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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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        93        (151

Net increase in cash and cash equivalents

     2        68        146   

Cash and cash equivalents at end of year

   $ 318      $ 316      $ 248   
 

 

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Operating Cash Flows

Net cash provided by Dominion’s operating activities did not change significantly for 2014.

Dominion believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In 2015, Dominion’s Board of Directors updated the dividend policy it set in December 2012 to a target payout ratio of 70-75%, and established an annual dividend rate for 2015 of $2.59 per share of common stock, an 8% increase over the 2014 rate. In January 2015, Dominion’s Board of Directors declared dividends payable March 20, 2015 of 64.75 cents per share of common stock. Declarations of dividends are subject to further Board of Directors approval.

Dominion’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, and which are discussed in Item 1A. Risk Factors.

CREDIT RISK

Dominion’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion’s credit exposure as of December 31, 2014 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

 

      Gross
Credit
Exposure
     Credit
Collateral
     Net
Credit
Exposure
 
(millions)                     

Investment grade(1)

   $ 189       $ 114       $ 75   

Non-investment grade(2)

     1                 1   

No external ratings:

        

Internally rated-investment grade(3)

     7                 7   

Internally rated-non-investment grade(4)

     31                 31   

Total

   $ 228       $ 114       $ 114   

 

(1) Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 47% of the total net credit exposure.
(2) The five largest counterparty exposures, combined, for this category represented approximately 1% of the total net credit exposure.
(3) The five largest counterparty exposures, combined, for this category represented approximately 6% of the total net credit exposure.
(4) The five largest counterparty exposures, combined, for this category represented approximately 20% of the total net credit exposure.

Investing Cash Flows

In 2014, net cash used in Dominion’s investing activities increased by $1.7 billion, primarily due to higher capital expenditures and lower proceeds from sales of assets and businesses.

Financing Cash Flows and Liquidity

Dominion relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed in Credit Ratings, Dominion’s ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

Dominion currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows Dominion to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.

In 2014, net cash provided by Dominion’s financing activities increased by $1.7 billion, primarily reflecting higher net debt issuances, proceeds from Dominion Midstream’s initial public offering and the absence of the acquisition of the Juniper non-controlling interest recorded in 2013 related to Fairless.

LIABILITY MANAGEMENT

During 2014, Dominion elected to redeem certain debt and preferred securities prior to their stated maturities. Proceeds from the issuance of lower-cost senior and enhanced junior subordinated notes were used to fund the redemption payments. See Note 17 to the Consolidated Financial Statements for descriptions of these redemptions.

From time to time, Dominion may reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity and repurchases in the open market, in privately negotiated transactions, through tender offers or otherwise.

CREDIT FACILITIES AND SHORT-TERM DEBT

Dominion uses short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.

In connection with commodity hedging activities, Dominion is required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, Dominion may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, Dominion may vary the form of collateral provided to counterparties after weighing the costs and benefits of various factors associated with the different forms of collateral. These factors include short-term borrowing and short-term investment rates, the spread over these short-term rates at which Dominion can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives.

 

 

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

 

 

 

Dominion’s commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:

 

December 31, 2014   

Facility

Limit

    

Outstanding

Commercial

Paper

   

Outstanding

Letters of

Credit

    

Facility

Capacity

Available

 
(millions)                           

Joint revolving credit facility(1)

   $ 4,000       $ 2,664      $       $ 1,336   

Joint revolving credit facility(2)

     500         111        48         341   

Total

   $ 4,500       $ 2,775 (3)    $ 48       $ 1,677   

 

(1) In May 2014, this credit facility was amended and restated. The facility limit was increased from $3 billion to $4 billion and the maturity date was extended from September 2018 to April 2019. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.
(2) In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.
(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were 0.38% and 0.33% at December 31, 2014 and 2013, respectively.

SHORT-TERM NOTES

In November 2013, Dominion issued $400 million of private placement short-term notes that matured and were repaid in November 2014 and bore interest at a variable rate. The proceeds were used for general corporate purposes.

In November 2014, Dominion issued $400 million of private placement short-term notes that mature in November 2015 and bear interest at a variable rate. The proceeds were used for general corporate purposes.

LONG-TERM DEBT

During 2014, Dominion issued the following long-term debt:

 

Type    Principal      Rate     Maturity  
     (millions)               

Senior notes

   $ 400         1.25     2017   

Senior notes

     700         2.50     2019   

Senior notes

     450         2.50     2019   

Senior notes

     350         3.45     2024   

Senior notes

     450         3.60     2024   

Senior notes

     500         3.63     2024   

Senior notes

     600         4.45     2044   

Senior notes

     500         4.60     2044   

Senior notes

     450         4.70     2044   

Enhanced junior subordinated notes

     685         5.75     2054   

Remarketable subordinated notes

     1,000         1.50     2020   

Total notes issued

   $ 6,085                    

During 2014, Dominion repaid and repurchased $4 billion of long-term debt, including redemption premiums.

ISSUANCE OF COMMON STOCK AND OTHER EQUITY SECURITIES

Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2014, Dominion began purchasing its common stock on the open market for these plans. In April 2014, Dominion began issuing new common shares for these direct stock purchase plans.

During 2014, Dominion issued approximately 3.8 million shares of common stock totaling $273 million through employee savings plans, direct stock purchase and dividend reinvestment plans, converted securities and other employee and director benefit plans. Dominion received cash proceeds of $205 million from the issuance of 2.9 million of such shares through Dominion Direct and employee savings plans.

In December 2014, Dominion filed an SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at-the-market program. See Note 19 to the Consolidated Financial Statements for a description of the at-the-market program.

In June 2013 and July 2014, Dominion issued equity units, initially in the form of Corporate Units. Each Corporate Unit consists of a stock purchase contract and 1/20 interest in a RSN issued by Dominion. The stock purchase contracts obligate the holders to purchase shares of Dominion common stock at a future settlement date. See Note 17 to the Consolidated Financial Statements for a description of common stock to be issued by Dominion.

REPURCHASE OF COMMON STOCK

Dominion did not repurchase any shares in 2014 and does not plan to repurchase shares during 2015, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not count against its stock repurchase authorization.

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Dominion believes that its current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion may affect its ability to access these funding sources or cause an increase in the return required by investors. Dominion’s credit ratings affect its liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which it is able to offer its debt securities.

Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for Dominion are affected by its financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.

 

 

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In November 2014, Standard & Poor’s changed Dominion’s rating outlook to negative from stable. Dominion cannot predict the potential impact the negative outlook at Standard & Poor’s could have on its cost of borrowing. Credit ratings as of February 23, 2015 follow:

 

      Fitch      Moody’s      Standard
& Poor’s
 

Senior unsecured debt securities

     BBB+         Baa2         BBB+   

Junior subordinated debt securities

     BBB-         Baa3         BBB   

Enhanced junior subordinated notes

     BBB-         Baa3         BBB   

Commercial paper

     F2         P-2         A-2   

As of February 23, 2015, Fitch and Moody’s maintained a stable outlook for their respective ratings of Dominion and Standard & Poor’s maintained a negative outlook for its respective ratings of Dominion.

A downgrade in an individual company’s credit rating would not necessarily restrict its ability to raise short-term and long-term financing as long as its credit rating remains investment grade, but it could result in an increase in the cost of borrowing. Dominion works closely with Fitch, Moody’s and Standard & Poor’s with the objective of achieving its targeted credit ratings. Dominion may find it necessary to modify its business plan to maintain or achieve appropriate credit ratings and such changes may adversely affect growth and EPS.

Debt Covenants

As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion must enter into enabling agreements. These agreements contain covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion.

Some of the typical covenants include:

Ÿ  

The timely payment of principal and interest;

Ÿ  

Information requirements, including submitting financial reports filed with the SEC and information about changes in Dominion’s credit ratings to lenders;

Ÿ  

Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation, and restrictions on disposition of all or substantially all assets;

Ÿ  

Compliance with collateral minimums or requirements related to mortgage bonds; and

Ÿ  

Limitations on liens.

Dominion is required to pay annual commitment fees to maintain its credit facilities. In addition, Dominion’s credit agreements contain various terms and conditions that could affect its ability to borrow under these facilities. They include maximum debt to total capital ratios and cross-default provisions.

As of December 31, 2014, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:

 

Company    Maximum Allowed Ratio     Actual  Ratio(1)  

Dominion

     65     59

 

(1) Indebtedness as defined by the bank agreements excludes junior subordinated and remarketable subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets.

If Dominion or any of its material subsidiaries fails to make payment on various debt obligations in excess of $100 million, the lenders could require that company to accelerate its repayment of any outstanding borrowings under the credit facilities and the lenders could terminate their commitment to lend funds to that company. Accordingly, any default by Virginia Power or Dominion Gas under the joint credit facilities with Dominion would affect the lender’s commitment to Dominion.

Dominion executed RCCs in connection with its issuance of the following hybrid securities:

Ÿ  

June 2006 hybrids;

Ÿ  

September 2006 hybrids; and

Ÿ  

June 2009 hybrids.

In October 2014, Dominion redeemed all of the June 2009 hybrids. The redemption was conducted in compliance with the RCC. See Note 17 to the Consolidated Financial Statements for additional information, including terms of the RCCs.

At December 31, 2014, the termination dates and covered debt under the RCCs associated with Dominion’s hybrids were as follows:

 

Hybrid   

RCC

Termination

Date

    

Designated Covered Debt

Under RCC

 

June 2006 hybrids

     6/30/2036         September 2006 hybrids   

September 2006 hybrids

     9/30/2036         June 2006 hybrids   

Dominion monitors these debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2014, there have been no events of default under or changes to Dominion’s debt covenants.

Dividend Restrictions

Certain agreements associated with Dominion’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s ability to pay dividends or receive dividends from its subsidiaries at December 31, 2014.

See Note 17 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes and equity units, initially in the form of corporate units, which information is incorporated herein by reference.

 

 

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

 

 

 

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

CONTRACTUAL OBLIGATIONS

Dominion is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion is a party as of December 31, 2014. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in the Consolidated Balance Sheets, other than current maturities of long-term debt, interest payable and certain derivative instruments. The majority of Dominion’s current liabilities will be paid in cash in 2015.

 

     2015    

2016-

2017

   

2018-

2019

   

2020 and

thereafter

    Total  
(millions)                              

Long-term debt(1)

  $ 861      $ 2,756      $ 3,900      $ 15,683      $ 23,200   

Interest payments(2)

    1,081        1,914        1,603        13,147        17,745   

Leases(3)

    63        106        79        79        327   

Purchase obligations(4):

         

Purchased electric capacity for utility operations

    313        408        169        99        989   

Fuel commitments for utility operations

    769        825        488        2,052        4,134   

Fuel commitments for nonregulated operations

    148        105        105        117        475   

Pipeline transportation and storage

    176        278        244        750        1,448   

Energy commodity purchases for resale(5)

    24        2                      26   

Other(6)

    1,021        79        24        13        1,137   

Other long-term liabilities(7):

         

Financial derivative-commodities(5)

    18        14                      32   

Other contractual obligations(8)

    98        201        109        19        427   

Total cash payments

  $ 4,572      $ 6,688      $ 6,721      $ 31,959      $ 49,940   

 

(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders. At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015. As a result, at December 31, 2014, the notes were included in Securities due within one year in the Consolidated Balance Sheets.
(2) Includes interest payments over the terms of the debt and payments on related stock purchase contracts. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2014 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 17 to the Consolidated Financial Statements. Does not reflect Dominion’s ability to defer interest and stock purchase contract payments on junior subordinated notes or RSNs and equity units, initially in the form of Corporate Units.
(3) Primarily consists of operating leases.
(4) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.
(5) Represents the summation of net losses, by contracts, due from Dominion if all physical or financial transactions among its counterparties and Dominion were liquidated and terminated.
(6) Includes capital, operations, and maintenance commitments.
(7) Excludes regulatory liabilities, AROs and employee benefit plan obligations, which are not contractually fixed as to timing and amount. See Notes 12, 14 and 21 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $79 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 5 to the Consolidated Financial Statements.
(8) Includes interest rate swap agreements.

