2006 hybrids

  

2006 Series B Enhanced Junior Subordinated Notes due 2066

Shell

  

Shell WindEnergy, Inc.

SO2

  

Sulfur dioxide

Standard & Poor’s

  

Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.

State Line

  

State Line power station

Surry

  

Surry nuclear power station

TSR

  

Total shareholder return

U.S.

  

United States of America

UAO

  

Unilateral Administrative Order

UEX Rider

  

Uncollectible Expense Rider deployed by East Ohio

VDEQ

  

Virginia Department of Environmental Quality

 

6        

 


Table of Contents

 

 

Abbreviation or Acronym    Definition

VEBA

  

Voluntary Employees’ Beneficiary Association

VIE

  

Variable interest entity

Virginia City Hybrid Energy Center

  

A 600 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County, Virginia

Virginia Commission

  

Virginia State Corporation Commission

Virginia Power

  

The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power and its consolidated subsidiaries

VOWTAP

  

Virginia Offshore Wind Technology Advancement Project

Warren County

  

A 1,342 MW combined-cycle, natural gas-fired power station in Warren County, Virginia

West Virginia Commission

  

Public Service Commission of West Virginia

Western System

  

Collection of approximately 212 miles of various diameter natural gas pipelines and three compressor stations in Ohio

Yorktown

  

Yorktown power station

 

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Table of Contents

Part I

 

 

 

Item 1. Business

GENERAL

Dominion, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion’s strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. As of December 31, 2014, Dominion’s portfolio of assets includes approximately 24,600 MW of generating capacity, 6,400 miles of electric transmission lines, 57,100 miles of electric distribution lines, 10,900 miles of natural gas transmission, gathering and storage pipeline and 21,900 miles of gas distribution pipeline, exclusive of service lines. As of December 31, 2014, Dominion serves over 5 million utility and retail energy customers in 10 states and operates one of the nation’s largest underground natural gas storage systems, with approximately 947 bcf of storage capacity.

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. In October 2014, Dominion Midstream launched its initial public offering and issued 20,125,000 common units representing limited partner interests, which included a 2,625,000 common unit over-allotment option that was exercised in full by the underwriters. Dominion owns the general partner and 68.5% of the limited partner interests in Dominion Midstream, which owns a preferred equity interest and the general partner interest in Cove Point. Dominion Midstream is consolidated by Dominion, and is an SEC registrant. However, its Form 10-K is filed separately and is not combined herein.

Dominion is focused on expanding its investment in regulated electric generation, transmission and distribution and regulated natural gas transmission and distribution infrastructure within and around its existing footprint. With this investment, Dominion expects 80% to 90% of future earnings from its primary operating segments to come from regulated and long-term contracted businesses.

Dominion continues to expand and improve its regulated and long-term contracted electric and natural gas businesses, in accordance with its six-year capital investment program. A major impetus for this program is to meet the anticipated increase in demand in its electric utility service territory. Other drivers for the capital investment program include the construction of infrastructure to handle the increase in natural gas production from the Marcellus and Utica Shale formations, to upgrade Dominion’s gas and electric transmission and distribution networks, and to meet environmental requirements and standards set by various regulatory bodies. Investments in utility solar generation are expected to be a focus in meeting such environmental requirements, particularly in Virginia. Investments to gather and process natural gas production from the Utica Shale formation, in eastern Ohio and western Pennsylvania, are being made by the Blue Racer joint venture. In September 2014, Dominion announced the formation of Atlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately 550-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, to increase natural gas supplies in the region.

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.

 

 

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EMPLOYEES

As of December 31, 2014, Dominion had approximately 14,400 full-time employees, of which approximately 5,300 employees are subject to collective bargaining agreements. As of December 31, 2014, Virginia Power had approximately 6,800 full-time employees, of which approximately 3,100 employees are subject to collective bargaining agreements. As of December 31, 2014, Dominion Gas had approximately 2,800 full-time employees, of which approximately 2,000 employees are subject to collective bargaining agreements.

 

 

WHERE YOU CAN FIND MORE INFORMATION ABOUT THE COMPANIES

The Companies file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov. You may also read and copy any document they file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

The Companies make their SEC filings available, free of charge, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, through Dominion’s internet website, http://www.dom.com, as soon as reasonably practicable after filing or furnishing the material to the SEC. Information contained on Dominion’s website is not incorporated by reference in this report.

 

 

ACQUISITIONS AND DISPOSITIONS

Following are significant acquisitions and divestitures by the Companies during the last five years.

ACQUISITION OF SOLAR DEVELOPMENT PROJECTS

Throughout 2014, Dominion completed the acquisitions of 100% of the equity interests in various solar development projects in California for approximately $200 million. The projects are expected to cost approximately $599 million to construct, including the initial acquisition cost, and are expected to generate approximately 179 MW. See Note 3 to the Consolidated Financial Statements for additional information on solar acquisitions.

SALE OF ELECTRIC RETAIL ENERGY MARKETING BUSINESS

In March 2014, Dominion completed the sale of its electric retail energy marketing business. The proceeds were approximately $187 million, net of transaction costs. The sale of the electric retail energy marketing business did not qualify for discontinued operations classification. See Note 3 to the Consolidated Financial Statements for additional information.

SALE OF PIPELINES AND PIPELINE SYSTEMS

In March 2014, Dominion Gas sold the Northern System to an affiliate that subsequently sold the Northern System to Blue Racer

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 OF MARCELLUS 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 INVESTMENT IN 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.

 

 

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OPERATING SEGMENTS

Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued, which is discussed in Note 3 to the Consolidated Financial Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s other operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

Dominion Gas manages its daily operations through its primary operating segment: Dominion Energy. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance.

While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by the Companies and their respective legal subsidiaries.

A description of the operations included in the Companies’ primary operating segments is as follows:

 

Primary Operating

Segment

  Description of Operations   Dominion    

Virginia

Power

   

Dominion

Gas

 

DVP

 

Regulated electric distribution

    X        X     
   

Regulated electric transmission

    X        X           

Dominion Generation

  Regulated electric fleet     X        X     
  Merchant electric fleet     X       
   

Nonregulated retail energy marketing

    X                   

Dominion Energy

 

Gas transmission and storage

    X (1)        X   
 

Gas distribution and storage

    X          X   
 

Gas gathering and processing

    X          X   
    LNG import and storage     X                   

 

(1) Includes remaining producer services activities.

For additional financial information on operating segments, including revenues from external customers, see Note 25 to the Consolidated Financial Statements. For additional information on operating revenue related to the Companies’ principal products and services, see Notes 2 and 4 to the Consolidated Financial Statements, which information is incorporated herein by reference.

DVP

The DVP Operating Segment of Dominion and Virginia Power includes Virginia Power’s regulated electric transmission and dis-

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-

 

 

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ting approvals. This could result in additional competition to build transmission lines in Virginia Power’s service area in the future and could allow Dominion to seek opportunities to build facilities in other service territories.

REGULATION

DVP Operating Segment—Dominion and Virginia Power

Virginia Power’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia and North Carolina Commissions. Virginia Power’s wholesale electric transmission rates, tariffs and terms of service are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. See State Regulations and Federal Regulations in Regulation and Note 13 to the Consolidated Financial Statements for additional information, including a discussion of the 2013 Biennial Review Order.

PROPERTIES

DVP Operating Segment—Dominion and Virginia Power

Virginia Power has approximately 6,400 miles of electric transmission lines of 69 kV or more located in the states of North Carolina, Virginia and West Virginia. Portions of Virginia Power’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.

As a part of PJM’s RTEP process, PJM authorized the following material reliability projects (including estimated cost):

  Ÿ  

Mt. Storm-to-Doubs line ($336 million);

  Ÿ  

Surry-to-Skiffes Creek-to-Whealton lines ($150 million);

  Ÿ  

Dooms-to-Lexington line ($112 million);

  Ÿ  

Cunningham-to-Dooms ($100 million); and

  Ÿ  

Landstown voltage regulation project ($70 million).

The following material reliability projects (including estimated cost) are awaiting PJM authorization:

  Ÿ  

Warrenton project (including Remington CT-to-Warrenton, Vint Hill-to-Wheeler, Wheeler-to-Loudoun and Vint Hill and Wheeler switching stations) ($109 million); and

  Ÿ  

Cunningham-to-Elmont line ($106 million).

Over the next 5 years, Virginia Power plans to increase transmission substation physical security and to invest in a new system operations center. Virginia Power expects to invest $300 million–$500 million during that time to strengthen its electrical system to better protect critical equipment, enhance its spare equipment process, and create multiple levels of security.

In addition, Virginia Power’s electric distribution network includes approximately 57,100 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private

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

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

 

 

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25 years. See Note 3 to the Consolidated Financial Statements for additional information regarding certain solar acquisitions.

Earnings for the Dominion Generation Operating Segment of Virginia Power primarily result from the sale of electricity generated by its utility fleet. Revenue is based primarily on rates established by state regulatory authorities and state law. Approximately 80% of revenue comes from serving Virginia jurisdictional customers. Base rates for the Virginia jurisdiction are set using a modified cost-of-service rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. Earnings variability may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather on customers’ demand for services. Likewise, earnings may reflect variations in the timing or nature of expenses as compared to those contemplated in current rates, such as labor and benefit costs, capacity expenses, and the timing, duration and costs of scheduled and unscheduled outages. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. The cost of new generation facilities is generally recovered through rate adjustment clauses in Virginia. Variability in earnings from rate adjustment clauses reflects changes in the authorized ROE and the carrying amount of these facilities, which are largely driven by the timing and amount of capital investments, as well as depreciation. See Electric Regulation in Virginia under Regulation and Note 13 to the Consolidated Financial Statements for additional information.

The Dominion Generation Operating Segment of Dominion derives its earnings primarily from the sale of electricity generated by Virginia Power’s utility and Dominion’s merchant generation assets, as well as from associated capacity and ancillary services. Variability in earnings provided by Dominion’s nonrenewable merchant fleet relates to changes in market-based prices received for electricity and capacity. Market-based prices for electricity are largely dependent on commodity prices, primarily natural gas, and the demand for electricity, which is primarily dependent upon weather. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion manages the electric price volatility of its merchant fleet by hedging a substantial portion of its expected near-term energy sales with derivative instruments. Variability also results from changes in the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages. In 2012 and 2013, Dominion sold or began decommissioning several of its merchant generation facilities, including Brayton Point, Kincaid, State Line, Salem Harbor and Kewaunee.

Dominion’s retail energy marketing operations compete in nonregulated energy markets. In March 2014, Dominion completed the sale of its electric retail energy marketing business; however, it still participates in the retail natural gas and energy-related products and services businesses. The remaining customer base includes approximately 1.3 million customer accounts. Dominion has a heavy concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice.

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

 

 

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Commission and the North Carolina Commission. See State Regulations and Federal Regulations in Regulation and Note 13 to the Consolidated Financial Statements for more information.

PROPERTIES

For a listing of Dominion’s and Virginia Power’s existing generation facilities, see Item 2. Properties.

Dominion Generation Operating Segment—Dominion and Virginia Power

The generation capacity of Virginia Power’s electric utility fleet totals approximately 20,400 MW. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro, renewables, and power purchase agreements. Virginia Power’s generation facilities are located in Virginia, West Virginia and North Carolina and serve load in Virginia and northeastern North Carolina.