PLANNED CAPITAL EXPENDITURES

Dominion’s planned capital expenditures are expected to total approximately $5.8 billion, $5.6 billion and $4.6 billion in 2015, 2016 and 2017, respectively. Dominion’s expenditures are expected to include construction and expansion of electric generation and natural gas transmission and storage facilities, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel and the construction of the Liquefaction Project and Dominion’s portion of the Atlantic Coast Pipeline project.

Dominion expects to fund its capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the Board of Directors.

See DVP, Dominion Generation and Dominion Energy-Properties in Item 1. Business for a discussion of Dominion’s expansion plans.

These estimates are based on a capital expenditures plan reviewed and endorsed by Dominion’s Board of Directors in late 2014 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.

Use of Off-Balance Sheet Arrangements

GUARANTEES

Dominion primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others. See Note 22 to the Consolidated Financial Statements for additional information, which information is incorporated herein by reference.

FUTURE ISSUES AND OTHER MATTERS

See Item 1. Business and Notes 13 and 22 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other matters that may impact future results of operations, financial condition, and/or cash flows.

 

 

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Environmental Matters

Dominion is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES

Dominion incurred approximately $192 million, $182 million and $189 million of expenses (including depreciation) during 2014, 2013, and 2012 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $193 million and $188 million in 2015 and 2016, respectively. In addition, capital expenditures related to environmental controls were $101 million, $64 million, and $213 million for 2014, 2013 and 2012, respectively. These expenditures are expected to be approximately $97 million and $60 million for 2015 and 2016, respectively.

FUTURE ENVIRONMENTAL REGULATIONS

Air

The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, delegated states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements.

In December 2012, the EPA issued a final rule that set a more stringent annual air quality standard for fine particulate matter. The EPA issued final attainment/nonattainment designations in January 2015. Until states develop their implementation plans, Dominion cannot determine whether or how facilities located in areas designated nonattainment for the standard will be impacted, but does not expect such impacts to be material.

The EPA has finalized rules establishing a new 1-hour NAAQS for NO2 and a new 1-hour NAAQS for SO2, which could require additional NOX and SO2 controls in certain areas where Dominion operates. Until the states have developed implementation plans for these standards, the impact on Dominion’s facilities that emit NOX and SO2 is uncertain. Additionally, the impact of permit limits for implementing NAAQS on Dominion’s facilities is uncertain at this time.

In January 2010, the EPA also proposed a new, more stringent NAAQS for ozone and had planned to finalize the rule in 2011. In September 2011, the EPA announced a delay from 2011 to 2014 of the rulemaking. In November 2014, the EPA issued a new proposal to tighten the ozone standard and expects to finalize the rule in October 2015. The EPA is not expected to complete attainment designations for a new standard until 2017 and states will have until 2020 to develop plans to address the new standard. Until the states have developed implementation plans, Dominion is unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significant expenditures are required to implement additional controls, it could adversely affect Dominion’s results of operations and cash flows.

In June 2005, the EPA finalized amendments to the Regional Haze Rule, also known as the Clean Air Visibility Rule. The rule requires the states to implement best available retrofit technology requirements for sources to address impacts to visual air quality through regional haze state implementation plans, but allows other alternative options. Dominion anticipates that the emission reductions achieved through compliance with other CAA-required programs will generally address this rule.

The Clear 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. The proposal would require states to meet state-by-state emission rate or intensity-based CO2 binding goals or limits. The EPA is expected to finalize the guidelines by summer 2015. States will then be required to submit plans to the EPA by summer 2016 identifying how they will comply with the rule, with possible one- or two-year extensions. Dominion’s most recent integrated resources plan filed in August 2014 included an alternative scenario benchmarked on the proposed EPA rule, as a plausible compliance strategy, that includes additional coal unit retirements and additional low or zero-carbon resources. However, until the state plans are developed and the EPA approves the plans, Dominion cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.

In June 2014, the EPA published proposed performance standards to address CO2 emissions from modified and reconstructed electric generating units. The proposed standards would only apply to coal- and natural-gas fired boilers and natural gas-fired combined cycle units, constructed for the purpose of supplying more than one-third of their potential output to the grid and which are designed to sell approximately 25 MW, that meet certain, specific conditions described in the CAA for being modified or reconstructed. Modifications undertaken for the primary purpose of installing pollution control technology will not be subject to the proposed standards. Dominion currently cannot predict with certainty the direct or indirect financial impact on operations from these rule revisions, but believes the expenditures to comply with any new requirements could be material.

In January 2015, the EPA announced plans to reduce methane emissions from natural gas processing and transmission sources as part of its Climate Action Plan. The plan would impose regulations to reduce methane from new sources, including compressor stations and is expected to be proposed in summer 2015 and finalized in 2016. The EPA will develop control technology guidelines to reduce emissions of volatile organic compounds from existing sources in ozone nonattainment areas in the northeast Ozone Transport Region. Until these regulations and guidelines are finalized, Dominion is unable to predict future requirements or estimate compliance costs.

 

 

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

 

 

 

Water

The CWA is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. Dominion must comply with applicable aspects of the CWA programs at its operating facilities.

In June 2013, the EPA issued a proposed rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The proposed rule establishes updated standards for wastewater discharges at coal, oil, gas, and nuclear steam generating stations. Affected facilities could be required to convert from wet to dry coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. The EPA is subject to a consent decree requiring that it take final action on the proposed rule by September 30, 2015. Dominion currently cannot predict with certainty the direct or indirect financial impact on operations from these rule revisions, but believes the expenditures to comply with any new requirements could be material.

Climate Change Legislation and Regulation

Some regions and states in which Dominion operates have already adopted or may adopt GHG emission reduction programs. Any of these new or contemplated regulations may affect capital costs, or create significant permitting delays, for new or modified facilities that emit GHGs.

Dodd-Frank Act

The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The CEA, as amended by Title VII of the Dodd- Frank Act, requires certain over-the counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, may elect the end-user exception to the CEA’s clearing requirements. Dominion has elected to exempt its swaps from the CEA’s clearing requirements. The CFTC may continue to adopt final rules and implement provisions of the Dodd-Frank Act through its ongoing rulemaking process, including rules regarding margin requirements for non-cleared swaps. If, as a result of the rulemaking process, Dominion’s derivative activities are not exempted from clearing, exchange trading or margin requirements, it could be subject to higher costs due to decreased market liquidity or increased margin payments. In addition, Dominion’s swap dealer counterparties may attempt to pass-through additional trading costs in connection with the implementation of, and compliance with, Title VII of the Dodd-Frank Act. Due to the ongoing rulemaking process, Dominion is currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on its financial condition, results of operations or cash flows.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs

and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact the Companies.

 

 

MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT

The Companies’ financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in Dominion’s and Virginia Power’s electric operations and Dominion’s and Dominion Gas’ natural gas procurement and marketing operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt and future issuances of debt. In addition, the Companies are exposed to investment price risk through various portfolios of equity and debt securities.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% unfavorable change in commodity prices or interest rates.

Commodity Price Risk

To manage price risk, Dominion and Virginia Power primarily hold commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products and Dominion Gas primarily holds commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of natural gas and other energy-related products.

The repositioning of Dominion’s producer services business was completed in the first quarter of 2014. This, combined with Dominion’s sale of its electric retail energy marketing business, has reduced Dominion’s commodity price risk exposure.

The derivatives used to manage commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based financial derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on observable market prices.

A hypothetical 10% unfavorable change in commodity prices of Dominion’s commodity-based financial derivative instruments would have resulted in an increase in fair value of approximately $101 million and $171 million as of December 31, 2014 and 2013, respectively. The decline in sensitivity is largely due to decreased commodity derivative activity and lower commodity prices.

A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of Virginia Power’s commodity-based financial derivatives as of December 31, 2014 or 2013.

A hypothetical 10% unfavorable change in commodity prices of Dominion Gas’ commodity-based financial derivative instru-

 

 

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ments would have resulted in an increase in fair value of approximately $2 million and a decrease in fair value of $14 million as of December 31, 2014 and 2013, respectively. The decline in sensitivity is largely due to decreased commodity derivative activity.

The impact of a change in energy commodity prices on the Companies’ commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.

Interest Rate Risk

The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt and interest rate swaps designated under fair value hedging and outstanding for the Companies, a hypothetical 10% increase in market interest rates would not have resulted in a material change in annual earnings at December 31, 2014 or 2013.

The Companies may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. As of December 31, 2014, Dominion, Virginia Power and Dominion Gas had $4.1 billion, $1.5 billion and $250 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $46 million, $25 million and $2 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2014. As of December 31, 2013, Dominion, Virginia Power and Dominion Gas had $1.1 billion, $600 million and $450 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $20 million, $13 million and $8 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2013.

The impact of a change in interest rates on the Companies’ interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.

Investment Price Risk

Dominion and Virginia Power are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value.

Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $176 million and $163 million in 2014 and 2013, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2014 and 2013, Dominion recorded, in AOCI and

regulatory liabilities, a net increase in unrealized gains on these investments of $172 million and $417 million, respectively.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $77 million and $52 million in 2014 and 2013, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2014 and 2013, Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $87 million and $193 million, respectively.

Dominion sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power and Dominion Gas employees participate in these plans. Aggregate actual returns for Dominion’s pension and other postretirement plan assets were $706 million in 2014 and $959 million in 2013, versus expected returns of $610 million and $554 million, respectively. Aggregate actual returns for pension and other postretirement benefit plan assets for Dominion Gas employees represented by collective bargaining units were $157 million in 2014 and $214 million in 2013, versus expected returns of $138 million and $125 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion’s plan assets would result in an increase in net periodic cost of approximately $15 million and $14 million as of December 31, 2014 and 2013, respectively, for pension benefits and $3 million as of December 31, 2014 and 2013, for other postretirement benefits. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Gas’ plan assets, for employees represented by collective bargaining units, would result in an increase in net periodic cost of approximately $4 million and $3 million as of December 31, 2014 and 2013, respectively, for pension benefits and $1 million as of both December 31, 2014 and 2013, for other postretirement benefits.

Risk Management Policies

The Companies have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies of all subsidiaries, including Virginia Power and Dominion Gas. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and the Companies’ December 31, 2014 provision for credit losses, management believes that it is unlikely that a material adverse effect on the Companies’ financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

 

 

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Item 8. Financial Statements and Supplementary Data

 

 

 

      Page Number  

Dominion Resources, Inc.

  

Report of Independent Registered Public Accounting Firm

     57   

Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012

     58   

Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012

     59   

Consolidated Balance Sheets at December 31, 2014 and 2013

     60   

Consolidated Statements of Equity at December 31, 2014, 2013 and 2012 and for the years then ended

     62   

Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012

     63   

Virginia Electric and Power Company

  

Report of Independent Registered Public Accounting Firm

     64   

Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012

     65   

Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012

     66   

Consolidated Balance Sheets at December 31, 2014 and 2013

     67   

Consolidated Statements of Common Shareholder’s Equity at December  31, 2014, 2013 and 2012 and for the years then ended

     69   

Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012

     70   

Dominion Gas Holdings, LLC

  

Report of Independent Registered Public Accounting Firm

     71   

Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012

     72   

Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012

     73   

Consolidated Balance Sheets at December 31, 2014 and 2013

     74   

Consolidated Statements of Equity at December 31, 2014, 2013 and 2012 and for the years then ended

     76   

Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012

     77   

Combined Notes to Consolidated Financial Statements

     78   

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

 

To the Board of Directors and Shareholders of

Dominion Resources, Inc.

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of Dominion’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Resources, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Dominion’s internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2015 expressed an unqualified opinion on Dominion’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2015

 

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Dominion Resources, Inc.

Consolidated Statements of Income

 

 

 

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

Operating Revenue

   $ 12,436       $ 13,120      $ 12,835   

Operating Expenses

       

Electric fuel and other energy-related purchases

     3,400         3,885        3,645   

Purchased electric capacity

     361         358        387   

Purchased gas

     1,355         1,331        1,177   

Other operations and maintenance

     2,765         2,459        3,091   

Depreciation, depletion and amortization

     1,292         1,208        1,127   

Other taxes

     542         563        550   

Total operating expenses

     9,715         9,804        9,977   

Income from operations

     2,721         3,316        2,858   

Other income

     250         265        223   

Interest and related charges

     1,193         877        816   

Income from continuing operations including noncontrolling interests before income taxes

     1,778         2,704        2,265   

Income tax expense

     452         892        811   

Income from continuing operations including noncontrolling interests

     1,326         1,812        1,454   

Loss from discontinued operations(1)

             (92     (1,125

Net income including noncontrolling interests

     1,326         1,720        329   

Noncontrolling interests

     16         23        27   

Net income attributable to Dominion

     1,310         1,697        302   

Amounts attributable to Dominion:

       

Income from continuing operations, net of tax

     1,310         1,789        1,427   

Loss from discontinued operations, net of tax

             (92     (1,125

Net income attributable to Dominion

     1,310         1,697        302   

Earnings Per Common Share-Basic:

       

Income from continuing operations

   $ 2.25       $ 3.09      $ 2.49   

Loss from discontinued operations

             (0.16     (1.96

Net income attributable to Dominion

   $ 2.25       $ 2.93      $ 0.53   

Earnings Per Common Share-Diluted:

       

Income from continuing operations

   $ 2.24       $ 3.09      $ 2.49   

Loss from discontinued operations

             (0.16     (1.96

Net income attributable to Dominion

   $ 2.24       $ 2.93      $ 0.53   

Dividends declared per common share

   $ 2.40       $ 2.25      $ 2.11   

 

(1) Includes income tax benefit of $43 million and $692 million in 2013 and 2012, respectively. For 2012, includes impairment charges of $1.6 billion related to Brayton Point and Kincaid. See Note 6 for additional information.

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

 

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Dominion Resources, Inc.

Consolidated Statements of Comprehensive Income

 

 

 

Year Ended December 31,    2014     2013     2012  
(millions)                   

Net income including noncontrolling interests

   $ 1,326      $ 1,720      $ 329   

Other comprehensive income (loss), net of taxes:

      

Net deferred gains (losses) on derivatives-hedging activities, net of $(20), $161 and $5 tax

     17        (243     (8

Changes in unrealized net gains on investment securities, net of $(59), $(136) and $(68) tax

     128        203        108   

Changes in net unrecognized pension and other postretirement benefit costs, net of $189, $(341) and $209 tax

     (305     516        (330

Amounts reclassified to net income:

      

Net derivative (gains) losses-hedging activities, net of $(59), $(53) and $34 tax

     93        77        (60

Net realized gains on investment securities, net of $33, $35 and $16 tax

     (54     (55     (25

Net pension and other postretirement benefit costs, net of $(24), $(39) and $(32) tax

     33        55        48   

Changes in other comprehensive income (loss) from equity method investees, net of $3, $— and $— tax

     (4              

Total other comprehensive income (loss)

     (92     553        (267

Comprehensive income including noncontrolling interests

     1,234        2,273        62   

Comprehensive income attributable to noncontrolling interests

     16        23        27   

Comprehensive income attributable to Dominion

   $ 1,218      $ 2,250      $ 35   

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

 

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Dominion Resources, Inc.

Consolidated Balance Sheets

 

 

 

At December 31,    2014     2013  
(millions)             
ASSETS     

Current Assets

    

Cash and cash equivalents

   $ 318      $ 316   

Customer receivables (less allowance for doubtful accounts of $34 and $25)

     1,514        1,695   

Other receivables (less allowance for doubtful accounts of $3 and $4)

     119        141   

Inventories:

    

Materials and supplies

     923        689   

Fossil fuel

     413        393   

Gas stored

     74        94   

Derivative assets

     536        687   

Margin deposit assets

     287        620   

Prepayments

     167        192   

Deferred income taxes

     800        778   

Regulatory assets

     347        217   

Other

     117        118   

Total current assets

     5,615        5,940   

Investments

    

Nuclear decommissioning trust funds

     4,196        3,903   

Investment in equity method affiliates

     1,081        916   

Other

     284        283   

Total investments

     5,561        5,102   

Property, Plant and Equipment

    

Property, plant and equipment

     51,406        46,969   

Accumulated depreciation, depletion and amortization

     (15,136     (14,341

Total property, plant and equipment, net

     36,270        32,628   

Deferred Charges and Other Assets

    

Goodwill

     3,044        3,086   

Pension and other postretirement benefit assets

     956        942   

Intangible assets, net

     570        560   

Regulatory assets

     1,642        1,228   

Other

     669        610   

Total deferred charges and other assets

     6,881        6,426   

Total assets

   $ 54,327      $ 50,096   

 

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At December 31,    2014     2013  
(millions)             
LIABILITIES AND EQUITY     

Current Liabilities

    

Securities due within one year

   $ 1,375      $ 1,519   

Short-term debt

     2,775        1,927   

Accounts payable

     952        1,168   

Accrued interest, payroll and taxes

     566        609   

Derivative liabilities

     591        828   

Other

     939        943   

Total current liabilities

     7,198        6,994   

Long-Term Debt

    

Long-term debt

     18,348        16,877   

Junior subordinated notes

     1,374        1,373   

Remarketable subordinated notes

     2,083        1,080   

Total long-term debt

     21,805        19,330   

Deferred Credits and Other Liabilities

    

Deferred income taxes and investment tax credits

     7,444        7,114   

Asset retirement obligations

     1,633        1,484   

Pension and other postretirement benefit liabilities

     1,296        481   

Regulatory liabilities

     1,991        2,001   

Other

     1,003        793   

Total deferred credits and other liabilities

     13,367        11,873   

Total liabilities

     42,370        38,197   

Commitments and Contingencies (see Note 22)

                

Subsidiary Preferred Stock Not Subject To Mandatory Redemption

            257   

Equity

    

Common stock-no par(1)

     5,876        5,783   

Retained earnings

     6,095        6,183   

Accumulated other comprehensive loss

     (416     (324

Total common shareholders’ equity

     11,555        11,642   

Noncontrolling interests

     402          

Total equity

     11,957        11,642   

Total liabilities and equity

   $ 54,327      $ 50,096   

 

(1) 1 billion shares authorized; 585 million shares and 581 million shares outstanding at December 31, 2014 and 2013, respectively.

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

 

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Dominion Resources, Inc.

Consolidated Statements of Equity

 

 

 

      Common Stock     Dominion Shareholders                       
      Shares      Amount     Other
Paid-In
Capital
    Retained
Earnings
    Accumulated
Other
Comprehensive
Income (Loss)
    Total Common
Shareholders’
Equity
    Noncontrolling
Interests
    Total
Equity
 
(millions)                                                  

December 31, 2011

     570       $ 5,180      $ 179      $ 6,697      $ (610   $ 11,446      $ 57      $ 11,503   

Net income including noncontrolling interests

            318          318        11        329   

Issuance of stock-employee and direct stock purchase plans

     4         246              246          246   

Stock awards and stock options exercised (net of change in unearned compensation)

     1         26              26          26   

Other stock issuances(1)

     1         41        (27         14          14   

Tax benefit from stock awards and stock options exercised

          10            10          10   

Dividends

            (1,225 )(2)        (1,225     (11     (1,236

Other comprehensive loss, net of tax

                                      (267     (267             (267

December 31, 2012

     576         5,493        162        5,790        (877     10,568        57        10,625   

Net income including noncontrolling interests

            1,714          1,714        6        1,720   

Issuance of stock-employee and direct stock purchase plans

     4         278              278          278   

Stock awards (net of change in unearned compensation)

        12              12          12   

Other stock issuances(3)

     1         15        (8         7          7   

Present value of stock purchase contract payments related to RSNs(4)

          (154     (2       (156       (156

Fairless lease buyout(5)

        (15           (15     (57     (72

Dividends

            (1,319 )(2)        (1,319     (6     (1,325

Other comprehensive income, net of tax

                                      553        553                553   

December 31, 2013

     581         5,783               6,183        (324     11,642               11,642   

Net income including noncontrolling interests

            1,323          1,323        3        1,326   

Issuance of Dominion Midstream common units, net of offering costs

                       392        392   

Issuance of stock-employee and direct stock purchase plans

     3         205              205          205   

Stock awards (net of change in unearned compensation)

        14              14          14   

Other stock issuances(1)

     1         14              14          14   

Present value of stock purchase contract payments related to RSNs(4)

        (143           (143       (143

Dividends

            (1,411 )(2)        (1,411       (1,411

Other comprehensive income, net of tax

              (92     (92       (92

Other

              3                                3        7        10   

December 31, 2014

     585       $ 5,876      $      $ 6,095      $ (416   $ 11,555      $ 402      $ 11,957   

 

(1) Contains shares issued in excess of principal amounts related to converted securities. See Note 17 for further information on convertible securities.
(2) Includes subsidiary preferred dividends related to noncontrolling interests of $13 million, $17 million and $16 million in 2014 and 2013 and 2012, respectively.
(3) Primarily includes $28 million in shares issued in excess of principal amounts related to converted securities, net of reclassification from other paid-in capital. See Note 17 for further information on convertible securities.
(4) See Note 17 for further information.
(5) See Note 15 for further information.

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements

 

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Dominion Resources, Inc.