Virginia Power is developing, financing, and constructing new generation capacity to meet growing electricity demand within its service territory. Significant projects under construction or development are set forth below:

Ÿ  

In August 2013, the Virginia Commission authorized the construction of Brunswick County, which is estimated to cost approximately $1.2 billion. Construction of the facility commenced in the third quarter of 2013 with commercial operations expected to begin in mid- 2016. Brunswick County is expected to offset the expected reduction in capacity caused by the retirement of coal-fired units at Chesapeake in December 2014 and at Yorktown as early as 2016, primarily due to the cost of compliance with MATS.

Ÿ  

In January 2015, Virginia Power filed a CPCN with the Virginia Commission to build the state’s first utility-scale solar facility. The 20 MW project would be built near Virginia Power’s Remington Power Station in Fauquier County. The estimated in-service date for the facility, subject to regulatory approvals, is the fourth quarter of 2016.

Ÿ  

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. See Note 13 to the Consolidated Financial Statements for more information on this project.

Ÿ  

The BOEM auctioned approximately 113,000 acres of federal land off the Virginia coast as a single lease for construction of offshore wind turbines. Virginia Power was awarded the lease, effective November 1, 2013. BOEM has several lease milestones with which Virginia Power must comply as conditions to being awarded the lease.

Ÿ  

Virginia Power is also considering the development of a commercial offshore wind generation project through a federal land lease off the Virginia coast. Virginia Power and several partners are collaborating to develop a 12 MW offshore wind demonstration project, which is proposed to be located approximately 24 miles off the coast of Virginia. In May 2014, the DOE selected the VOWTAP as one of three projects to receive up to $47 million of follow-on funding. This project may be operational as early as the end of 2017, pending regulatory approvals.

Dominion Generation Operating Segment—Dominion

The generation capacity of Dominion’s merchant fleet totals approximately 4,200 MW. The generation mix is diversified and

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:

Ÿ  

In September 2014, Dominion entered into agreements to acquire 100% of the equity interests in two solar projects in California from EDF Renewable Development, Inc. for approximately $175 million. The acquisitions are expected to close in the first half of 2015 prior to the projects commencing operations. The projects are expected to cost approximately $185 million once constructed, including the initial acquisition cost. Upon completion, the facilities are expected to generate approximately 42 MW.

Ÿ  

In October 2014, Dominion acquired 100% of the equity interests of a solar project in Utah from juwi solar Inc. The project is expected to cost approximately $120 million once constructed, including the initial acquisition cost. The facility is expected to begin commercial operations in the second half of 2015 and generate approximately 50 MW.

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.

 

 

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Biomass—Dominion Generation’s biomass supply is obtained through long-term contracts and short-term spot agreements from local suppliers.

Purchased Power—Dominion Generation purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for utility system load requirements.

Dominion Generation also occasionally purchases electricity from the PJM and ISO-NE spot markets to satisfy physical forward sale requirements as part of its merchant generation operations.

Dominion Generation Operating Segment—Virginia Power

Presented below is a summary of Virginia Power’s actual system output by energy source:

 

Source    2014     2013     2012  

Nuclear(1)

     33     33     33

Purchased power, net

     19        21        27   

Coal(2)

     30        29        22   

Natural gas

     15        16        17   

Other(3)

     3        1        1   

Total

     100     100     100

 

(1) Excludes ODEC’s 11.6% ownership interest in North Anna.
(2) Excludes ODEC’s 50.0% ownership interest in the Clover power station. The average cost of coal for 2014 Virginia in-system generation was $35.30 per MWh.
(3) Includes oil, hydro and biomass.

Dominion Generation Operating Segment-Dominion

The supply of gas to serve Dominion’s retail energy marketing customers is procured through market wholesalers or by Dominion Energy. See Dominion Energy for additional information.

SEASONALITY

Dominion Generation Operating Segment—Dominion and Virginia Power

Sales of electricity for Dominion Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. See DVP—Seasonality above for additional considerations that also apply to Dominion Generation.

Dominion Generation Operating Segment—Dominion

The earnings of Dominion’s retail energy marketing operations also vary seasonally. Generally, the demand for gas peaks during the winter months to meet heating needs.

NUCLEAR DECOMMISSIONING

Dominion Generation Operating Segment—Dominion and Virginia Power

Virginia Power has a total of four licensed, operating nuclear reactors at Surry and North Anna in Virginia.

Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers 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.

 

 

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The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion and Virginia Power are shown in the following table:

 

     

NRC

license

expiration

year

    

Most

recent

cost

estimate

(2014

dollars)(1)

    

Funds in

trusts at

December 31,

2014

    

2014

contributions

to trusts

 
(dollars in millions)                            

Surry

           

Unit 1

     2032       $ 576       $ 547       $ 0.6   

Unit 2

     2033         596         539         0.6   

North Anna

           

Unit 1(2)

     2038         493         435         0.4   

Unit 2(2)

     2040         504         409         0.3   

Total (Virginia Power)

        2,169         1,930         1.9   

Millstone

           

Unit 1(3)

     n/a         367         450           

Unit 2

     2035         540         569           

Unit 3(4)

     2045         656         559           

Kewaunee

           

Unit 1(5)

     n/a         520         688           

Total (Dominion)

            $ 4,252       $ 4,196       $ 1.9   

 

(1) The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on Dominion’s and Virginia Power’s contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Dominion’s and Virginia Power’s nuclear decommissioning AROs.
(2) North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect 89.26% of the decommissioning cost for both of North Anna’s units.
(3) Unit 1 permanently ceased operations in 1998, before Dominion’s acquisition of Millstone.
(4) Millstone Unit 3 is jointly owned by Dominion Nuclear Connecticut, with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. Decommissioning cost is shown at Dominion’s ownership percentage. At December 31, 2014, the minority owners held approximately $35 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.
(5) Permanently ceased operations in 2013.

Also see Note 14 and Note 22 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively, and Note 9 for information about nuclear decommissioning trust investments.

Dominion Energy

The Dominion Energy Operating Segment of Dominion Gas includes the majority of Dominion’s regulated natural gas operations. DTI, the gas transmission pipeline and storage business, serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in the transmission pipeline and storage business is gas gathering and processing activity, which sells extracted products at market rates. East Ohio, the primary gas distribution business of Dominion, serves residential, commercial and industrial gas sales, transportation and gathering service customers. Dominion Iroquois holds a 24.72% general partnership interest in Iroquois, which provides 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 primarily in New York.

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.

 

 

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Earnings for the Dominion Energy Operating Segment of Dominion primarily result from rates established by FERC and the West Virginia Commission. Additionally, Dominion Energy receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain LNG storage and regasification services. Hope’s gas distribution operations in West Virginia serve residential, commercial and industrial gas sales, transportation and gathering service customers. Revenue provided by Hope’s operations is based primarily on rates established by the West Virginia Commission. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their 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. However, the processing and fractionation operations within Dominion Energy’s Blue Racer joint venture are primarily managed under long-term fee-based contracts, which minimizes commodity risk.

COMPETITION

Dominion Energy Operating Segment—Dominion and Dominion Gas

Dominion Gas’ natural gas transmission operations compete with domestic and Canadian pipeline companies. Dominion Gas also competes with gas marketers seeking to provide or arrange transportation, storage and other services. Alternative energy sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain long-line pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enable Dominion to tailor its services to meet the needs of individual customers.

DTI’s processing and fractionation operations face competition in obtaining natural gas supplies for its processing and related services. Numerous factors impact any given customer’s choice of processing services provider, including the location of the facilities, efficiency and reliability of operations, and the pricing arrangements offered.

In Ohio, there has been no legislation enacted to require supplier choice for natural gas distribution consumers. However, East Ohio has offered an Energy Choice program to residential and commercial customers since October 2000. East Ohio has since taken various steps approved by the Ohio Commission toward exiting the merchant function, including restructuring its commodity service and placing Energy Choice-eligible customers in a direct retail relationship with participating suppliers. Further, in April 2013, East Ohio fully exited the merchant function for its nonresidential customers, which are now required 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 million of East Ohio’s 1.2 million Ohio customers were participating in the Energy Choice program.

Dominion Energy Operating Segment—Dominion

For Hope, West Virginia does not allow customers to choose their provider in its retail natural gas markets at this time. See

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 in Regulation 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

 

 

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one of its Pennsylvania natural gas storage fields. See Note 10 to the Consolidated Financial Statements for further information.

In July 2013, East Ohio signed long-term precedent agreements with two customers to move 320,000 Dths per day of processed gas from the outlet of new gas processing facilities in Ohio to interconnections with multiple interstate pipelines. The first phase of the Western Access Project provides system enhancements to facilitate the movement of processed gas over East Ohio’s system. The initial phase of the project was completed in the fourth quarter of 2014 and cost approximately $85 million. During the second and third quarters of 2014, East Ohio executed long-term precedent agreements with customers for 450,000 Dths per day of service to new interconnects with interstate pipelines. This second phase of the Western Access Project will expand the number of interstate pipelines to which East Ohio will deliver processed gas to four. The project is expected to be completed in the fourth quarter of 2015 and cost approximately $130 million.

In September 2014, DTI announced its intent to construct and operate the Supply Header Project which is expected to cost approximately $500 million and provide 1,500,000 Dths per day of firm transportation service to various customers. In October 2014, DTI requested authorization to use the FERC’s pre-filing process. The application to request FERC authorization to construct and operate the project facilities is expected to be filed in the third quarter of 2015, with the facilities expected to be in service in the fourth quarter of 2018. In December 2014, DTI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header Project.

In June 2014, DTI executed binding precedent agreements with two power generators for the Leidy South Project. In November 2014, one of the power generators assigned a portion of its capacity to an affiliate, bringing the total number of project customers to three. The project is expected to cost approximately $210 million and provide 155,000 Dths per day of firm transportation service from Clinton County, Pennsylvania to Loudoun County, Virginia. Because the project facilities would be installed at existing DTI compressor stations rather than greenfield sites, DTI will submit a standard certificate application rather than utilize the FERC pre-filing process. The application to request FERC authorization to construct and operate the project facilities is expected to be filed in the second quarter of 2015. Service under the 20-year contracts is expected to commence in the fourth quarter of 2017.

During the second quarter of 2014, DTI executed a binding precedent agreement with a customer for the Monroe-to-Cornwell Project. The project is expected to cost approximately $70 million and provide 205,000 Dths per day of firm transportation service from Monroe County, Ohio to an interconnect near Cornwell, West Virginia. In October 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 the first quarter of 2014, DTI executed a binding precedent agreement for the Lebanon West II Project. The project is expected to cost approximately $112 million and provide 130,000 Dths per day of firm transportation service from Butler County, Pennsylvania to an interconnect with Texas Gas Pipeline in Lebanon, Ohio. In September 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 $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

 

 

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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 an in-service date anticipated in late 2017. 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 with 20-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 the front-end engineering and design work, Dominion also announced it had awarded its EPC 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 December 2014, Cove Point filed an application to request FERC authorization to construct and operate facilities that will provide firm transportation service for a new power generating facility located in Maryland. The $31 million St. Charles Transportation Project will provide 132,000 Dths per day of firm transportation service from Cove Point’s interconnect with Transcontinental Gas Pipe Line in Fairfax County, Virginia to CPV Maryland, LLC’s facility in Charles County, Maryland. Service under a 20-year contract is expected to commence in June 2016.