Consolidated Statements of Cash Flows

 

 

 

Year Ended December 31,    2014     2013     2012  
(millions)                   

Operating Activities

      

Net income including noncontrolling interests

   $ 1,326      $ 1,720      $ 329   

Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:

      

Impairment of generation assets

            48        2,089   

Net payments related to rate refunds

            (5     (151

Depreciation, depletion and amortization (including nuclear fuel)

     1,560        1,390        1,443   

Deferred income taxes and investment tax credits

     449        737        246   

Gains on the sale of assets and businesses

     (220     (122     (81

Charges associated with North Anna and offshore wind legislation

     374                 

Charges associated with Liability Management Exercise

     284                 

Charges associated with proposed settlement for ash pond closure costs

     121                 

Other adjustments

     (113     (129     (164

Changes in:

      

Accounts receivable

     131        (98     292   

Inventories

     (43     (29     33   

Deferred fuel and purchased gas costs, net

     (180     102        368   

Prepayments

     24        123        (85

Accounts payable

     (202     50        (61

Accrued interest, payroll and taxes

     (41     (27     (12

Margin deposit assets and liabilities

     361        (414     45   

Other operating assets and liabilities

     (392     87        (154

Net cash provided by operating activities

     3,439        3,433        4,137   

Investing Activities

      

Plant construction and other property additions (including nuclear fuel)

     (5,345     (4,065     (4,145

Acquisition of solar development projects

     (206     (39       

Proceeds from sales of securities

     1,235        1,476        1,356   

Purchases of securities

     (1,241     (1,493     (1,392

Proceeds from the sale of Brayton Point, Kincaid and equity method investment in Elwood

            465          

Proceeds from the sale of electric retail energy marketing business

     187                 

Proceeds from Blue Racer

     85        160        115   

Proceeds from assignments of Marcellus acreage

     60        18          

Restricted cash equivalents

     8        25        108   

Other

     36        (5     118   

Net cash used in investing activities

     (5,181     (3,458     (3,840

Financing Activities

      

Issuance (repayment) of short-term debt, net

     848        (485     598   

Issuance of short-term notes

     400        400        400   

Repayment of short-term notes

     (400     (400       

Issuance of long-term debt

     6,085        4,135        1,500   

Repayment and repurchase of long-term debt, including redemption premiums

     (3,993     (1,245     (1,675

Repayment of junior subordinated notes

            (258       

Acquisition of Juniper noncontrolling interest in Fairless

            (923       

Net proceeds from issuance of Dominion Midstream common units

     392                 

Subsidiary preferred stock redemption

     (259              

Issuance of common stock

     205        278        265   

Common dividend payments

     (1,398     (1,302     (1,209

Subsidiary preferred dividend payments

     (11     (17     (16

Other

     (125     (90     (14

Net cash provided by (used in) financing activities

     1,744        93        (151

Increase in cash and cash equivalents

     2        68        146   

Cash and cash equivalents at beginning of year

     316        248        102   

Cash and cash equivalents at end of year

   $ 318      $ 316      $ 248   

Supplemental Cash Flow Information

      

Cash paid (received) during the year for:

      

Interest and related charges, excluding capitalized amounts

   $ 889      $ 852      $ 913   

Income taxes

     72        56        (58

Significant noncash investing activities:

      

Accrued capital expenditures

     315        375        388   

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

 

To the Board of Directors and Shareholder of

Virginia Electric and Power Company

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (“Virginia Power”) as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of Virginia Power’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Virginia Power’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2015

 

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Virginia Electric and Power Company

Consolidated Statements of Income

 

 

 

Year Ended December 31,    2014      2013      2012  
(millions)                     

Operating Revenue(1)

   $ 7,579       $ 7,295       $ 7,226   

Operating Expenses

        

Electric fuel and other energy-related purchases(1)

     2,406         2,304         2,368   

Purchased electric capacity

     360         358         386   

Other operations and maintenance:

        

Affiliated suppliers

     286         290         305   

Other

     1,630         1,161         1,161   

Depreciation and amortization

     915         853         782   

Other taxes

     258         249         232   

Total operating expenses

     5,855         5,215         5,234   

Income from operations

     1,724         2,080         1,992   

Other income

     93         86         96   

Interest and related charges

     411         369         385   

Income from operations before income tax expense

     1,406         1,797         1,703   

Income tax expense

     548         659         653   

Net Income

     858         1,138         1,050   

Preferred dividends(2)

     13         17         16   

Balance available for common stock

   $ 845       $ 1,121       $ 1,034   

 

(1) See Note 24 for amounts attributable to affiliates.
(2) Includes $2 million associated with the write-off of issuance expenses related to the redemption of Virginia Power’s preferred stock in 2014. See Note 18 for additional information.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

 

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Virginia Electric and Power Company

Consolidated Statements of Comprehensive Income

 

 

 

Year Ended December 31,    2014     2013     2012  
(millions)                   

Net income

   $ 858      $ 1,138      $ 1,050   

Other comprehensive income (loss), net of taxes:

      

Net deferred gains (losses) on derivatives-hedging activities, net of $2, $(3) and $3 tax

     (4     6        (5

Changes in unrealized net gains on nuclear decommissioning trust funds, net of $(9), $(13) and $(7) tax

     15        20        13   

Amounts reclassified to net income:

      

Net derivative (gains) losses-hedging activities, net of $2, $— and $(2) tax

     (3            2   

Net realized gains on nuclear decommissioning trust funds, net of $4, $2 and $2 tax

     (6     (3     (4

Other comprehensive income

     2        23        6   

Comprehensive income

   $ 860      $ 1,161      $ 1,056   

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

 

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Virginia Electric and Power Company

Consolidated Balance Sheets

 

 

 

At December 31,    2014     2013  
(millions)             
ASSETS     

Current Assets

    

Cash and cash equivalents

   $ 15      $ 16   

Customer receivables (less allowance for doubtful accounts of $25 and $11)

     986        946   

Other receivables (less allowance for doubtful accounts of $1 and $2)

     65        78   

Inventories (average cost method):

    

Materials and supplies

     455        418   

Fossil fuel

     398        390   

Prepayments

     252        32   

Regulatory assets

     298        128   

Deferred income taxes

     6        87   

Other(1)

     76        68   

Total current assets

     2,551        2,163   

Investments

    

Nuclear decommissioning trust funds

     1,930        1,765   

Other

     4        12   

Total investments

     1,934        1,777   

Property, Plant and Equipment

    

Property, plant and equipment

     35,180        32,848   

Accumulated depreciation and amortization

     (11,080     (10,580

Total property, plant and equipment, net

     24,100        22,268   

Deferred Charges and Other Assets

    

Intangible assets, net

     205        193   

Regulatory assets

     439        417   

Other(1)

     280        143   

Total deferred charges and other assets

     924        753   

Total assets

   $ 29,509      $ 26,961   

(1) See Note 24 for amounts attributable to affiliates.

 

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At December 31,    2014      2013  
(millions)              
LIABILITIES AND SHAREHOLDERS EQUITY      

Current Liabilities

     

Securities due within one year

   $ 211       $ 58   

Short-term debt

     1,361         842   

Accounts payable

     458         479   

Payables to affiliates

     92         69   

Affiliated current borrowings

     427         97   

Accrued interest, payroll and taxes

     199         218   

Derivative liabilities

     60         12   

Customer deposits

     107         95   

Regulatory liabilities

     90         41   

Other

     271         306   

Total current liabilities

     3,276         2,217   

Long-Term Debt

     8,726         7,974   

Deferred Credits and Other Liabilities

     

Deferred income taxes and investment tax credits

     4,415         4,137   

Asset retirement obligations

     848         689   

Regulatory liabilities

     1,683         1,597   

Pension and other postretirement benefit liabilities(1)

     219         147   

Other

     287         145   

Total deferred credits and other liabilities

     7,452         6,715   

Total liabilities

     19,454         16,906   

Commitments and Contingencies (see Note 22)

                 

Preferred Stock Not Subject to Mandatory Redemption

             257   

Common Shareholder’s Equity

     

Common stock-no par(2)

     5,738         5,738   

Other paid-in capital

     1,113         1,113   

Retained earnings

     3,154         2,899   

Accumulated other comprehensive income

     50         48   

Total common shareholder’s equity

     10,055         9,798   

Total liabilities and shareholder’s equity

   $ 29,509       $ 26,961   

 

(1) See Note 24 for amounts attributable to affiliates.
(2) 500,000 shares authorized at December 31, 2014 and 2013; 274,723 shares outstanding at December 31, 2014 and 2013.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

 

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Virginia Electric and Power Company

Consolidated Statements of Common Shareholder’s Equity

 

 

 

      Common Stock      Other
Paid-In
Capital
     Retained
Earnings
    Accumulated
Other
Comprehensive
Income
     Total  
     Shares      Amount             
(millions, except for shares)    (thousands)                                         

Balance at December 31, 2011

     275       $ 5,738       $ 1,111       $ 1,882      $ 19       $ 8,750   

Net income

              1,050           1,050   

Dividends

              (575        (575

Tax benefit from stock awards and stock options exercised

           2              2   

Other comprehensive income, net of tax

                                        6         6   

Balance at December 31, 2012

     275         5,738         1,113         2,357        25         9,233   

Net income

              1,138           1,138   

Dividends

              (596        (596

Other comprehensive income, net of tax

                                        23         23   

Balance at December 31, 2013

     275         5,738         1,113         2,899        48         9,798   

Net income

              858           858   

Dividends

              (603        (603

Other comprehensive income, net of tax

                                        2         2   

Balance at December 31, 2014

     275       $ 5,738       $ 1,113       $ 3,154      $ 50       $ 10,055   

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

 

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Virginia Electric and Power Company

Consolidated Statements of Cash Flows

 

 

 

Year Ended December 31,    2014     2013     2012  
(millions)                   

Operating Activities

      

Net income

   $ 858      $ 1,138      $ 1,050   

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation and amortization (including nuclear fuel)

     1,090        1,016        927   

Deferred income taxes and investment tax credits, net

     396        240        502   

Charges associated with North Anna and offshore wind legislation

     374                 

Charges associated with proposed settlement for ash pond closure costs

     121                 

Net payments related to rate refunds

            (5     (151

Other adjustments

     (35     (63     (70

Changes in:

      

Accounts receivable

     (27     (124     126   

Affiliated accounts receivable and payable

     23        3        (2

Inventories

     (45     (19     8   

Deferred fuel expenses, net

     (191     93        378   

Prepayments

     (220     (9     18   

Accounts payable

     5        15        19   

Accrued interest, payroll and taxes

     (19     14        (22

Other operating assets and liabilities

     (82     30        (77

Net cash provided by operating activities

     2,248        2,329        2,706   

Investing Activities

      

Plant construction and other property additions

     (2,911     (2,394     (2,082

Purchases of nuclear fuel

     (196     (139     (206

Purchases of securities

     (574     (603     (638

Proceeds from sales of securities

     549        572        626   

Other

     (2     (37     18   

Net cash used in investing activities

     (3,134     (2,601     (2,282

Financing Activities

      

Issuance (repayment) of short-term debt, net

     519        (151     98   

Issuance (repayment) of affiliated current borrowings, net

     330        (338     248   

Issuance of long-term debt

     950        1,835        450   

Repayment of long-term debt

     (61     (470     (641

Preferred stock redemption

     (259              

Common dividend payments

     (590     (579     (559

Preferred dividend payments

     (11     (17     (16

Other

     7        (20     (5

Net cash provided by (used in) financing activities

     885        260        (425

Decrease in cash and cash equivalents

     (1     (12     (1

Cash and cash equivalents at beginning of year

     16        28        29   

Cash and cash equivalents at end of year

   $ 15      $ 16      $ 28   

Supplemental Cash Flow Information

      

Cash paid during the year for:

      

Interest and related charges, excluding capitalized amounts

   $ 383      $ 328      $ 376   

Income taxes

     386        427        225   

Significant noncash investing activities:

      

Accrued capital expenditures

     181        276        242   

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

 

To the Board of Directors of

Dominion Gas Holdings, LLC

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Dominion Gas Holdings, LLC (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (“Dominion Gas”) as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of Dominion Gas’ management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Dominion Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Dominion Gas’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Gas Holdings, LLC and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2015

 

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Dominion Gas Holdings, LLC

Consolidated Statements of Income

 

 

 

Year Ended December 31,    2014      2013      2012  
(millions)                     

Operating Revenue(1)

   $ 1,898       $ 1,937       $ 1,677   

Operating Expenses

        

Purchased gas(1)

     315         323         235   

Other energy-related purchases

     40         93         41   

Other operations and maintenance:

        

Affiliated suppliers

     64         70         112   

Other(2)

     274         353         223   

Depreciation and amortization

     197         188         176   

Other taxes

     157         148         140   

Total operating expenses

     1,047         1,175         927   

Income from operations

     851         762         750   

Other income

     22         28         37   

Interest and related charges(1)

     27         28         40   

Income from operations before income tax expense

     846         762         747   

Income tax expense

     334         301         288   

Net Income

   $ 512       $ 461       $ 459   

 

(1) See Note 24 for amounts attributable to related parties.
(2) Includes gains on the sales of assets to related parties of $59 million, $122 million and $176 million in 2014, 2013 and 2012, respectively. See Note 9 for more information.

The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.

 

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Dominion Gas Holdings, LLC

Consolidated Statements of Comprehensive Income

 

 

 

Year Ended December 31,    2014     2013      2012  
(millions)                    

Net income

   $ 512      $ 461       $ 459   

Other comprehensive income (loss), net of taxes:

       

Net deferred gains (losses) on derivatives-hedging activities, net of $19, $(27) and $(10) tax

     (31     39         13   

Changes in unrecognized pension and other postretirement benefit costs, net of $6, $(18) and $5 tax

     (10     26         (7

Amounts reclassified to net income:

       

Net derivative losses-hedging activities, net of $(5), $(5) and $(13) tax

     8        11         20   

Net pension and other postretirement benefit costs, net of $(3), $(4) and $(4) tax

     5        6         5   

Other comprehensive income (loss)

     (28     82         31   

Comprehensive income

   $ 484      $ 543       $ 490   

The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.

 

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Dominion Gas Holdings, LLC

Consolidated Balance Sheets

 

 

 

At December 31,    2014     2013  
(millions)             
ASSETS     

Current Assets

    

Cash and cash equivalents

   $ 9      $ 8   

Customer receivables (less allowance for doubtful accounts of $4 and $5)(1)

     322        311   

Other receivables (less allowance for doubtful accounts of $1 at both dates)

     19        2   

Affiliated receivables

     12        41   

Inventories:

    

Materials and supplies

     53        56   

Gas stored

     12        7   

Prepayments

     166        67   

Regulatory assets

     38        79   

Deferred income taxes

     96        89   

Other(1)

     83        141   

Total current assets

     810        801   

Investments

     108        106   

Property, Plant and Equipment

    

Property, plant and equipment

     8,902        8,240   

Accumulated depreciation and amortization

     (2,538     (2,421

Total property, plant and equipment, net

     6,364        5,819   

Deferred Charges and Other Assets

    

Goodwill

     542        545   

Intangible assets, net

     79        82   

Regulatory assets

     379        285   

Pension and other postretirement benefit assets(1)

     1,486        1,436   

Other(1)

     80        68   

Total deferred charges and other assets

     2,566        2,416   

Total assets

   $ 9,848      $ 9,142   

(1) See Note 24 for amounts attributable to related parties.

 

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At December 31,    2014     2013  
(millions)             
LIABILITIES AND EQUITY     

Current Liabilities

    

Accounts payable

   $ 247      $ 277   

Payables to affiliates

     41        45   

Affiliated current borrowings

     384        1,342   

Accrued interest, payroll and taxes

     194        209   

Regulatory liabilities

     75        79   

Other(1)

     97        118   

Total current liabilities

     1,038        2,070   

Long-Term Debt

     2,594        1,198   

Deferred Credits and Other Liabilities

    

Deferred income taxes and investment tax credits

     2,158        1,977   

Regulatory liabilities

     192        203   

Other(1)

     300        267   

Total deferred credits and other liabilities

     2,650        2,447   

Total liabilities

     6,282        5,715   

Commitments and Contingencies (see Note 22)

                

Equity

    

Membership interests

     3,652        3,485   

Accumulated other comprehensive loss

     (86     (58

Total equity

     3,566        3,427   

Total liabilities and equity

   $ 9,848      $ 9,142   

 

(1) See Note 24 for amounts attributable to related parties.

The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.

 

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Dominion Gas Holdings, LLC

Consolidated Statements of Equity

 

 

 

      Membership Interests     Accumulated
Other
Comprehensive
Income (Loss)
    Total  
(millions)                   

Balance at December 31, 2011

   $ 3,167      $ (171   $ 2,996   

Net income

     459          459   

Distributions

     (210       (210

Other comprehensive income, net of tax

             31        31   

Balance at December 31, 2012

     3,416        (140     3,276   

Net income

     461          461   

Equity contribution from parent

     6          6   

Distributions

     (398       (398

Other comprehensive income, net of tax

             82        82   

Balance at December 31, 2013

     3,485        (58     3,427   

Net income

     512          512   

Equity contribution from parent

     1          1   

Distributions

     (346       (346

Other comprehensive loss, net of tax

             (28     (28

Balance at December 31, 2014

   $ 3,652      $ (86   $ 3,566   

The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.

 

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Dominion Gas Holdings, LLC

Consolidated Statements of Cash Flows

 

 

 

Year Ended December 31,    2014     2013     2012  
(millions)                   

Operating Activities

      

Net income

   $ 512      $ 461      $ 459   

Adjustments to reconcile net income to net cash provided by operating activities:

      

Gains on sales of assets

     (124     (122     (176

Depreciation and amortization

     197        188        176   

Deferred income taxes and investment tax credits, net

     216        102        294   

Other adjustments

     2        (3     2   

Changes in:

      

Accounts receivable

     (42     (17     63   

Affiliated receivables

     (1     2        (3

Inventories

     (2            5   

Prepayments

     (99     13        (9

Accounts payable

     (35     62        (52

Payables to affiliates

     (4     8        (12

Accrued interest, payroll and taxes

     (15     48        (43

Other operating assets and liabilities

     (134     (44     (75

Net cash provided by operating activities

     471        698        629   

Investing Activities

      

Plant construction and other property additions

     (719     (650     (928

Proceeds from sale of assets to an affiliate

     47        113          

Proceeds from Blue Racer

     1        78          

Proceeds from assignments of Marcellus acreage

     60        18          

Advances to affiliate, net

            (5     (14

Other

     (5     (14     (10

Net cash used in investing activities

     (616     (460     (952

Financing Activities

      

Issuance (repayment) of affiliated current borrowings, net

     (892     (545     549   

Repayment and acquisition of affiliated long-term debt

            (569     (10

Issuance of long-term debt

     1,400        1,200          

Distribution payments

     (346     (318     (210

Other

     (16     (10       

Net cash provided by (used in) financing activities

     146        (242     329   

Increase (decrease) in cash and cash equivalents

     1        (4     6   

Cash and cash equivalents at beginning of year

     8        12        6   

Cash and cash equivalents at end of year

   $ 9      $ 8      $ 12   

Supplemental Cash Flow Information

      

Cash paid during the year for:

      

Interest and related charges, excluding capitalized amounts

   $ 23      $ 31      $ 43   

Income taxes

     266        148        67   

Significant noncash investing and financing activities:

      

Accrued capital expenditures

     35        42        62   

Extinguishment of affiliated long-term debt in exchange for assets sold to affiliate

     67               187   

Distribution of non-cash asset (account receivable) to parent

            80          

Proceeds from sale of assets to affiliate not yet received

            30        61   

Conversion of affiliated current borrowings to membership interests

                   61   

The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.

 

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Combined Notes to Consolidated Financial Statements

 

 

 

NOTE 1. NATURE OF OPERATIONS

Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Gas. Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion. Dominion Gas is a holding company that conducts 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. All of Dominion Gas’ membership interests are held by Dominion.

Dominion’s operations also include an LNG import, transport and storage facility in Maryland, a preferred equity interest in which was contributed to Dominion Midstream in 2014, an equity investment in Atlantic Coast Pipeline and regulated gas transportation and distribution operations in West Virginia. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities, retail energy marketing operations and an equity investment in Blue Racer.

In October 2014, Dominion Midstream launched its initial public offering of 20,125,000 common units representing limited partner interests at a price of $21 per unit, which included an over-allotment option to purchase an additional 2,625,000 common units at the initial offering price, which was exercised in full by the underwriters. Dominion received $392 million in net proceeds from the sale of the units, after deducting underwriting discounts, structuring fees and estimated offering expenses. 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. The public’s ownership interest in Dominion Midstream is reflected as non-controlling interest in Dominion’s Consolidated Financial Statements.

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 and Note 25. 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.

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 one 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 and the effect of certain items recorded at Dominion Gas as a result of the recognition of Dominion’s basis in the net assets contributed.

See Note 25 for further discussion of the Companies’ operating segments.

 

 

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

General

The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates.

The Companies’ Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of their respective majority-owned subsidiaries.

The Companies report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.

Dominion maintains pension and other postretirement benefit plans. Virginia Power and Dominion Gas participate in certain of these plans. See Note 21 for further information on these plans.

Certain amounts in the 2013 and 2012 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2014 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

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

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Dominion and Virginia Power collect sales, consumption and consumer utility taxes and Dominion Gas collects sales taxes; however, these amounts are excluded from revenue. Dominion’s customer receivables at December 31, 2014 and 2013 included $564 million and $555 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2014 and 2013 included $407 million and $395 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. Dominion Gas’ customer receivables at December 31, 2014 and 2013 included $127 million and $106 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its customers.

 

 

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The primary types of sales and service activities reported as operating revenue for Dominion are as follows:

Ÿ  

Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

Ÿ  

Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;

Ÿ  

Regulated gas sales consist primarily of state- and FERC-regulated natural gas sales and related distribution services;

Ÿ  

Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity;

Ÿ  

Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; and

Ÿ  

Other revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes miscellaneous service revenue from electric and gas distribution operations, and gas processing and handling revenue.

The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:

Ÿ  

Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and

Ÿ  

Other revenue consists primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.

The primary types of sales and service activities reported as operating revenue for Dominion Gas are as follows:

Ÿ  

Regulated gas sales consist primarily of state- and FERC-regulated natural gas sales and related distribution services;

Ÿ  

Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices and sales of gas purchased from third parties. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties;

Ÿ  

Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers;

Ÿ  

NGL revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity; and

Ÿ  

Other revenue consists primarily of miscellaneous service revenue, gas processing and handling revenue and gathering revenue.

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Where permitted by regulatory authorities, the differences between Dominion’s and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion’s and Dominion Gas’

purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.

Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 84% is currently subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.

Virtually all of Dominion Gas’, Cove Point’s and Hope’s natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale.

Income Taxes

A consolidated federal income tax return is filed for Dominion and its subsidiaries, including Virginia Power and Dominion Gas’ subsidiaries. In addition, where applicable, combined income tax returns for Dominion and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed.

Although Dominion Gas is disregarded for income tax purposes, a provision for income taxes is recognized to reflect the inclusion of its business activities in the tax returns of its parent, Dominion. Virginia Power and Dominion Gas participate in intercompany tax sharing agreements with Dominion and its subsidiaries, and current income taxes are based on taxable income or loss, determined on a separate company basis.

Under the agreements, if a subsidiary incurs a net operating loss, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or to the extent the net operating loss is absorbed by the taxable income of other Dominion consolidated group members. Otherwise, the net operating loss is carried forward and is recognized as a deferred tax asset until realized.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. The Companies establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

The Companies recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited

 

 

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to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the consolidated balance sheets and current payables are included in accrued interest, payroll and taxes on the consolidated balance sheets.

The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income, respectively. Penalties are also recognized in other income.

Dominion’s, Virginia Power’s and Dominion Gas’ interest and penalties were immaterial in 2014, 2013 and 2012.

At December 31, 2014, Virginia Power’s Consolidated Balance Sheet included $225 million of federal and state income taxes receivable, $13 million of noncurrent state income taxes receivable and $38 million of noncurrent federal and state income taxes payable.

At December 31, 2013, Virginia Power’s Consolidated Balance Sheet included $3 million of state income taxes receivable, $22 million of federal and state income taxes payable, $12 million of noncurrent state income taxes receivable and $28 million of noncurrent federal and state income taxes payable.

At December 31, 2014, Dominion Gas’ Consolidated Balance Sheet included $96 million of federal and state income taxes receivable, $14 million of state income taxes payable, $7 million of noncurrent state income taxes payable and $20 million noncurrent state income taxes receivable.