In December 2014, Cove Point filed an application to request FERC authorization to construct and operate facilities that will provide firm transportation service for a new power generating facility located in Maryland. The $37 million Keys Energy Project will provide 107,000 Dths per day of firm transportation service from Cove Point’s interconnect with Transcontinental Gas Pipe Line in Fairfax County, Virginia to Keys Energy Center, LLC’s facility in Prince George’s County, Maryland. Service under a 20-year contract is expected to commence in March 2017.

See Item 2. Properties for more information about the Cove Point facility.

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.

 

 

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SEASONALITY

Dominion Energy Operating Segment—Dominion and Dominion Gas

Dominion Energy’s natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March; however, implementation of the straight-fixed-variable rate design at East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipeline and storage business can also be weather sensitive. Earnings are also impacted by changes in commodity prices driven by seasonal weather changes, the effects of unusual weather events on operations and the economy.

Corporate and Other

Corporate and Other Segment—Virginia Power and Dominion Gas

Virginia Power’s and Dominion Gas’ Corporate and Other segments primarily include certain specific items attributable to their operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

Corporate and Other Segment—Dominion

Dominion’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued, which is discussed in Note 3 and Note 25 to the Consolidated Financial Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

ENVIRONMENTAL STRATEGY

The Companies are committed to being good environmental stewards. Their ongoing objective is to provide reliable, affordable energy for their customers while being environmentally responsible. The integrated strategy to meet this objective consists of four major elements:

Ÿ  

Compliance with applicable environmental laws, regulations and rules;

Ÿ  

Conservation and load management;

Ÿ  

Renewable generation development; and

Ÿ  

Improvements in other energy infrastructure, including natural gas operations.

This strategy incorporates the Companies’ efforts to voluntarily reduce GHG emissions, which are described below. See Dominion Generation-Properties and Dominion Energy-Properties for more information on certain of the projects described below. In addition to the environmental strategy described above, Dominion formed the AES department in April 2009 to conduct research in the renewable and alternative energy technologies sector and to support strategic investments to advance Dominion’s degree of understanding of such technologies.

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

 

 

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electricity demand within its service territory, maintain reliability, and to address environmental requirements. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service, and are intended to address both continued population growth and increases in electricity consumption by the typical consumer. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed or to be developed in the future. See Properties in Item 1., Operating Segments, DVP for additional information.

Dominion and Dominion Gas, in connection with their six-year investment plan, are also pursuing the construction or upgrade of regulated infrastructure in their natural gas businesses. See Properties and Investments in Item 1., Operating Segments, Dominion Energy for additional information, including natural gas infrastructure projects.

The Companies’ Strategy for Voluntarily Reducing GHG Emissions

The Companies have not established a standalone GHG emissions reduction target or timetable, but they are actively engaged in voluntary reduction efforts. The Companies have an integrated voluntary strategy for reducing GHG emission intensity with diversification as its cornerstone. The six principal components of the strategy include initiatives that address electric energy management, electric energy production, electric energy delivery and natural gas storage, transmission and delivery, as follows:

Ÿ  

Enhance conservation and energy efficiency programs to help customers use energy wisely and reduce environmental impacts;

Ÿ  

Expand the Companies’ renewable energy portfolio, principally wind power, solar, fuel cells and biomass, to help diversify the Companies’ fleet, meet state renewable energy targets and lower the carbon footprint;

Ÿ  

Build other new generating capacity, including low-emissions natural-gas fired and emissions-free nuclear units to meet customers’ future electricity needs;

Ÿ  

Construct new electric transmission infrastructure to modernize the grid, promote economic security and help deliver more green energy to population centers where it is needed most;

Ÿ  

Construct new natural gas infrastructure to expand availability of this cleaner fuel, to reduce emissions, and to promote energy and economic security both in the U.S. and abroad; and

Ÿ  

Implement and enhance voluntary methane mitigation measures through the EPA’s Natural Gas Star Program.

Since 2000, Dominion and Virginia Power have tracked the emissions of their electric generation fleet, which employs a mix of fuel and renewable energy sources. Comparing annual year 2000 to annual year 2013, the entire electric generating fleet (based on ownership percentage) reduced its average CO2 emissions rate per MWh of energy produced from electric generation by about 39%. Comparing annual year 2000 to annual year 2013, the regulated electric generating fleet (based on ownership percentage) reduced its average CO2 emissions rate per MWh of energy produced from electric generation by about 19%. Dominion and Virginia Power do not yet have final 2014 emissions data.

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.

 

 

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Electric Regulation in Virginia

Under the Regulation Act enacted in 2007, Virginia Power’s base rates are set by a process that allows the recovery of operating costs and an ROIC. The Virginia Commission reviews and has the ability to adjust Virginia Power’s base rates, terms and conditions for generation and distribution services on a biennial basis in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a combined two-year historic test period, and the determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances described in the Regulation Act, the Virginia Commission may also order a base rate increase or reduction during the biennial review. Circumstances where the Virginia Commission may order a base rate decrease include determination by the Virginia Commission that Virginia Power has exceeded its authorized level of earnings for two consecutive biennial review periods. Virginia Power’s authorized ROE can be set no lower than the average, for a three-year historic period, of the actual returns reported to the SEC by not less than a majority of comparable utilities within the Southeastern U.S., with certain limitations as described in the Regulation Act.

In February 2015, the Virginia Governor signed legislation into law which will keep Virginia Power’s base rates unchanged until at least December 1, 2022. The legislation limits the 2015 biennial review to solely a determination of Virginia Power’s actual earned ROE during the combined 2013-2014 test period and whether any refunds are due to customers. In addition, no biennial reviews will be conducted by the Virginia Commission for the five successive 12-month test periods beginning January 1, 2015, and ending December 31, 2019. During this suspension period, Virginia Power bears the risk of any severe weather events and natural disasters, as well as the risk of asset impairments related to the early retirement of any generation facilities due to the implementation of the Clean Power Plan regulations, and Virginia Power may not recover its associated costs through increases to base rates. The legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility’s ROE for use in connection with rate adjustment clauses.

The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs; and it provides for enhanced returns on capital expenditures on specific new generation projects. The Regulation Act also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.

Legislation enacted in February 2013 amended the Regulation Act prospectively, including elimination of the 50 basis points RPS ROE incentive. 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, the Virginia Commission has the discretion to increase or decrease a utility’s authorized ROE based on the utility’s performance consistent with Virginia Commission precedent that existed prior 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.

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

 

 

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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. A straight-fixed-variable rate design, in which the majority of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohio’s customers pursuant to a 2008 rate case settlement which included an authorized return on equity of 10.38%.

In addition to general base rate increases, East Ohio makes routine filings with the Ohio Commission to reflect changes in the costs of gas purchased for operational balancing on its system. 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 rider filings cover unrecovered gas costs plus prospective annual demand costs. Increases or decreases in gas cost rider rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure projects and certain other costs that vary widely over time; such costs are excluded from general base rates. See Note 13 to the Consolidated Financial Statements for additional information.

Gas Regulation in West Virginia

Dominion’s gas distribution subsidiary 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.

Status of Competitive Retail Gas Services

Both of the states in which Dominion and Dominion Gas have gas distribution operations have considered legislation regarding a competitive deregulation of natural gas sales at the retail level.

Ohio—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 month-end settlement and passing that gas cost to customers under the Standard Service Offer pro-

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

FEDERAL ENERGY REGULATORY COMMISSION

Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominion’s merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion’s market-based sales tariffs authorized by FERC. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.

Dominion and Virginia Power are subject to FERC’s Standards of Conduct that govern conduct between transmission function employees of interstate gas and electricity transmission providers and the marketing function employees of their affiliates. The rule defines the scope of transmission and marketing-related functions that are covered by the standards and is designed to prevent transmission providers from giving their affiliates undue preferences.

Dominion and Virginia Power are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between Virginia Power and Dominion’s merchant plants without first receiving FERC authorization, (2) require the merchant plants and Virginia Power to conduct their wholesale power sales operations separately, and (3) prohibit Virginia Power from sharing market information with merchant plant operating personnel. The rules are designed to prohibit Virginia Power from giving the merchant plants a competitive advantage.

 

 

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EPACT included provisions to create an ERO. The ERO is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC has certified NERC as the ERO and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of between $1 thousand and $1 million per day, and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.

Dominion and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion and Virginia Power employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. Dominion and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cybersecurity programs as well as efforts to ensure appropriate facility ratings for Virginia Power’s transmission lines. In October 2010, NERC issued an industry alert identifying possible discrepancies between the design and actual field conditions of transmission facilities as a potential reliability issue. The alert recommends that entities review their current facilities rating methodology to verify that the methodology is based on actual field conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power has evaluated its transmission facilities for any discrepancies between design and actual field conditions and has taken necessary corrective actions. In addition, NERC has redefined critical assets which expanded the number of assets subject to NERC reliability standards, including cybersecurity assets. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.

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

Gas

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

Dominion 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 and FERC regulations.

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

 

 

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federal, regional and state legislative and regulatory action in this area. The Companies support national climate change legislation that would provide a consistent, economy-wide approach to addressing this issue and are currently taking action to protect the environment and address climate change while meeting the future needs of their growing service territory. Dominion’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including climate change, and Dominion’s Board of Directors receives periodic updates on these matters. See Environmental Strategy above, Environmental Matters in Future Issues and Other Matters in 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.

Nuclear Regulatory Commission

All aspects of the operation and maintenance of Dominion’s and Virginia Power’s nuclear power stations are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.

From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining Dominion’s and Virginia Power’s nuclear generating units. See Note 22 to the Consolidated Financial Statements for further information.

The NRC also requires Dominion and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and Dominion and Virginia Power are required by the NRC to be financially prepared. For information on decommissioning trusts, see Dominion Generation-Nuclear Decommissioning above and Note 9 to the Consolidated Financial Statements. See Note 22 to the Consolidated Financial Statements for information on spent nuclear fuel.

 

 

CYBERSECURITY

In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, the Companies are subject to mandatory cybersecurity regulatory requirements, interface regularly with a wide range of external organizations, and participate in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. The Companies’ current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats. See Item 1A. Risk Factors for additional information.

 

 

Item 1A. Risk Factors

The Companies’ businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond their control. A number

of these factors have been identified below. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in Item 7. MD&A.

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

 

 

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proceeding that involves the determination of Virginia Power’s actual earned ROE during a combined two-year historic test period, and the determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances described in the Regulation Act, Virginia Power may be required to share a portion of its earnings with customers through a refund process.

Legislation signed by the Virginia Governor in February 2015 suspends biennial reviews for the five successive 12-month test periods beginning January 1, 2015 and ending December 31, 2019, and no changes will be made to Virginia Power’s existing base rates until at least December 1, 2022. During this period, Virginia Power bears the risk of any severe weather events and natural disasters, as well as the risk of asset impairments related to the early retirement of any generation facilities due to the implementation of the Clean Power Plan regulations, and Virginia Power may not recover its associated costs through increases to base rates. If Virginia Power incurs any such significant unusual expenses during this period, Virginia Power may not be able to recover its costs and/or earn a reasonable return on capital investment, which could negatively affect Virginia Power’s future earnings.

Virginia Power’s retail electric base rates for bundled generation, transmission, and distribution services to customers in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes, and the rules and procedures of the North Carolina Commission. If retail electric earnings exceed the returns established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery through base rates, on a timely basis, of costs incurred in providing service, Virginia Power’s future earnings could be negatively impacted.