At December 31, 2013, Dominion Gas’ Consolidated Balance Sheet included $17 million of federal income taxes payable, $23 million of state income taxes payable, $1 million of state income taxes receivable, $7 million of noncurrent state income taxes payable and $20 million noncurrent state income taxes receivable.

Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until they are presented for payment. The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies:

 

Year Ended December 31,    2014      2013  
(millions)              

Dominion

   $ 42       $ 38   

Virginia Power

     20         21   

Dominion Gas

     9         7   
    

 

 

    

 

 

 

For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Derivative Instruments

Dominion and Virginia Power use derivative instruments such as futures, swaps, forwards, options and FTRs to manage the commodity, currency exchange and financial market risks of their business operations. Dominion Gas uses derivative instruments such as physical and financial forwards, futures and swaps to manage commodity price and interest rate risks.

All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.

The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion had margin assets of $287 million and $620 million associated with cash collateral at December 31, 2014 and 2013, respectively. Dominion had margin liabilities of $34 million and $2 million associated with cash collateral at December 31, 2014 and 2013, respectively. Virginia Power had margin assets of $6 million and $11 million associated with cash collateral at December 31, 2014 and 2013, respectively. Virginia Power did not have any margin liabilities associated with cash collateral at December 31, 2014 or 2013. Dominion Gas did not have any margin assets or liabilities related to cash collateral at December 31, 2014 or 2013. See Note 7 for further information about derivatives.

To manage price risk, Dominion and Virginia Power hold certain derivative instruments that are not designated as hedges for accounting purposes. However, to the extent Dominion and Virginia Power do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. As part of Dominion’s strategy to market energy and manage related risks, it formerly managed a portfolio of commodity-based financial derivative instruments held for trading purposes. Dominion used established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and used various derivative instruments to reduce risk by creating offsetting market positions. In the second quarter of 2013, Dominion commenced a repositioning of its producer services business. The repositioning was completed in the first quarter of 2014 and resulted in the termination of natural gas trading and certain energy marketing activities.

Statement of Income Presentation:

Ÿ  

Derivatives Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis.

 

 

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Ÿ  

Derivatives Not Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses or interest and related charges based on the nature of the underlying risk.

In Virginia Power’s generation operations, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.

DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS

The Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, the Companies formally document the relationship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using the hedging instrument. The Companies assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges—A majority of the Companies’ hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas, NGLs and other energy-related products. The Companies also use foreign currency contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which the Companies are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Dominion entered into interest rate derivative instruments to hedge its forecasted interest payments related to planned debt issuances in 2013 and 2014. These interest rate derivatives were designated by Dominion as cash flow hedges in 2012 and 2013, prior to the formation of Dominion Gas. For the purposes of the Dominion Gas financial statements, the derivative balances, AOCI balance, and any income statement impact related to these

interest rate derivative instruments entered into by Dominion have been, and will continue to be, included in the Dominion Gas’ Consolidated Financial Statements as the forecasted interest payments related to the debt issuances will now occur at Dominion Gas.

Fair Value Hedges—Dominion also uses fair value hedges to mitigate the fixed price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, Dominion and Virginia Power have designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Derivative gains and losses from the hedged item are reclassified to earnings when the hedged item is included in earnings, or earlier, if the hedged item no longer qualifies for hedge accounting. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.

Property, Plant and Equipment

Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred.

In 2014, 2013 and 2012, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $80 million, $66 million and $91 million, respectively. In 2014, 2013 and 2012, Virginia Power capitalized AFUDC to property, plant and equipment of $39 million, $33 million and $31 million, respectively. In 2014, 2013 and 2012, Dominion Gas capitalized AFUDC to property, plant and equipment of $1 million, $5 million and $23 million, respectively.

Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2014, 2013 and 2012, Virginia Power recorded $8 million, $32 million and $37 million of AFUDC related to these projects, respectively.

For property subject to cost-of-service rate regulation, including Virginia Power electric distribution, electric transmission, and generation property, Dominion Gas natural gas distribution and transmission property, and for certain Dominion natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be abandoned.

For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not asso-

 

 

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ciated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows:

 

Year Ended December 31,    2014      2013      2012  
(percent)                     

Dominion

        

Generation

     2.66         2.71         2.62   

Transmission

     2.38         2.36         2.17   

Distribution

     3.12         3.13         3.17   

Storage

     2.39         2.43         2.59   

Gas gathering and processing

     2.81         2.39         2.49   

General and other

     3.62         3.82         4.55   

Virginia Power

        

Generation

     2.66         2.71         2.62   

Transmission

     2.34         2.28         1.98   

Distribution

     3.34         3.33         3.32   

General and other

     3.29         3.51         4.32   

Dominion Gas

        

Transmission

     2.40         2.43         2.35   

Distribution

     2.47         2.50         2.66   

Storage

     2.40         2.43         2.58   

Gas gathering and processing

     2.82         2.39         2.50   

General and other

     5.77         5.93         6.09   

In 2013, Virginia Power revised its depreciation rates to reflect the results of a new depreciation study. This change resulted in an increase of $19 million ($12 million after-tax) in depreciation and amortization expense in Virginia Power’s Consolidated Statements of Income.

In 2014, Virginia Power also made a one-time adjustment to depreciation expense as ordered by the Virginia Commission. This adjustment resulted in an increase of $38 million ($23 million after-tax) in depreciation and amortization expense in Virginia Power’s Consolidated Statements of Income.

In 2013, Dominion Gas revised the depreciation rates for East Ohio to reflect the results of a new depreciation study. This change resulted in a decrease of $8 million ($5 million after-tax) in depreciation and amortization expense in Dominion Gas’ Consolidated Statements of Income.

Dominion’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

 

Asset    Estimated Useful Lives  

Merchant generation-nuclear

     44 years   

Merchant generation-other

     15 - 36 years   

General and other

     5 - 59 years   

Depreciation and amortization related to Virginia Power’s and Dominion Gas’ nonutility property, plant and equipment and E&P properties was immaterial for the years ended December 31, 2014, 2013 and 2012.

Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in

electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.

Long-Lived and Intangible Assets

The Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for a discussion of impairments related to certain long-lived assets and intangible assets with finite lives.

Regulatory Assets and Liabilities

The accounting for Dominion’s and Dominion Gas’ regulated gas and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their 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 that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. 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.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. 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.

Asset Retirement Obligations

The Companies recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. At least annually, the Companies evaluate the key assumptions underlying their AROs including estimates of the amounts and timing of future cash flows associated with retirement activities. AROs are adjusted when significant changes in these assumptions are identified. Dominion and Dominion Gas report accretion of AROs and depreciation on asset retirement costs associated with their natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Virginia Power reports accretion of AROs and depreciation on asset retirement costs associated with decommissioning its nuclear

 

 

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power stations as an adjustment to the regulatory liability for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs is reported in other operations and maintenance expense and depreciation expense in the Consolidated Statements of Income.

Debt Issuance Costs

The Companies defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as an asset and classified in other current assets and other deferred charges and other assets in the Consolidated Balance Sheets. Unamortized costs associated with redemptions of debt securities prior to stated maturity dates are generally recognized and recorded in interest expense immediately. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized over the lives of the new issuances.

Investments

MARKETABLE EQUITY AND DEBT SECURITIES

Dominion accounts for and classifies investments in marketable equity and debt securities as trading or available-for-sale securities. Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities.

Ÿ  

Trading securities include marketable equity and debt securities held by Dominion in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

Ÿ  

Available-for-sale securities include all other marketable equity and debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other available-for-sale securities, including those held in Dominion’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

In determining realized gains and losses for marketable equity and debt securities, the cost basis of the security is based on the specific identification method.

NON-MARKETABLE INVESTMENTS

The Companies account for illiquid and privately held securities for which market prices or quotations are not readily available under either the equity or cost method. Non-marketable investments include:

Ÿ  

Equity method investments when the Companies have the ability to exercise significant influence, but not control, over the investee. Dominion’s investments are included in investments in equity method affiliates and Virginia Power’s investments are included in other investments in their Consolidated Balance Sheets. The Companies record equity method adjustments in other income in the Consolidated Statements of Income including: their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

Ÿ  

Cost method investments when Dominion and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion’s and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds.

OTHER-THAN-TEMPORARY IMPAIRMENT

Dominion and Virginia Power periodically review their investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period.

Decommissioning Trust Investments—Special Considerations

Ÿ  

The recognition provisions of the FASB’s other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities.

Ÿ  

Debt Securities—Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, Dominion and Virginia Power record the credit loss in earnings and any remaining portion of the unrealized loss in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

Ÿ  

Equity securities and other investments—Dominion’s and Virginia Power’s method of assessing other-than-temporary declines requires demonstrating the ability to hold individual

 

 

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securities for a period of time sufficient to allow for the anticipated recovery in their market value prior to the consideration of the other criteria mentioned above. Since Dominion and Virginia Power have limited ability to oversee the day-to-day management of nuclear decommissioning trust fund investments, they do not have the ability to ensure investments are held through an anticipated recovery period. Accordingly, they consider all equity and other securities as well as non-marketable investments held in nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired.

Inventories

Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory for Dominion Gas used in East Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at $12 million and $7 million at December 31, 2014 and December 31, 2013, respectively. Based on the average price of gas purchased during 2014 and 2013, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $98 million and $77 million, respectively. Stored gas inventory for Dominion held by Hope and certain nonregulated gas operations is valued using the weighted-average cost method.

Gas Imbalances

Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion and Dominion Gas value these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion and Dominion Gas from other parties are reported in other current assets and imbalances that Dominion and Dominion Gas owe to other parties are reported in other current liabilities in the Consolidated Balance Sheets.

Goodwill

Dominion and Dominion Gas evaluate goodwill for impairment annually as of April 1 and whenever 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.

 

 

NOTE 3. ACQUISITIONS AND DISPOSITIONS

DOMINION

ACQUISITION OF SOLAR DEVELOPMENT PROJECTS

In March 2014, Dominion acquired 100% of the equity interests of six solar development projects in California from Recurrent Energy Development Holdings, LLC for approximately $50 million in cash. The projects cost approximately $446 million to construct, including the initial acquisition cost. The facilities, which began commercial operations in the fourth quarter of 2014, generate approximately 139 MW.

In November 2014, Dominion acquired 100% of the equity interests of a solar project in California from CSI Project Holdco,

LLC for approximately $79 million in cash. The project costs approximately $80 million to construct, including the initial acquisition cost. The facility, which began commercial operations in the fourth quarter of 2014, generates approximately 20 MW.

In December 2014, Dominion acquired 100% of the equity interests of a solar project in California from EDF Renewable Development, Inc. for approximately $71 million in cash. The project is expected to cost approximately $73 million to construct, including the initial acquisition cost. The facility, which began commercial operations in January 2015, generates approximately 20 MW.

The purchase price for each of these acquisitions was allocated to Property, Plant and Equipment.

In September 2014, Dominion entered into agreements to acquire 100% of the equity interests in two additional solar projects in California from EDF Renewable Development, Inc. for approximately $175 million in cash. 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.

These acquisitions provide Dominion with a large utility-scale solar presence and significantly increase its solar generation portfolio. Long-term power purchase, interconnection and operation and maintenance agreements have been executed for the projects. Dominion has claimed or expects to claim federal investment tax credits on the projects.

ACQUISITION OF CGT

In January 2015, Dominion completed the acquisition of 100% of the equity interests of CGT from SCANA Corporation for approximately $495 million in cash, subject to final acquired working capital adjustments. CGT owns and operates nearly 1,500 miles of FERC-regulated interstate natural gas pipeline in South Carolina and southeastern Georgia. This acquisition supports Dominion’s natural gas expansion into the Southeast. The acquired assets of CGT will be included in the Dominion Energy operating segment. Subject to board approvals by Dominion and Dominion Midstream, Dominion expects to contribute CGT into Dominion Midstream for a combination of debt and Dominion Midstream common units during the first half of 2015. The allocation of the purchase price to individual assets is under evaluation by management and has not been finalized.

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 resulted in a gain, subject to post-closing adjustments, of approximately $100 million ($57 million after-tax) net of a $31 million write-off of goodwill, and is included in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. The sale of the electric retail energy marketing business did not qualify for discontinued operations classification.

SALE OF ILLINOIS GAS CONTRACTS

In June 2013, Dominion completed the sale of Illinois Gas Contracts. The sales price was approximately $32 million, subject to post-closing adjustments. The sale resulted in a gain of approx-

 

 

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imately $29 million ($18 million after-tax) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in Dominion’s Consolidated Statement of Income. The sale of Illinois Gas Contracts did not qualify for discontinued operations classification as it is not considered a component under applicable accounting guidance.

SALE OF BRAYTON POINT, KINCAID AND EQUITY METHOD INVESTMENT IN ELWOOD

In March 2013, Dominion entered into an agreement with Energy Capital Partners to sell Brayton Point, Kincaid, and its equity method investment in Elwood.

In the first and second quarters of 2013, Brayton Point’s and Kincaid’s assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell, resulting in impairment charges totaling $48 million ($28 million after-tax), which are included in discontinued operations in Dominion’s Consolidated Statements of Income. In both periods, Dominion used the market approach to estimate the fair value of Brayton Point’s and Kincaid’s long-lived assets. These were considered Level 2 fair value measurements given that they were based on the agreed-upon sales price.

Dominion’s 50% interest in Elwood was an equity method investment and therefore, in accordance with applicable accounting guidance, the carrying amount of this investment was not classified as held for sale nor were the equity earnings from this investment reported as discontinued operations.

In August 2013, Dominion completed the sale and received proceeds of approximately $465 million, net of transaction costs. The sale resulted in a $35 million ($25 million after-tax) gain attributable to its equity method investment in Elwood, which is included in other income in Dominion’s Consolidated Statement of Income, which was partially offset by a $17 million ($18 million after-tax) loss attributable to Brayton Point and Kincaid, which includes a $16 million write-off of goodwill and is reflected in loss from discontinued operations in Dominion’s Consolidated Statement of Income. See Note 6 for other impairments related to these power stations.

The following table presents selected information regarding the results of operations of Brayton Point and Kincaid, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income:

 

Year Ended December 31,    2013     2012  
(millions)             

Operating revenue

   $ 304      $ 258   

Loss before income taxes

     (135 )(1)      (1,768 )(2) 

 

(1) Includes $64 million of charges related to the defeasance of Brayton Point debt and the early redemption of Kincaid debt in 2013.
(2) Includes a long-lived asset impairment charge of $1.6 billion.

SALE OF SALEM HARBOR AND STATE LINE

In August 2012, Dominion completed the sale of Salem Harbor. In the second quarter of 2012, the assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell. Also during the second quarter of 2012, Dominion completed the sale of State Line, which ceased operations in March 2012. See Note 6 for impairments related to these power stations.

The following table presents selected information regarding the results of operations of Salem Harbor and State Line, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income:

 

Year Ended December 31,    2012  
(millions)       

Operating revenue

   $ 57   

Loss before income taxes

     (49

Dominion and Dominion Gas

BLUE RACER

See Note 9 for a discussion of transactions related to Blue Racer.

MARCELLUS ACREAGE

See Note 10 for a discussion of assignments of Marcellus acreage.

 

 

NOTE 4. OPERATING REVENUE

The Companies’ operating revenue consists of the following:

 

Year Ended December 31,    2014      2013      2012  
(millions)                     

Dominion

        

Electric sales:

        

Regulated

   $ 7,460       $ 7,193       $ 7,102   

Nonregulated

     1,839         2,511         2,483   

Gas sales:

        

Regulated

     334         323         250   

Nonregulated

     751         930         1,071   

Gas transportation and storage

     1,543         1,535         1,401   

Other

     509         628         528   

Total operating revenue

   $ 12,436       $ 13,120       $ 12,835   

Virginia Power

        

Regulated electric sales

   $ 7,460       $ 7,193       $ 7,102   

Other

     119         102         124   

Total operating revenue

   $ 7,579       $ 7,295       $ 7,226   

Dominion Gas

        

Gas sales:

        

Regulated

   $ 209       $ 202       $ 138   

Nonregulated

     26         32         28   

Gas transportation and storage

     1,353         1,338         1,188   

NGL revenue

     212         292         275   

Other

     98         73         48   

Total operating revenue

   $ 1,898       $ 1,937       $ 1,677   
 

 

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NOTE 5. 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. The Companies are routinely audited by federal and state tax authorities. 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.

In December 2014, U.S. federal legislation was enacted that provides an extension of the 50% bonus depreciation allowance for qualifying capital expenditures incurred through 2014.

Continuing Operations

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

 

     Dominion     Virginia Power     Dominion Gas  
Year Ended December 31,   2014     2013     2012     2014     2013     2012     2014     2013     2012  
(millions)                                                      

Current:

                 

Federal

  $ (11   $ 317      $ 43      $ 85      $ 357      $ 70      $ 86      $ 158      $ (8

State

    14        110        84        67        62        81        32        41        2   

Total current expense (benefit)

    3        427        127        152        419        151        118        199        (6

Deferred:

                 

Federal

                 

Taxes before operating loss carryforwards and investment tax credits

    956        563        645        381        224        482        192        92        257   

Tax benefit of operating loss carryforwards

    (352     (18                                                 

Investment tax credits

    (152     (48                                                 

State

    (2     (31     40        16        17        21        24        10        37   

Total deferred expense

    450        466        685        397        241        503        216        102        294   

Amortization of deferred investment tax credits

    (1     (1     (1     (1     (1     (1                     

Total income tax expense

  $ 452      $ 892      $ 811      $ 548      $ 659      $ 653      $ 334      $ 301      $ 288   
 

 

For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows:

 

      Dominion     Virginia Power     Dominion Gas  
Year Ended December 31,    2014     2013     2012     2014     2013     2012     2014     2013      2012  

U.S. statutory rate

     35.0     35.0     35.0     35.0     35.0     35.0     35.0     35.0      35.0

Increases (reductions) resulting from:

                   

State taxes, net of federal benefit

            2.1        4.2        3.8        3.1        3.9        4.4        4.3         3.4   

Investment tax credits

     (8.6     (1.8                                                  

Production tax credits

     (1.2     (0.6     (0.5     (0.6     (0.2                             

Valuation allowances

     0.7        (0.1     (0.7                                           

AFUDC - equity

            (0.6     (0.9            (0.8     (0.9            (0.1      (0.6

Employee stock ownership plan deduction

     (0.9     (0.6     (0.7                                           

Other, net

     0.4        (0.4     (0.6     0.8        (0.4     0.3        0.1        0.3         0.7   

Effective tax rate

     25.4     33.0     35.8     39.0     36.7     38.3     39.5     39.5      38.5

Dominion’s effective tax rate in 2014 reflects the recognition of state tax credits and previously unrecognized tax benefits due to the expiration of statutes of limitations.

 

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The Companies’ deferred income taxes consist of the following:

 

     Dominion     Virginia Power     Dominion Gas  
At December 31,   2014     2013     2014     2013     2014     2013  
(millions)                                    

Deferred income taxes:

           

Total deferred income tax assets

  $ 2,023      $ 2,142      $ 500      $ 462      $ 227      $ 216   

Total deferred income tax liabilities

    8,663        8,463        4,915        4,498        2,289        2,103   

Total net deferred income tax liabilities

  $ 6,640      $ 6,321      $ 4,415      $ 4,036      $ 2,062      $ 1,887   

Total deferred income taxes:

           

Plant and equipment, primarily depreciation method and basis differences

  $ 5,895      $ 5,383      $ 3,965      $ 3,628      $ 1,417      $ 1,266   

Nuclear decommissioning

    1,241        1,136        474        441                 

Deferred state income taxes

    659        606        299        285        207        182   

Federal benefit of deferred state income taxes

    (231     (212     (105     (100     (72     (64

Deferred fuel, purchased energy and gas costs

    27        (33     18        (50     7        13   

Pension benefits

    272        435        (77     (52     567        522   

Other postretirement benefits

    (17     (78     13        (3     (12     (13

Loss and credit carryforwards

    (1,434     (797     (116     (106     (10     (10

Valuation allowances

    87        69                               

Partnership basis differences

    304        125                      42        42   

Other

    (163     (313     (56     (7     (84     (51

Total net deferred income tax liabilities

  $ 6,640      $ 6,321      $ 4,415      $ 4,036      $ 2,062      $ 1,887   

At December 31, 2014, Dominion had the following deductible loss and credit carryforwards:

   

Federal loss carryforwards of $2.2 billion that expire if unutilized during the period 2021 through 2034;

   

Federal investment tax credits of $245 million that expire if unutilized during the period 2033 through 2034;

   

Federal production and other tax credits of $65 million that expire if unutilized during the period 2031 through 2034;

   

State loss carryforwards of $1.7 billion that expire if unutilized during the period 2018 through 2034. A valuation allowance on $962 million of these carryforwards has been established;

   

State minimum tax credits of $194 million that do not expire; and

   

State investment tax credits of $29 million that expire if unutilized during the period 2016 through 2019.

At December 31, 2014, Virginia Power had the following deductible loss and credit carryforwards:

   

Federal loss carryforwards of $279 million that expire if unutilized during the period 2031 through 2033; and

   

Federal production and other tax credits of $14 million that expire if unutilized during the period 2031 through 2034.

At December 31, 2014, Dominion Gas had the following deductible loss carryforwards:

   

Federal loss carryforwards of $25 million that expire if unutilized during the period 2031 through 2033; and

   

State loss carryforwards of $4 million that expire if unutilized during the period 2031 through 2032.

Dominion Gas had no credit carryforwards at December 31, 2014.

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:

 

     Dominion     Virginia Power     Dominion Gas  
     2014     2013     2012     2014     2013     2012     2014     2013     2012  
(millions)                                                      

Balance at January 1

  $ 222      $ 293      $ 347      $ 39      $ 57      $ 114      $ 29      $ 30      $ 30   

Increases-prior period positions

    24        17        28        2        12        4                        

Decreases-prior period positions

    (26     (99     (106     (16     (42     (80            (1       

Increases-current period positions

    16        30        43        11        14        24                        

Decreases-current period positions

           (5                                                 

Settlements with tax authorities

           (2     (4            (2     (4                     

Expiration of statutes of limitations

    (91     (12     (15                   (1                     

Balance at December 31

  $ 145      $ 222      $ 293      $ 36      $ 39      $ 57      $ 29      $ 29      $ 30   

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. 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. For Dominion and its subsidiaries, these unrecognized tax benefits were $77 million, $126 million and $167 million at December 31, 2014, 2013 and 2012, respectively. For Dominion, the change in these unrecognized tax benefits decreased income tax expense by $47 million and $29 million in 2014 and 2013, respectively, and increased income tax expense by $1 million in 2012. For Virginia Power, these unrecognized tax benefits were $8 million at December 31, 2014 and 2013, and $13 million at December 31, 2012. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by less than $1 million in 2014, and increased income tax expense by $4 million and $1 million in 2013 and 2012, respectively. For Dominion Gas, these unrecognized tax benefits were $19 million at December 31, 2014 and 2013 and $20 million at December 31, 2012. For Dominion Gas, the change in these unrecognized tax benefits affected income tax expense by less than $1 million in 2014, 2013 and 2012.