The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of operations and subject the Companies to monetary penalties. The Companies’ operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. Such laws and regulations govern the terms and conditions of the services we offer, our relationships with affiliates, protection of our critical electric infrastructure assets and pipeline safety, among other matters. These operations are also subject to legislation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that the business is conducted in accordance with applicable laws. The Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if any of the Companies is found not to be in compliance, including mandatory reliability standards and interaction in the wholesale markets. New laws or regulations, the revision or reinterpretation of existing laws or regulations, changes in enforcement practices of regulators, or penalties imposed for non-compliance with existing laws or regulations may result in substantial additional expense.

Dominion’s and Virginia Power’s generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. Dominion’s and Virginia Power’s generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs to make changes in market design. FERC also periodically reviews Dominion’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets 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

 

 

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disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects.

The development and construction of several large-scale infrastructure projects simultaneously involves significant execution risk. The Companies are currently simultaneously developing or constructing several major projects, including the Liquefaction Project, the Atlantic Coast Pipeline project, the strategic undergrounding project, Brunswick County, and multiple DTI producer outlet projects, which together help contribute to the over $16 billion in capital expenditures planned by the Companies through 2017. Several of the Companies’ key projects are increasingly large-scale, complex and being constructed in constrained geographic areas (for example, the Liquefaction Project) or in difficult terrain (for example, the Atlantic Coast Pipeline project). The advancement of the Companies’ ventures is also affected by the activities of stakeholder and advocacy groups, some of which oppose natural gas-related and energy infrastructure projects. Given that these projects provide the foundation for the Companies’ strategic growth plan, if the Companies are unable to obtain the required approvals, develop the necessary technical expertise, allocate and coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies’ financial position, results of operations and cash flows. Further, an inability to obtain financing or otherwise provide liquidity for the projects on acceptable terms could negatively affect the Companies’ financial condition, cash flows, the projects’ anticipated financial results and/or impair the Companies’ ability to execute the business plan for the projects as scheduled.

Given their significant anticipated capital expenditures and unique attributes, the Liquefaction Project and the Atlantic Coast Pipeline project in particular are subject to significant execution risk.

Cove Point Liquefaction Project—The Liquefaction Project, which is expected to cost approximately $2.6 billion to complete, exclusive of financing costs, involves regulatory, construction, customer and other risks. Dominion has received the required approvals to commence construction of the Liquefaction Project from the DOE, FERC and the Maryland Commission, which are subject to compliance with the applicable permit conditions. However, all DOE export licenses are subject to review and possible withdrawal should the DOE conclude that such export authorization is no longer in the public interest. The issuance of the FERC and Maryland approval orders has been appealed by third parties. Dominion does not know whether any existing or potential interventions or other actions by third parties will interfere with its ability to maintain such approvals, but loss of any material approval could have a material adverse effect on the construction or operation of the facility. In addition, the Liquefaction Project has been the subject of litigation in the past and could be the subject of litigation in the future. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect Dominion’s ability to execute its business plan.

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-

 

 

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ing efficiency improvements from fossil fuel-fired electric generating units.

Compliance with GHG emission reduction requirements may require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon controls and/or reduction programs, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower emitting generation facilities. The Clean Power Plan uses a set of measures for reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units, expanding renewable resources and increasing customer energy efficiency. Compliance with the Clean Power Plan’s anticipated implementing regulations may require Virginia Power to prematurely retire certain generating facilities, with the potential lack or delay of cost recovery and substantially higher electric rates, which could affect consumer demand. The cost of compliance with GHG emission legislation and/or regulation is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon controls and/or reduction programs, and the selected compliance alternatives. Dominion and Virginia Power cannot estimate the aggregate effect of such requirements on their results of operations, financial condition or their customers. However, such expenditures, if material, could make Dominion’s and Virginia Power’s generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.

There are also potential impacts on Dominion’s and Dominion Gas’ natural gas businesses as federal or state GHG legislation or regulations may require GHG emission reductions from the natural gas sector and could affect demand for natural gas. Several regions of the U.S. have moved forward with GHG emission regulations including regions where Dominion has operations. For example, Rhode Island has implemented regulations requiring reductions in CO2 emissions through RGGI, a cap and trade program covering CO2 emissions from power plants in the Northeast. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products.

The Companies’ operations are subject to a number of environmental laws and regulations which impose significant compliance costs to the Companies. The Companies’ operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of environmental control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and the Companies expect that they will remain significant in the

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

 

 

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by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. The Companies’ businesses are dependent upon sophisticated information technology systems and network infrastructure, the failure of which could prevent them from accomplishing critical business functions. Because the Companies’ transmission facilities, pipelines and other facilities are interconnected with those of third parties, the operation of their facilities and pipelines could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

Operation of the Companies’ facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of the Companies’ facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less output or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement output from third parties in the open market to satisfy forward energy and capacity or other contractual obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.

In addition, there are many risks associated with the Companies’ operations and the transportation, storage and processing of natural gas and NGLs, including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environmental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk. Further, the location of pipelines and storage facilities, or generation, transmission, substations and distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.

Dominion and Virginia Power have substantial ownership interests in and operate nuclear generating units; as a result, each may incur substantial costs and liabilities. Dominion’s and Virginia Power’s nuclear facilities are subject to operational, environmental, health and financial risks such as the on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. Dominion and Virginia Power maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If

Dominion’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

 

 

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cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion does not enter into long-term power purchase agreements or otherwise effectively hedge its output, these changes in market prices could adversely affect its financial results.

Dominion purchases fuel under a variety of terms, including long-term and short-term contracts and spot market purchases. Dominion is exposed to fuel cost volatility for the portion of its fuel obtained through short-term contracts or on the spot market, including as a result of market supply shortages. Fuel prices can be volatile and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs, thus adversely impacting Dominion’s financial results.

In addition, in the event that any of the merchant generation facilities experience a forced outage, Dominion may not receive the level of revenue it anticipated.

The Companies’ financial results can be adversely affected by various factors driving demand for electricity and gas and related services. Technological advances required by federal laws mandate new levels of energy efficiency in end-use devices, including lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Further, Virginia Power’s business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility generation. However, advances in distributed generation technologies, such as solar cells, gas microturbines and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use our services.

Reduced energy demand or significantly slowed growth in demand due to customer adoption of energy efficient technology, conservation, distributed generation or regional economic conditions, unless substantially offset through regulatory cost allocations, could adversely impact the value of the Companies’ business activities.

Dominion Gas has experienced a decline in demand for certain of its processing services due to competing facilities operating in nearby areas.

Dominion Gas may not be able to maintain, renew or replace its existing portfolio of customer contracts successfully, or on favorable terms. Upon contract expiration, customers may not elect to re-contract with Dominion Gas as a result of a variety of factors, including the amount of competition in the industry, changes in the price of natural gas, their level of satisfaction with Dominion Gas’ services, the extent to which Dominion Gas is able to successfully execute its business plans and the effect of the regulatory framework on customer demand. The failure to replace any such customer contracts on similar terms could result in a loss of revenue for Dominion Gas.

Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. The Companies are exposed to credit risks of their counterparties and the risk that

one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. 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

 

 

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requirements. Final rules for the over-the-counter derivative-related provisions of the Dodd-Frank Act will continue to be established through the ongoing rulemaking process of the applicable regulators, including rules regarding margin requirements for non-cleared swaps. If, as a result of the rulemaking process, the Companies’ derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs, including from higher margin requirements, for their derivative activities. In addition, implementation of, and compliance with, the swaps provisions of the Dodd-Frank Act by the Companies’ counterparties could result in increased costs related to the Companies’ derivative activities.

Changing rating agency requirements could negatively affect the Companies’ growth and business strategy. In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, the Companies may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in the Companies’ credit ratings could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require the Companies to post additional collateral in connection with some of its price risk management activities.

Dominion Gas depends, in part, on an intercompany credit agreement with Dominion and certain bank syndicated credit facilities available to Dominion and Dominion Gas for short-term borrowings to meet working capital needs. If Dominion’s short-term funding resources, which include the commercial paper market and its syndicated bank credit facilities, become unavailable to Dominion, Dominion Gas’ access to short-term funding could also be in jeopardy. Dominion Gas relies, in part, on an IRCA with Dominion to provide Dominion Gas, and its subsidiaries, with short-term borrowings to meet working capital and other cash needs. Dominion relies, in part, on the issuance of commercial paper in the short-term money markets to fund advances it makes to Dominion Gas under the IRCA. The issuance of commercial paper by Dominion is supported by its access to two bank syndicated revolving credit facilities. In addition, these facilities could be drawn upon either by Dominion Gas directly or by Dominion to fund Dominion Gas borrowing requests under the IRCA.

In the event of a default under the bank syndicated credit facilities by any of the Companies, Dominion could lose access to these facilities. In such an event, Dominion may not be able to rely on either the commercial paper market or the bank facility for its own short-term funding, and thus may not be able to fund a request by Dominion Gas under the IRCA.

An inability to access financial markets could adversely affect the execution of the Companies’ business plans. The Companies rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for business plans with increasing capital expenditure needs, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of the Companies’

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.

 

 

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A successful cyber attack on the systems that control the Companies’ electric generation, electric or gas transmission or distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. The Companies maintain property and casualty insurance that may cover certain damage caused by potential cyber incidents; however, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect the Companies’ business, financial condition and results of operations.

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on the Companies’ operations. The Companies’ business strategy is dependent on their ability to recruit, retain and motivate employees. The Companies’ key executive officers are the CEO, CFO and presidents and those responsible for financial, operational, legal, regulatory and accounting functions. Competition for skilled management employees in these areas of the Companies’ business operations is high. In addition, demand for skilled professional and technical employees in gas transmission, storage, gathering, processing and distribution and in design and construction is high in light of growth in demand for natural gas, increased supply of natural gas as a result of developments in gas production, increased infrastructure projects, increased risk in certain areas of the business, such as cybersecurity, and increased regulation of these activities. The Companies’ inability to retain and attract these employees could adversely affect their business and future operating results. An aging workforce in the energy industry also necessitates recruiting, retaining and developing the next generation of leadership.

 

 

Item 1B. Unresolved Staff Comments

None.

 

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.

 

 

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DVP

See Item 1. Business, General for details regarding DVP’s principal properties, which primarily include transmission and distribution lines.

 

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.

 

 

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The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2014:

VIRGINIA POWER UTILITY GENERATION

 

Plant    Location   

Net Summer

Capability (MW)

   

Percentage

Net Summer

Capability

 

Gas

       

Warren County (CC)

   Warren County, VA      1,342     

Ladysmith (CT)

   Ladysmith, VA      783     

Remington (CT)

   Remington, VA      608     

Bear Garden (CC)

   Buckingham County, VA      590     

Possum Point (CC)

   Dumfries, VA      559     

Chesterfield (CC)

   Chester, VA      397     

Elizabeth River (CT)

   Chesapeake, VA      348     

Possum Point

   Dumfries, VA      316     

Bellemeade (CC)

   Richmond, VA      267     

Bremo(1)

   Bremo Bluff, VA      227     

Gordonsville Energy (CC)

   Gordonsville, VA      218     

Gravel Neck (CT)

   Surry, VA      170     

Darbytown (CT)

   Richmond, VA      168     

Rosemary (CC)

   Roanoke Rapids, NC      165           

Total Gas

        6,158        30

Coal

       

Mt. Storm

   Mt. Storm, WV      1,629     

Chesterfield

   Chester, VA      1,267     

Virginia City Hybrid Energy Center

   Wise County, VA      610     

Clover

   Clover, VA      439 (3)   

Yorktown(2)

   Yorktown, VA      323     

Mecklenburg

   Clarksville, VA      138           

Total Coal

        4,406        22   

Nuclear

       

Surry

   Surry, VA      1,676     

North Anna

   Mineral, VA      1,672 (4)         

Total Nuclear

        3,348        16   

Oil

       

Yorktown

   Yorktown, VA      790     

Possum Point

   Dumfries, VA      786     

Gravel Neck (CT)

   Surry, VA      198     

Darbytown (CT)

   Richmond, VA      168     

Possum Point (CT)

   Dumfries, VA      72     

Chesapeake (CT)

   Chesapeake, VA      51     

Low Moor (CT)

   Covington, VA      48     

Northern Neck (CT)

   Lively, VA      47           

Total Oil

        2,160        11   

Hydro

       

Bath County

   Warm Springs, VA      1,802 (5)   

Gaston

   Roanoke Rapids, NC      220     

Roanoke Rapids

   Roanoke Rapids, NC      95     

Other

   Various      3           

Total Hydro

        2,120        10   

Biomass

       

Pittsylvania

   Hurt, VA      83     

Altavista

   Altavista, VA      51     

Polyester

   Hopewell, VA      51     

Southhampton

   Southampton, VA      51           

Total Biomass

        236        1   

Various

       

Mt. Storm (CT)

   Mt. Storm, WV      11          
            18,439           

Power Purchase Agreements

          1,978        10   

Total Utility Generation

          20,417        100

Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.

(1) Converted from coal to gas in 2014.
(2) Coal-fired units are expected to be retired at Yorktown as early as 2016 as a result of the issuance of the MATS rule.
(3) Excludes 50% undivided interest owned by ODEC.
(4) Excludes 11.6% undivided interest owned by ODEC.
(5) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.

 

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DOMINION MERCHANT GENERATION

 

Plant    Location   

Net Summer

Capability (MW)

   

Percentage

Net Summer

Capability

 

Nuclear

       

Millstone

   Waterford, CT      2,001 (1)         

Total Nuclear

        2,001        48

Gas

       

Fairless (CC)

   Fairless Hills, PA      1,196     

Manchester (CC)

   Providence, RI      461           

Total Gas

        1,657        39   

Wind

       

Fowler Ridge(2)

   Benton County, IN      150 (3)   

NedPower Mt. Storm(2)

   Grant County, WV      132 (4)         

Total Wind

        282        7   

Solar(5)

       

Camelot Solar

   Mojave, CA      45     

Indy Solar

   Indianapolis, IN      29     

CID Solar

   Corcoran, CA      20     

Kansas Solar

   Lenmore, CA      20     

Kent South Solar

   Lenmore, CA      20     

Old River One Solar

   Bakersfield, CA      20     

West Antelope Solar

   Lancaster, CA      20     

Adams East Solar

   Tranquility, CA      19     

Mulberry Solar

   Selmer, TN      16     

Selmer Solar

   Selmer, TN      16     

Columbia 2 Solar

   Mojave, CA      15     

Azalea Solar

   Davisboro, GA      8     

Somers Solar

   Somers, CT      5           

Total Solar

        253        6   

Fuel Cell

       

Bridgeport Fuel Cell

   Bridgeport, CT      15           

Total Fuel Cell

          15          

Total Merchant Generation

          4,208        100

Note: (CC) denotes combined cycle.

(1) Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain.
(2) Subject to a lien securing the facility’s debt.
(3) Excludes 50% membership interest owned by BP.
(4) Excludes 50% membership interest owned by Shell.
(5) All solar facilities are alternating current.

 

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Item 3. Legal Proceedings

From time to time, the Companies are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Companies, or permits issued by various local, state and/or federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Companies and their subsidiaries are involved in various legal proceedings.

In August 2014, Cove Point received a “Request to Show Cause” from the EPA alleging violations of certain release reporting requirements under CERCLA and EPCRA. In February 2013, Cove Point first reported to the EPA a continuous release of ammonia emissions from the NOx control systems attached to its electric generating turbines as a part of normal operations. While these emissions are not subject to permit limits, Cove Point verified and submitted to the EPA that the ammonia emissions periodically exceeded the reporting threshold between December 2012 and February 2013. Cove Point further submitted to the EPA the required written follow-up reports. In December 2014, Cove Point and the EPA finalized a Consent Agreement and Final Order resolving this matter, which included a civil penalty of $365,000. Cove Point paid the penalty in December 2014.

In October 2014, Virginia Power received a draft consent order from the VDEQ in connection with excess carbon monoxide emissions reported in February 2014 for Altavista. The draft consent order included a proposed penalty of approximately $135,000. In January 2015, Virginia Power and VDEQ finalized a consent order resolving this matter, which included a final penalty of approximately $95,000. Virginia Power has also submitted to VDEQ a request to modify Altavista’s Title V air permit to address the underlying operational issues.

In January 2015, Virginia Power received a draft consent order from the VDEQ in connection with excess particulate matter emissions reported in August and September 2014 for Yorktown. Virginia Power submitted evidence in late September 2014 that the excess emissions have been corrected. In January 2015, Virginia Power and VDEQ finalized a consent order resolving this matter, which included a penalty of approximately $107,000.

Also in January 2015, DTI received a draft consent agreement from the EPA in connection with alleged violations of certain CAA monitoring and permitting requirements at the Hastings facility. The draft consent agreement includes a proposed penalty of approximately $160,000. DTI is working with the EPA to resolve this matter. The ultimate resolution of the consent agreement is not expected to have a material effect on Dominion Gas.

See Notes 13 and 22 to the Consolidated Financial Statements and Future Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which the Companies are a party.

Item 4. Mine Safety Disclosures

Not applicable.

 

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Executive Officers of Dominion

 

 

 

Information concerning the executive officers of Dominion, each of whom is elected annually, is as follows:

 

Name and Age    Business Experience Past Five Years(1)

Thomas F. Farrell II (60)

   Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date. Chairman and CEO of Dominion Midstream GP, LLC (the general partner of Dominion Midstream) from March 2014 to date and President from February 2015 to date; CEO of Dominion Gas from September 2013 to date and Chairman from March 2014 to date; Chairman and CEO of Virginia Power from February 2006 to date.

Mark F. McGettrick (57)

   Executive Vice President and CFO of Dominion from June 2009 to date, Dominion Midstream GP, LLC from March 2014 to date, Virginia Power from June 2009 to date and Dominion Gas from September 2013 to date.

David A. Christian (60)

   Executive Vice President and CEO—Dominion Generation Group of Dominion from February 2013 to date; Executive Vice President of Dominion from May 2011 to February 2013; President and COO of Virginia Power from June 2009 to date.

Paul D. Koonce (55)

   Executive Vice President and CEO—Energy Infrastructure Group of Dominion from February 2013 to date; Executive Vice President of Dominion from April 2006 to February 2013; Executive Vice President of Dominion Midstream GP, LLC from March 2014 to date; President and COO of Virginia Power from June 2009 to date; President of Dominion Gas from September 2013 to date.

David A. Heacock (57)

   President and CNO of Virginia Power from June 2009 to date.

Robert M. Blue (47)

   President of Virginia Power from January 2014 to date; Senior Vice President-Law, Public Policy and Environment of Dominion from January 2011 to December 2013; Senior Vice President-Public Policy and Environment of Dominion from February 2010 to December 2010.

Michele L. Cardiff (47)

   Vice President, Controller and CAO of Dominion from April 2014 to date; Vice President-Accounting of DRS from January 2014 to March 2014; Vice President, Controller and CAO of Virginia Power from April 2014 to date, Dominion Gas from March 2014 to date, and Dominion Midstream GP, LLC from March 2014 to date and General Auditor of DRS from September 2012 to December 2013; Controller of Virginia Power from June 2009 to August 2012.

Diane Leopold (48)

   President of DTI, East Ohio and Dominion Cove Point, Inc. from January 2014 to date; Senior Vice President of DTI from April 2012 to December 2013; Senior Vice President—Business Development & Generation Construction of Virginia Power from April 2009 to March 2012.

Mark O. Webb (50)

   Vice President, General Counsel and Chief Risk Officer of Dominion, Virginia Power and Dominion Gas from January 2014 to date; Vice President and General Counsel of Dominion Midstream GP, LLC from March 2014 to date; Vice President and General Counsel of Dominion from January 2013 to December 2013; Deputy General Counsel of DRS from July 2011 to December 2012; Director-Policy & Business Evaluation AES of DRS from May 2009 to June 2011.

 

(1) Any service listed for Virginia Power, Dominion Midstream GP, LLC, Dominion Gas, DTI, East Ohio, Dominion Cove Point, Inc. and DRS reflects service at a subsidiary of Dominion.

 

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Part II

 

 

 

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Dominion

Dominion’s common stock is listed on the NYSE. At January 31, 2015, there were approximately 132,000 record holders of Dominion’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion Direct. Discussions of expected dividend payments and restrictions on Dominion’s payment of dividends required by this Item are contained in Liquidity and Capital Resources in Item 7. MD&A and Notes 17 and 20 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 2014 and 2013. Quarterly information concerning stock prices and dividends is disclosed in Note 26 to the Consolidated Financial Statements, which information is incorporated herein by reference.

The following table presents certain information with respect to Dominion’s common stock repurchases during the fourth quarter of 2014:

 

 

DOMINION PURCHASES OF EQUITY SECURITIES  
Period   

Total

Number

of Shares

(or Units)

Purchased(1)

    

Average

Price

Paid per

Share

(or Unit)(2)

    

Total Number

of Shares (or Units)

Purchased as Part

of Publicly Announced

Plans or Programs

    

Maximum Number (or

Approximate Dollar Value)

of Shares (or Units) that May

Yet Be Purchased under the

Plans or Programs(3)

 

10/1/2014-10/31/14

     405       $ 69.26         N/A       19,629,059 shares/$ 1.18 billion   

11/1/2014-11/30/14

     444       $ 71.30         N/A       19,629,059 shares/$ 1.18 billion   

12/1/2014-12/31/14

           $         N/A       19,629,059 shares/$ 1.18 billion   

Total

     849       $ 70.33         N/A       19,629,059 shares/$ 1.18 billion   

 

(1) 405 and 444 shares were tendered by employees to satisfy tax withholding obligations on vested restricted stock in October and November 2014, respectively.
(2) Represents the weighted-average price paid per share.
(3) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion Board of Directors was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion.

Virginia Power

There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion. Restrictions on Virginia Power’s payment of dividends are discussed in Note 20 to the Consolidated Financial Statements. Virginia Power paid quarterly cash dividends on its common stock as follows:

 

     

First

Quarter

    

Second

Quarter

    

Third

Quarter

    

Fourth

Quarter

    

Full

Year

 
(millions)                                   

2014

   $ 148       $ 121       $ 196       $ 125       $ 590   

2013

     148         120         195         116         579   

As discussed in Note 18 to the Consolidated Financial Statements in this report, during 2014, Virginia Power redeemed all shares of each outstanding series of its preferred stock. Effective October 30, 2014, the Virginia Power Board of Directors approved amendments to Virginia Power’s Articles of Incorporation to delete references to the redeemed series of preferred stock.

The text of the foregoing amendment to Virginia Power’s Articles of Incorporation is included in the Amended and Restated Articles of Incorporation filed with Virginia Power’s quarterly report on Form 10-Q for the nine months ended September 30, 2014.

Dominion Gas

All of Dominion Gas’ membership interests are owned by Dominion. Restrictions on Dominion Gas’ payment of distributions are discussed in Note 20 to the Consolidated Financial Statements. Dominion Gas paid quarterly distributions as follows:

 

     

First

Quarter

    

Second

Quarter

    

Third

Quarter

    

Fourth

Quarter

    

Full

Year

 
(millions)                                   

2014

   $ 78       $ 67       $ 61       $ 140       $ 346   

2013

                     80         318         398   

 

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Item 6. Selected Financial Data

DOMINION

 

Year Ended December 31,    2014      2013     2012     2011     2010  
(millions, except per share amounts)                                

Operating revenue

   $ 12,436       $ 13,120      $ 12,835      $ 13,765      $ 14,392   

Income from continuing operations, net of tax(1)

     1,310         1,789        1,427        1,466        3,056   

Loss from discontinued operations, net of tax(1)

             (92     (1,125     (58     (248

Net income attributable to Dominion

     1,310         1,697        302        1,408        2,808   

Income from continuing operations before loss from discontinued operations per common share-basic

     2.25         3.09        2.49        2.56        5.19   

Net income attributable to Dominion per common share-basic

     2.25         2.93        0.53        2.46        4.77   

Income from continuing operations before loss from discontinued operations per common share-diluted

     2.24         3.09        2.49        2.55        5.18   

Net income attributable to Dominion per common share-diluted

     2.24         2.93        0.53        2.45        4.76   

Dividends declared per common share

     2.40         2.25        2.11        1.97        1.83   

Total assets

     54,327         50,096        46,838        45,614        42,817   

Long-term debt

     21,805         19,330        16,851        17,394        15,758   

 

(1) Amounts attributable to Dominion’s common shareholders.

2014 results include $248 million of after-tax charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, a $193 million after-tax charge related to Dominion’s restructuring of its producer services business and a $174 million after-tax charge associated with the Liability Management Exercise.

2013 results include a $109 million after-tax charge related to Dominion’s restructuring of its producer services business ($76 million) and an impairment of certain natural gas infrastructure assets ($33 million). Also in 2013, Dominion recorded a $92 million after-tax net loss from the discontinued operations of Brayton Point and Kincaid.

2012 results include a $1.1 billion after-tax loss from discontinued operations, including impairment charges, of Brayton Point and Kincaid and a $303 million after-tax charge primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013.

2011 results include a $139 million after-tax charge reflecting generation plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units and a $59 million after-tax charge reflecting restoration costs associated with damage caused by Hurricane Irene.

2010 results include a $1.4 billion after-tax net income benefit from the sale of substantially all of Dominion’s Appalachian E&P operations, net of charges related to the divestiture and a $202 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program. The loss from discontinued operations in 2010 includes $127 million of after-tax impairment charges at certain merchant generation facilities and a $140 million after-tax loss on the sale of Peoples.

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

 

 

MD&A discusses Dominion’s results of operations and general financial condition and Virginia Power’s and Dominion Gas’ results of operations. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power and Dominion Gas meet the conditions to file under the reduced disclosure format, and therefore have omitted certain sections of MD&A.

 

 

CONTENTS OF MD&A

MD&A consists of the following information:

Ÿ  

Forward-Looking Statements

Ÿ  

Accounting Matters—Dominion

Ÿ  

Dominion

  Ÿ  

Results of Operations

  Ÿ  

Segment Results of Operations

Ÿ  

Virginia Power

  Ÿ  

Results of Operations

Ÿ  

Dominion Gas

  Ÿ  

Results of Operations

Ÿ  

Liquidity and Capital Resources—Dominion

Ÿ  

Future Issues and Other Matters—Dominion

 

 

FORWARD-LOOKING STATEMENTS

This report contains statements concerning the Companies’ expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words.

The Companies make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:

Ÿ  

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

Ÿ  

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

Ÿ  

Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;

Ÿ  

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

Ÿ  

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

Ÿ  

Changes in enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;

Ÿ  

Changes in regulator implementation of environmental standards and litigation exposure for remedial activities;

Ÿ  

Difficult to anticipate mitigation requirements associated with environmental approvals;

Ÿ  

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

Ÿ  

Unplanned outages at facilities in which the Companies have an ownership interest;

Ÿ  

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

Ÿ  

Counterparty credit and performance risk;

Ÿ  

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

Ÿ  

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

Ÿ  

Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion and Dominion Gas;

Ÿ  

Fluctuations in interest rates;

Ÿ  

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

Ÿ  

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

Ÿ  

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

Ÿ  

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

Ÿ  

Impacts of acquisitions, divestitures, transfers of assets to joint ventures or Dominion Midstream, and retirements of assets based on asset portfolio reviews;

Ÿ  

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

Ÿ  

The timing and execution of Dominion Midstream’s growth strategy;

Ÿ  

Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;

Ÿ  

Political and economic conditions, including inflation and deflation;

Ÿ  

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

Ÿ  

Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Gas’ pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;

Ÿ  

Additional competition in industries in which the Companies operate, including in electric markets in which Dominion’s merchant generation facilities operate, and competition in the development, construction and ownership of certain electric transmission facilities in Virginia Power’s service territory in connection with FERC Order 1000;

Ÿ  

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

 

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

 

 

 

Ÿ  

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

Ÿ  

Changes in operating, maintenance and construction costs;

Ÿ  

Timing and receipt of regulatory approvals necessary for planned construction or expansion projects and compliance with conditions associated with such regulatory approvals;

Ÿ  

The inability to complete planned construction, conversion or expansion projects at all, or with the outcomes or within the terms and time frames initially anticipated;

Ÿ  

Adverse outcomes in litigation matters or regulatory proceedings; and

Ÿ  

The impact of operational hazards including adverse developments with respect to pipeline safety or integrity, and other catastrophic events.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.

The Companies’ forward-looking statements are based on beliefs and assumptions using information available at the time the statements are made. The Companies caution the reader not to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. The Companies undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

 

 

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

Dominion has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions. Dominion has discussed the development, selection and disclosure of each of these policies with the Audit Committee of its Board of Directors.

ACCOUNTING FOR REGULATED OPERATIONS

The accounting for Dominion’s regulated electric and gas operations differs from the accounting for nonregulated operations in that Dominion is required to reflect the effect of rate regulation in its Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs are deferred as regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

Dominion evaluates whether or not recovery of its regulatory assets through future rates is probable and makes various assumptions in its analysis. The expectations of future recovery are generally based on orders issued by regulatory commissions,

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.

 

 

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In December 2013, Dominion recorded a reduction of $129 million ($47 million of which was credited to income) in the nuclear decommissioning AROs for its units due to a reduction in estimated costs.

INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2014, Dominion had $145 million of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.

Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion evaluates quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. Dominion establishes a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2014, Dominion had established $87 million of valuation allowances.

ACCOUNTING FOR DERIVATIVE CONTRACTS AND OTHER INSTRUMENTS AT FAIR VALUE

Dominion uses derivative contracts such as futures, swaps, forwards, options and FTRs to manage commodity, currency exchange and financial market risks of its business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies. The majority of investments held in Dominion’s nuclear decommissioning and rabbi and benefit plan trust funds are also subject to fair value accounting. See Notes 6 and 21 to the Consolidated Financial Statements for further information on these fair value measurements.

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker quotes and industry publications. When evaluat-

ing pricing information provided by brokers and other pricing services, Dominion considers whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if Dominion believes that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, Dominion must estimate prices based on available historical and near-term future price information and use of statistical methods, including regression analysis, that reflect its market assumptions.

Dominion maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value.

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

As of December 31, 2014, Dominion reported $3.0 billion of goodwill in its Consolidated Balance Sheet. A significant portion resulted from the acquisition of the former CNG in 2000.

In April of each year, Dominion tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2014, 2013 and 2012 annual tests and any interim tests did not result in the recognition of any goodwill impairment.

In general, Dominion estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. Fair value estimates are dependent on subjective factors such as Dominion’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present. See Note 11 to the Consolidated Financial Statements for additional information.

USE OF ESTIMATES IN LONG-LIVED ASSET IMPAIRMENT TESTING

Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived

 

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

 

 

 

assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about operating the long-lived assets and the selection of an appropriate discount rate. When determining whether an asset or asset group has been impaired, management groups assets at the lowest level that has identifiable cash flows. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. See Note 6 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets.

EMPLOYEE BENEFIT PLANS

Dominion sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit obligations, mortality rates and the anticipated rate of increase in healthcare costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between Dominion’s assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.

The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality rates are critical assumptions. Dominion determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:

Ÿ  

Expected inflation and risk-free interest rate assumptions;

Ÿ  

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

Ÿ  

Expected future risk premiums, asset volatilities and correlations;

Ÿ  

Forecasts of an independent investment advisor;

Ÿ  

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

Ÿ  

Investment allocation of plan assets. The strategic target asset allocation for Dominion’s pension funds is 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments, such as private equity investments.

Strategic investment policies are established for Dominion’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include those mentioned above such as employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns.

Dominion develops assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions. Dominion calculated its pension cost using an expected long-term rate of return on plan assets assumption of 8.75% for 2014 and 8.50% for 2013 and 2012. For 2015, the expected long-term rate of return for pension cost assumption is 8.75%. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2014 and 7.75% for 2013 and 2012. For 2015, the expected long-term rate of return for other postretirement benefit cost assumption is 8.50%. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets.

Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost ranged from 5.20% to 5.30% for pension plans and 5.00% to 5.10% for other postretirement benefit plans in 2014, ranged from 4.40% to 4.80% in 2013 and were 5.50% in 2012. Dominion selected a discount rate of 4.40% for determining both its December 31, 2014 projected pension and other postretirement benefit obligations.

Dominion establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected, and demographics of plan participants. Dominion’s healthcare cost trend rate assumption as of December 31, 2014 was 7.00% and is expected to gradually decrease to 5.00% by 2018 and continue at that rate for years thereafter.

Dominion develops its mortality assumption using plan-specific studies and projects mortality improvement using scales developed by the Society of Actuaries.

 

 

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The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed, while holding all other assumptions constant:

 

             Increase in Net Periodic Cost  
     

Change in

Actuarial

Assumption

   

Pension

Benefits

    

Other

Postretirement

Benefits

 
(millions, except percentages)                    

Discount rate

     (0.25 )%    $ 17       $ 1   

Long-term rate of return on plan assets

     (0.25 )%      15         3   

Healthcare cost trend rate

     1     N/A         26   

In addition to the effects on cost, at December 31, 2014, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $236 million and its accumulated postretirement benefit obligation by $47 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $186 million.

See Note 21 to the Consolidated Financial Statements for additional information on Dominion’s employee benefit plans.

DOMINION

 

 

RESULTS OF OPERATIONS

Presented below is a summary of Dominion’s consolidated results:

 

Year Ended
December 31,
   2014      $ Change     2013      $ Change      2012  
(millions, except EPS)                                  

Net Income attributable to Dominion

   $ 1,310       $ (387   $ 1,697       $ 1,395       $ 302   

Diluted EPS

     2.24         (0.69     2.93         2.40         0.53   

Overview

2014 VS. 2013

Net income attributable to Dominion decreased by 23% primarily due to charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, charges associated with Dominion’s Liability Management Exercise, and the repositioning of Dominion’s producer services business, which was completed in the first quarter of 2014. See Note 13 for more information on legislation related to North Anna and offshore wind facilities. See Liquidity and Capital Resources for more information on the Liability Management Exercise. These decreases were partially offset by an increase in investment tax credits received, primarily from new solar projects.

2013 VS. 2012

Net income attributable to Dominion increased by $1.4 billion primarily due to the absence of impairment and other charges recorded in 2012 related to the discontinued operations of Brayton Point and Kincaid and management’s decision to cease operations and begin decommissioning Kewaunee in 2013.

Analysis of Consolidated Operations

Presented below are selected amounts related to Dominion’s results of operations:

 

Year Ended December 31,   2014     $ Change     2013     $ Change     2012  
(millions)                              

Operating Revenue

  $ 12,436      $ (684   $ 13,120      $ 285      $ 12,835   

Electric fuel and other energy-related purchases

    3,400        (485     3,885        240        3,645   

Purchased electric capacity

    361        3        358        (29     387   

Purchased gas

    1,355        24        1,331        154        1,177   

Net Revenue

    7,320        (226     7,546        (80     7,626   

Other operations and maintenance

    2,765        306        2,459        (632     3,091   

Depreciation, depletion and amortization

    1,292        84        1,208        81        1,127   

Other taxes

    542        (21     563        13        550   

Other income

    250        (15     265        42        223   

Interest and related charges

    1,193        316        877        61        816   

Income tax expense

    452        (440     892        81        811   

Loss from discontinued operations

           92        (92     1,033        (1,125

An analysis of Dominion’s results of operations follows:

2014 VS. 2013

Net revenue decreased 3%, primarily reflecting:

Ÿ  

A $263 million decrease from retail energy marketing operations, primarily due to the sale of the retail electric business in March 2014; and

Ÿ  

A $195 million decrease primarily related to the repositioning of Dominion’s producer services business which was completed in the first quarter of 2014, reflecting the termination of natural gas trading and certain energy marketing activities.

These decreases were partially offset by:

Ÿ  

A $171 million increase from electric utility operations, primarily reflecting:

  Ÿ  

An increase from rate adjustment clauses at electric utility operations ($132 million); and

  Ÿ  

An increase in sales from electric utility operations primarily due to an increase in heating degree days ($34 million);

Ÿ  

A $46 million increase in gas transportation and storage activities and other revenues, largely due to various expansion projects being placed into service; and

Ÿ  

A $35 million increase in merchant generation margins, primarily due to higher realized prices ($120 million), partially offset by lower generation output due to the decommissioning of Kewaunee beginning in May 2013 ($95 million).

Other operations and maintenance increased 12%, primarily reflecting:

Ÿ  

$370 million in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities;

Ÿ  

A $135 million increase in planned outage costs at certain merchant generation facilities and at certain non-nuclear utility facilities; and

 

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

 

 

 

Ÿ  

A $121 million charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities.

These increases were partially offset by:

Ÿ  

A gain on the sale of Dominion’s electric retail energy marketing business in March 2014 ($100 million), net of a $31 million write-off of goodwill;

Ÿ  

A $67 million decrease primarily due to the deferral of utility nuclear outage costs beginning in the second quarter of 2014, pursuant to the Virginia legislation enacted in April 2014;

Ÿ  

The absence of a $65 million charge primarily reflecting impairment charges recorded in 2013 for certain natural gas infrastructure assets; and

Ÿ  

A decrease in bad debt expense at regulated natural gas distribution operations primarily related to low-income assistance programs ($53 million). These bad debt expenses are recovered through rates and do not impact net income.

Interest and related charges increased 36%, primarily due to charges associated with Dominion’s Liability Management Exercise in 2014 ($284 million) and higher long-term debt interest expense resulting from debt issuances in 2014 ($44 million).

Income tax expense decreased 49%, primarily reflecting lower pre-tax income ($350 million) and the impact of federal renewable energy investment tax credits ($105 million).

Loss from discontinued operations reflects the sale of Brayton Point and Kincaid in 2013.

2013 VS. 2012

Net Revenue decreased 1%, primarily reflecting:

Ÿ  

A $162 million decrease in producer services primarily related to unfavorable price changes on economic hedging positions, partially offset by higher physical margins, all associated with natural gas aggregation, marketing and trading activities;

Ÿ  

A $111 million decrease in retail energy marketing activities primarily due to the impact of lower margins on electric sales due to higher purchased power costs; and

Ÿ  

A $98 million decrease from merchant generation operations, primarily due to lower generation output ($133 million) largely due to the May 2013 closure of Kewaunee, partially offset by higher realized prices ($35 million).

These decreases were partially offset by:

Ÿ  

A $161 million increase from electric utility operations, primarily reflecting:

  Ÿ  

An increase in sales to retail customers, primarily due to an increase in heating degree days ($112 million); and

  Ÿ  

An increase from rate adjustment clauses ($92 million); partially offset by

  Ÿ  

A decrease in ancillary revenues received from PJM ($12 million) primarily due to a decrease in net operating reserve credits; and

Ÿ  

A $144 million increase from regulated natural gas transmission operations primarily related to the Appalachian Gateway Project that was placed into service in September 2012 ($44 million), an increase in gathering and storage services ($38 million), NGL activities primarily related to an increase in processing and fractionation volumes ($19 million) and the Northeast Expansion Project that was placed into service in November 2012 ($16 million).

Other operations and maintenance decreased 20%, primarily reflecting:

Ÿ  

A $589 million decrease related to Kewaunee largely due to the absence of charges recorded in 2012 following management’s decision to cease operations and begin decommissioning in 2013;

Ÿ  

A $123 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates;

Ÿ  

A $54 million decrease in storm damage and service restoration costs primarily due to the absence of damage caused by late June summer storms in 2012;

Ÿ  

A $42 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These expenses are recovered through rates and do not impact net income; and

Ÿ  

Increased gains from the sales of assets to Blue Racer ($32 million).

These decreases were partially offset by:

Ÿ  

A $65 million increase primarily related to impairment charges for certain natural gas infrastructure assets;

Ÿ  

A $46 million increase resulting from impacts of the 2013 Biennial Review Order;

Ÿ  

A $35 million increase due to the absence of adjustments recorded in 2012 in connection with the 2012 North Carolina rate case;

Ÿ  

A $34 million increase in PJM operating reserves and reactive service charges; and

Ÿ  

A $26 million charge related to the expected shutdown of certain coal-fired generating units.

Other Income increased 19%, primarily due to higher realized gains (including investment income) on nuclear decommissioning trust funds ($40 million) and a gain on the sale of Dominion’s 50% equity method investment in Elwood ($35 million), partially offset by a decrease in the equity component of AFUDC ($15 million) and a decrease in earnings from equity method investments ($11 million).

Income tax expense increased 10%, primarily reflecting higher pre-tax income in 2013 ($169 million), partially offset by an increase in renewable energy investment tax credits ($46 million) and a lower effective rate for state income taxes ($45 million).

Loss from discontinued operations reflects the sale of Brayton Point and Kincaid in 2013.

Outlook

Dominion’s strategy is to continue focusing on its regulated businesses while maintaining upside potential in well-positioned nonregulated businesses. The goals of this strategy are to provide earnings per share growth, a growing dividend and to maintain a stable credit profile. Dominion expects 80% to 90% of future earnings from its primary operating segments to come from regulated and long-term contracted businesses.

In 2015, Dominion is expected to experience an increase in net income on a per share basis as compared to 2014. Dominion’s anticipated 2015 results reflect the following significant factors:

Ÿ  

A return to normal weather in its electric utility operations;

Ÿ  

Growth in weather-normalized electric utility sales of approximately 1%, comparable to 2014 growth;

 

 

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Ÿ  

Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue;

Ÿ  

The absence of certain charges incurred in 2014, including charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, charges associated with Dominion’s Liability Management Exercise, charges related to the repositioning of Dominion’s producer services business, which was completed in the first quarter of 2014, and charges related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities;

Ÿ  

Construction and operation of growth projects in gas transmission and distribution; partially offset by

Ÿ  

An increase in depreciation, depletion, and amortization;

Ÿ  

Higher operating and maintenance expenses; and

Ÿ  

A higher effective tax rate, driven primarily by higher state income tax expense and lower investment tax credits.

Additionally, in 2015, Dominion expects to focus on meeting new and developing environmental requirements, including by making significant investments in utility solar generation, particularly in Virginia.

 

 

SEGMENT RESULTS OF OPERATIONS

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. Presented below is a summary of contributions by Dominion’s operating segments to net income attributable to Dominion:

 

Year Ended December 31,   2014     2013     2012  
    

Net

Income

attribu-

table

to
Dominion

   

Diluted

EPS

   

Net

Income

attribu-

table

to
Dominion

   

Diluted

EPS

   

Net

Income

attribu-

table

to
Dominion

   

Diluted

EPS

 
(millions, except EPS)                                    

DVP

  $ 502      $ 0.86      $ 475      $ 0.82      $ 439      $ 0.77   

Dominion Generation

    1,101        1.88        1,031        1.78        1,021        1.78   

Dominion Energy

    677        1.16        643        1.11        551        0.96   

Primary operating segments

    2,280        3.90        2,149        3.71        2,011        3.51   

Corporate and Other

    (970     (1.66     (452     (0.78     (1,709     (2.98

Consolidated

  $ 1,310      $ 2.24      $ 1,697      $ 2.93      $ 302      $ 0.53   

DVP

Presented below are operating statistics related to DVP’s operations:

 

Year Ended December 31,   2014     % Change     2013     % Change     2012  

Electricity delivered (million MWh)

    83.5        1     82.4        2     80.8   

Degree days:

         

Cooling

    1,638               1,645        (8     1,787   

Heating

    3,793        4        3,651        24        2,955   

Average electric distribution customer accounts (thousands)(1)

    2,500        1        2,475        1        2,455   

 

(1) Period average.

Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:

2014 VS. 2013

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Regulated electric sales:

    

Weather

   $ 8      $ 0.01   

Other

     (1       

FERC transmission equity return

     27        0.04   

Storm damage and service restoration

     13        0.02   

Depreciation

     (8     (0.01

Other

     (12     (0.02

Change in net income contribution

   $ 27      $ 0.04   

2013 VS. 2012

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Regulated electric sales:

    

Weather

   $ 24      $ 0.04   

Other

     (2       

FERC transmission equity return

     30        0.05   

Storm damage and service restoration(1)

     (20     (0.03

Depreciation

     (7     (0.01

Other operations and maintenance expense

     7        0.01   

Other

     4        0.01   

Share dilution

            (0.02

Change in net income contribution

   $ 36      $ 0.05   

 

(1) Excludes restoration costs associated with damage caused by severe storms in 2012, which are reflected in the Corporate and Other segment.

Dominion Generation

Presented below are operating statistics related to Dominion Generation’s operations:

 

Year Ended December 31,   2014     % Change     2013     % Change     2012  

Electricity supplied
(million MWh):

         

Utility

    83.9        1     82.8        2     80.9   

Merchant(1)

    25.0        (6     26.6        (5     28.0   

Degree days (electric
utility service area):

         

Cooling

    1,638               1,645        (8     1,787   

Heating

    3,793        4        3,651        24        2,955   

Average retail energy marketing customer accounts (thousands)(2)

    1,283 (3)      (39     2,119               2,129   

 

(1) Excludes 7.6 million and 12.8 million MWh for 2013 and 2012, respectively, related to Kewaunee, Brayton Point, Kincaid, State Line, Salem and Dominion’s equity method investment in Elwood. There are no exclusions related to these stations in 2014.
(2) Period average.
(3) Excludes 511 thousand average retail electric energy marketing customer accounts due to the sale of this business in March 2014.
 

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

 

 

 

Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:

2014 VS. 2013

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Merchant generation margin

   $ 64      $ 0.11   

Regulated electric sales:

    

Weather

     13        0.02   

Other

     (7     (0.01

Retail energy marketing operations(1)

     (20     (0.04

Rate adjustment clause equity return

     (8     (0.01

PJM ancillary services

     24        0.04   

Renewable energy investment tax credits

     97        0.17   

Outage costs

     (40     (0.07

AFUDC equity return

     (17     (0.04

Salaries and benefits

     (11     (0.03

Other

     (25     (0.04

Change in net income contribution

   $ 70      $ 0.10   

 

(1) Excludes earnings from Retail electric energy marketing, which was sold in March 2014.

2013 VS. 2012

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Merchant generation margin

   $ (14   $ (0.02

Regulated electric sales:

    

Weather

     44        0.08   

Other

     (4     (0.01

Retail energy marketing operations

     (54     (0.09

Rate adjustment clause equity return

     35        0.06   

PJM ancillary services

     (26     (0.05

Renewable energy investment tax credits

     40        0.07   

Outage costs

     10        0.02   

Other

     (21     (0.04

Share dilution

            (0.02

Change in net income contribution

   $ 10      $   

Dominion Energy

Presented below are selected operating statistics related to Dominion Energy’s operations.

 

Year Ended December 31,   2014     % Change     2013     % Change     2012  

Gas distribution throughput (bcf):

         

Sales

    32        10     29        12     26   

Transportation

    353        26        281        8        259   

Heating degree days

    6,330        8        5,875        18        4,986   

Average gas distribution customer accounts (thousands)(1):

         

Sales

    244        (1     246        (2     251   

Transportation

    1,052               1,049               1,044   

 

(1) Period average.

Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:

2014 VS. 2013

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Gas distribution margin:

    

Weather

   $ 4      $ 0.01   

Rate adjustment clauses

     15        0.02   

Other

     5        0.01   

Assignments of Marcellus acreage

     31        0.05   

Depreciation

     (8     (0.01

Blue Racer(1)

     (1       

Other

     (12     (0.03

Change in net income contribution

   $ 34      $ 0.05   

 

(1) Includes a $24 million decrease in gains from the sale of assets.

2013 VS. 2012

 

      Increase (Decrease)  
      Amount     EPS  
(millions, except EPS)             

Weather

   $ 8      $ 0.01   

Producer services margin(1)

     (37     (0.06

Gas transmission margin(2)

     88        0.15   

Blue Racer(3)

     17        0.03   

Assignment of Marcellus acreage

     12        0.02   

Other

     4        0.01   

Share dilution

            (0.01

Change in net income contribution

   $ 92      $ 0.15   

 

(1) Excludes charges incurred in 2013 associated with the ongoing exit of natural gas trading and certain energy marketing activities which are reflected in the Corporate and Other segment.
(2) Primarily reflects a full year of the Appalachian Gateway Project in service.
(3) Includes a $15 million increase in gains from the sale of assets.

Corporate and Other

Presented below are the Corporate and Other segment’s after-tax results:

 

Year Ended December 31,    2014     2013     2012  
(millions, except EPS amounts)                   

Specific items attributable to operating segments

   $ (544   $ (184   $ (1,467

Specific items attributable to Corporate and Other segment

     (149            (5

Total specific items

     (693     (184     (1,472

Other corporate operations

     (277     (268     (237

Total net expense

   $ (970   $ (452   $ (1,709

EPS impact

   $ (1.66   $ (0.78   $ (2.98

TOTAL SPECIFIC ITEMS

Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing those segments’ performance or allocating resources among the segments. See Note 25 to the Consolidated Financial Statements for discussion of these items in more detail. Corporate and other also includes specific items attributable to the Corporate and Other segment. In 2014, this primarily includes $174 million in after-tax charges associated with Dominion’s Liability Management Exercise.

 

 

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VIRGINIA POWER

 

 

RESULTS OF OPERATIONS

Presented below is a summary of Virginia Power’s consolidated results:

 

Year Ended December 31,    2014      $ Change     2013      $ Change      2012  
(millions)                                  

Net Income

   $ 858       $ (280   $ 1,138       $ 88       $ 1,050   

Overview

2014 VS. 2013

Net income decreased by 25% primarily due to charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities.

2013 VS. 2012

Net income increased by 8% primarily due to an increase in rate adjustment clause revenue, the impact of more favorable weather on utility operations, and the absence of restoration costs associated with damage caused by late June 2012 summer storms.

Analysis of Consolidated Operations

Presented below are selected amounts related to Virginia Power’s results of operations:

 

Year Ended December 31,   2014     $ Change     2013     $ Change     2012  
(millions)                              

Operating Revenue

  $ 7,579      $ 284      $ 7,295      $ 69      $ 7,226   

Electric fuel and other energy-related purchases

    2,406        102        2,304        (64     2,368   

Purchased electric capacity

    360        2        358        (28     386   

Net Revenue

    4,813        180        4,633        161        4,472   

Other operations and maintenance

    1,916        465        1,451        (15     1,466   

Depreciation and amortization

    915        62        853        71        782   

Other taxes

    258        9        249        17        232   

Other income

    93        7        86        (10     96   

Interest and related charges

    411        42        369        (16     385   

Income tax expense

    548        (111     659        6        653   

An analysis of Virginia Power’s results of operations follows:

2014 VS. 2013

Other operations and maintenance increased 32%, primarily reflecting:

Ÿ  

$370 million in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities; and

Ÿ  

A $121 million charge related to a settlement offer to incur future ash pond closure costs at certain generation facilities.

Interest and related charges increased 11%, primarily due to higher long-term debt interest expense resulting from debt issuances in August 2013 and February 2014.

Income tax expense decreased 17%, primarily reflecting lower pre-tax income.

2013 VS. 2012

Net Revenue increased 4%, primarily reflecting:

Ÿ  

An increase in sales to retail customers, primarily due to an increase in heating degree days ($112 million); and

Ÿ  

An increase from rate adjustment clauses ($92 million); partially offset by

Ÿ  

A decrease in ancillary revenues received from PJM ($12 million) primarily due to a decrease in net operating reserve credits.

Other operations and maintenance decreased 1%, primarily reflecting:

Ÿ  

A $123 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates; and

Ÿ  

A $54 million decrease in storm damage and service restoration costs primarily due to the absence of damage caused by late June summer storms in 2012.

These decreases were partially offset by:

Ÿ  

A $46 million increase resulting from impacts of the 2013 Biennial Review Order;

Ÿ  

A $35 million increase due to the absence of adjustments recorded in 2012 in connection with the 2012 North Carolina rate case;

Ÿ  

A $34 million increase in PJM operating reserves and reactive service charges;

Ÿ  

A $26 million charge related to the expected shutdown of certain coal-fired generating units; and

Ÿ  

A $22 million increase in salaries, wages and benefits.

DOMINION GAS

 

 

RESULTS OF OPERATIONS

Presented below is a summary of Dominion Gas’ consolidated results:

 

Year Ended December 31,   2014     $ Change     2013     $ Change     2012  
(millions)                              

Net Income

  $ 512      $ 51      $ 461      $ 2      $ 459   

Overview

2014 VS. 2013

Net income increased by 11% primarily due to the absence of impairment charges for certain natural gas infrastructure assets and increased gains due to assignments of Marcellus acreage, partially offset by decreased gains on sales of assets to related parties.

2013 VS. 2012

Net income increased $2 million due to increased revenue from operations, primarily reflecting the Appalachian Gateway Project and the Northeast Expansion Project being placed into service, partially offset by decreased gains on sales of assets and impairment charges related to certain natural gas infrastructure assets.

 

 

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Table of Contents

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

 

 

 

Analysis of Consolidated Operations

Presented below are selected amounts related to Dominion Gas’ results of operations:

 

Year Ended December 31,    2014      $ Change     2013      $ Change     2012  
(millions)                                 

Operating Revenue

   $ 1,898       $ (39   $ 1,937       $ 260      $ 1,677   

Purchased gas

     315         (8     323         88        235   

Other energy-related purchases

     40         (53     93         52        41   

Net Revenue

     1,543         22        1,521         120        1,401   

Other operations and maintenance

     338         (85     423         88        335   

Depreciation and amortization

     197         9        188         12        176   

Other taxes

     157         9        148         8        140   

Other income

     22         (6     28         (9     37   

Interest and related charges

     27         (1     28         (12     40   

Income tax expense

     334         33        301         13        288   

An analysis of Dominion Gas’ results of operations follows:

2014 VS. 2013

Other operations and maintenance decreased 20%, primarily reflecting:

Ÿ  

The absence of impairment charges related to certain natural gas infrastructure assets ($55 million);

Ÿ  

A decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs ($53 million). These bad debt expenses are recovered through rates and do not impact net income; and

Ÿ  

An increase in gains associated with assignments of Marcellus acreage ($42 million); partially offset by

Ÿ  

Decreased gains on the sale of assets to related parties ($43 million).

Income tax expense increased 11% primarily reflecting higher pre-tax income.

2013 VS. 2012

Net Revenue increased 9%, primarily reflecting:

Ÿ  

An increase in gas transmission transportation revenue primarily due to the Appalachian Gateway Project being placed into service in September 2012 ($64 million) and the Northeast Expansion Project that was placed into service in November 2012 ($16 million);

Ÿ  

An increase in gathering and storage services ($32 million);

Ÿ  

An increase in sales to gas distribution customers primarily due to an increase in heating degree days and other revenues ($18 million); and

Ÿ  

an increase in AMR and PIR program revenues ($16 million).

These increases were partially offset by:

Ÿ  

A decrease in rider revenue primarily related to bad debt expense ($42 million) related to low income assistance programs.

Other operations and maintenance increased 26%, primarily reflecting:

Ÿ  

Decreased gains on the sales of pipeline systems ($72 million); and

Ÿ  

Impairment charges related to certain natural gas infrastructure assets ($55 million).

These decreases were partially offset by:

Ÿ  

A $42 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and not impact net income; and

Ÿ  

An $18 million gain from agreements to convey Marcellus Shale development rights underneath several natural gas storage fields.

Other income decreased 24%, primarily due to a decrease in the equity component of AFUDC due to significant projects being placed into service in the second half of 2012.

Interest and related charges decreased 30%, primarily due to lower interest on affiliated long-term debt resulting from lower outstanding debt due to the extinguishment of intercompany borrowings through the sale of two pipelines to an affiliate in December 2012 and the acquisition of intercompany borrowings from debt issued to third parties in October 2013 ($18 million), partially offset by a decrease in the debt component of AFUDC ($7 million) due to significant projects being placed into service in the second half of 2012.

 

 

LIQUIDITY AND CAPITAL RESOURCES

Dominion depends on both internal and external sources of liquidity to provide working capital and as a bridge to long-term debt financings. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.

At December 31, 2014, Dominion had $1.7 billion of unused capacity under its credit facilities. See additional discussion below under Credit Facilities and Short-Term Debt.

A summary of Dominion’s cash flows is presented below:

 

Year Ended December 31,    2014     2013     2012  
(millions)                   

Cash and cash equivalents at beginning of year

   $ 316      $ 248      $ 102   

Cash flows provided by (used in):

      

Operating activities

     3,439        3,433        4,137   

Investing activities

     (5,181     (3,458     (3,840

Financing activities

     1,744