In January 2012, the Appellate Division of the IRS informed Dominion that the Joint Committee had completed its review of the settlement of tax years 2004 and 2005 for Dominion and its consolidated subsidiaries. Since the measurement of unrecognized tax benefits in 2011 considered the results of completed settlement negotiations, Dominion’s results of operations in 2012 were not affected.

In April 2012, the IRS issued its Revenue Agent Report for Dominion’s consolidated tax returns for tax years 2006 and 2007, reflecting the resolution of all issues except one that was subsequently settled in 2012.

 

 

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The IRS examination of tax years 2008, 2009, 2010 and 2011 concluded in late 2013, resulting in a payment of $46 million, and an adjustment to a refund previously received by Dominion for its carryback of 2008 losses to 2007. The loss carryback, as adjusted, was submitted to the Joint Committee for review. Early in 2014, Dominion received notification that the matter had been resolved with no further adjustments. Accordingly, the earliest tax year remaining open for examination of Dominion’s federal tax returns is 2012.

Effective for its 2014 tax year, Dominion has been accepted into the CAP. The CAP is a method of identifying and resolving tax issues through open, cooperative, and transparent interaction between the IRS and taxpayers prior to the filing of a return. Through the CAP, Dominion will have the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions accepted by the IRS. Under a Pre-CAP plan, the IRS audit of tax years 2012 and 2013 began in early 2014.

It is reasonably possible that settlement negotiations and expiration of statutes of limitations could result in a decrease in unrecognized tax benefits in 2015 by up to $30 million for Dominion and up to $25 million for Virginia Power. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by up to $10 million for Dominion and $7 million for Virginia Power.

Otherwise, with regard to 2014 and prior years, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2015.

After considering the possibility of potential changes in the status of its remaining unrecognized tax benefits, Dominion Gas has concluded that no significant changes are reasonably possible to occur in 2015.

For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows:

 

State    Earliest
Open Tax
Year
 

Pennsylvania(1)

     2010   

Connecticut

     2011   

Virginia(2)

     2011   

West Virginia(1)

     2011   

New York(1)

     2007   
(1) Considered a major state for Dominion Gas’ operations.
(2) Considered a major state for Virginia Power’s operations.

The Companies are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are subject to examination.

Discontinued Operations

Details of income tax expense for Dominion’s discontinued operations were as follows:

 

Year Ended December 31,    2013     2012  
(millions)             

Current:

    

Federal

   $ (274   $ (248

State

     (41     (6

Total current benefit

     (315     (254

Deferred:

    

Federal

     232        (368

State

     40        (70

Total deferred expense (benefit)

     272        (438

Total income tax benefit

   $ (43   $ (692

Dominion’s effective tax rate for 2013 reflects the impact of goodwill written off in the sale of Kincaid and Brayton Point that is not deductible for tax purposes.

 

 

 

NOTE 6. FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion and Virginia Power apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, and nuclear decommissioning trust and other investments including those held in Dominion’s rabbi, pension and other postretirement benefit plan trusts, in accordance with the requirements described above. Dominion Gas applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments and investments held in pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above. These credit adjustments are currently not material to the derivative fair values.

 

 

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Inputs and Assumptions

The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, the Companies consider 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 the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the Companies must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect their market assumptions.

The Companies’ commodity derivative valuations are prepared by Dominion’s ERM department. The ERM department reports directly to Dominion’s CFO. The ERM department creates daily mark-to-market valuations for the Companies’ derivative transactions using computer-based statistical models. The inputs that go into the market valuations are transactional information stored in the systems of record and market pricing information that resides in data warehouse databases. The majority of forward prices are automatically uploaded into the data warehouse databases from various third-party sources. Inputs obtained from third-party sources are evaluated for reliability considering the reputation, independence, market presence, and methodology used by the third-party. If forward prices are not available from third-party sources, then the ERM department models the forward prices based on other available market data. A team consisting of risk management and risk quantitative analysts meets each business day to assess the validity of market prices and mark-to-market valuations. During this meeting, the changes in mark-to-market valuations from period to period are examined and qualified against historical expectations. If any discrepancies are identified during this process, the mark-to-market valuations or the market pricing information is evaluated further and adjusted, if necessary.

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, Dominion and Virginia Power generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. Dominion and Virginia Power use other option models under special circumstances, including a Spread Approximation Model when contracts include different commodities or commodity locations and a Swing Option Model when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, Dominion and Virginia Power may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.

The inputs and assumptions used in measuring fair value include the following:

For commodity and foreign currency derivative contracts:

 

  Ÿ  

Forward commodity prices

  Ÿ  

Forward foreign currency prices

  Ÿ  

Transaction prices

  Ÿ  

Price volatility

  Ÿ  

Price correlation

  Ÿ  

Volumes

  Ÿ  

Commodity location

  Ÿ  

Interest rates

  Ÿ  

Credit quality of counterparties and the Companies

  Ÿ  

Credit enhancements

  Ÿ  

Time value

For interest rate derivative contracts:

  Ÿ  

Interest rate curves

  Ÿ  

Credit quality of counterparties and the Companies

  Ÿ  

Volumes

  Ÿ  

Credit enhancements

  Ÿ  

Time value

For investments:

  Ÿ  

Quoted securities prices and indices

  Ÿ  

Securities trading information including volume and restrictions

  Ÿ  

Maturity

  Ÿ  

Interest rates

  Ÿ  

Credit quality

  Ÿ  

NAV (for alternative investments and common/collective trust funds)

The Companies regularly evaluate and validate the inputs used to estimate fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities and investments in which the Companies transact.

Levels

The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

Ÿ  

Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as certain exchange-traded derivatives, and exchange-listed equities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion and Virginia Power, benefit plan trust funds for Dominion and Dominion Gas, and rabbi trust funds for Dominion.

Ÿ  

Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

   

primarily include commodity forwards and swaps, interest rate swaps, restricted cash equivalents, and certain Treasury securities, money market funds, common/collective trust funds, and corporate, state and municipal debt securities held in nuclear decommissioning trust funds for Dominion and Virginia Power, benefit plan trust funds for Dominion and Dominion Gas, and rabbi trust funds for Dominion.

Ÿ  

Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, NGLs, natural gas peaking options and other modeled commodity derivatives. Additional instruments categorized in Level 3 for Dominion and Dominion Gas include alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments, held in benefit plan trust funds.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

For derivative contracts, the Companies recognize transfers among Level 1, Level 2 and Level 3 based on fair values as of the first day of the month in which the transfer occurs. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.

Level 3 Valuations

Fair value measurements are categorized as Level 3 when a significant amount of price or other inputs that are considered to be unobservable are used in their valuations. Long-dated commodity derivatives are generally based on unobservable inputs due to the length of time to settlement and the absence of market activity and are therefore categorized as Level 3. For NGL derivatives, market illiquidity requires a valuation based on proxy markets that do not always correlate to the actual instrument, therefore they are categorized as Level 3. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from ISO auctions, which are generally not considered to be liquid markets. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets. Alternative investments are categorized as Level 3 due to the absence of quoted market prices, illiquidity and the long-term nature of these assets. These investments are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date.

The Companies enter into certain physical and financial forwards, futures, options and swaps, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards and futures contracts. An option model is used to value Level 3 physical and financial options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices, and volumes. For Level 3 fair value measurements, forward market prices, credit spreads and implied price volatilities are considered unobservable. The unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.

 

 

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The following table presents Dominion’s and Dominion Gas’ quantitative information about Level 3 fair value measurements at December 31, 2014. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility and credit spreads.

 

      Fair Value (millions)      Valuation Techniques      Unobservable Input           Range      Weighted
Average(1)
 

Assets:

                

Physical and Financial Forwards and Futures:

                

Natural Gas(2)

   $ 74         Discounted Cash Flow         Market Price (per Dth)      (4)      (2) – 11         (1
           Credit Spread      (6)      1% – 5%         2

FTRs

     44         Discounted Cash Flow         Market Price (per MWh)      (4)      (1) – 21         3   

NGLs(3)

     2         Discounted Cash Flow         Market Price (per Gal)      (4)      0 – 2         1   

Physical and Financial Options:

                

Natural Gas

     5         Option Model         Market Price (per Dth)      (4)      2 – 4         3   
           Price Volatility      (5)      19% – 67%         33

Total assets

   $ 125                                           

Liabilities:

                

Physical and Financial Forwards and Futures:

                

Natural Gas(2)

   $ 12         Discounted Cash Flow         Market Price (per Dth)      (4)      (2) – 4         2   

FTRs

     4         Discounted Cash Flow         Market Price (per MWh)      (4)      (21) – 21           

Physical and Financial Options:

                

Natural Gas

     2         Option Model         Market Price (per Dth)      (4)      2 – 4         3   
                         Price Volatility      (5)      19% – 67%         33

Total liabilities

   $ 18                                           

 

(1) Averages weighted by volume.
(2) Includes basis.
(3) Information represents Dominion Gas’ quantitative information about Level 3 fair value measurements.
(4) Represents market prices beyond defined terms for Levels 1 and 2.
(5) Represents volatilities unrepresented in published markets.
(6) Represents credit spreads unrepresented in published markets.

 

Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

 

Significant Unobservable
Inputs
   Position    Change to Input    Impact on Fair Value
Measurement
 

Market Price

   Buy    Increase (decrease)      Gain (loss)   

Market Price

   Sell    Increase (decrease)      Loss (gain)   

Price Volatility

   Buy    Increase (decrease)      Gain (loss)   

Price Volatility

   Sell    Increase (decrease)      Loss (gain)   

Credit Spread

   Asset    Increase (decrease)      Loss (gain)   

Nonrecurring Fair Value Measurements

DOMINION GAS

Natural Gas Assets

In the fourth quarter of 2014, Dominion Gas recorded an impairment charge of $9 million ($6 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write off previously capitalized costs following the cancellation of a development project.

In June 2013, Dominion Gas purchased certain natural gas infrastructure facilities that were previously leased from third parties. The purchase price was based on terms in the lease, which exceeded current market pricing. As a result of the purchase price and expected losses, Dominion Gas recorded an impairment charge of $49 million ($29 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write down the long-lived assets to their estimated fair values of less than $1 million. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion Gas used the income approach (discounted cash flows)

to estimate the fair value of the assets in this impairment test. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs, including estimates of future production and other commodity prices.

Also in June 2013, Dominion Gas recorded an impairment charge of $6 million ($4 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write off previously capitalized costs following the cancellation of two development projects.

DOMINION

Merchant Power Stations

In the third quarter of 2012, Dominion decided to pursue the sale of Brayton Point and Kincaid, as well as its 50% interest in Elwood, which is an equity method investment. Since Dominion was unlikely to operate the Brayton Point and Kincaid facilities through their estimated useful lives, Dominion evaluated these power stations for recoverability under a probability weighted approach and concluded that the carrying values of these facilities were not impaired as of September 30, 2012.

At December 31, 2012, Dominion updated its recoverability analysis for Brayton Point and Kincaid to reflect bids received and an updated probability weighting. As a result of this updated evaluation, Dominion recorded an impairment charge of approximately $1.6 billion ($1.0 billion after-tax), which is included in loss from discontinued operations in its Consolidated Statement of Income, to write down Brayton Point’s and Kincaid’s long-lived assets to their estimated fair value of approximately $216 million. Dominion used a market approach to estimate the fair value of Brayton Point’s and Kincaid’s long-lived assets. This was considered a Level 2 fair value measurement given it was based on bids received.

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

See Note 3 for information regarding the sale of Brayton Point, Kincaid and Dominion’s equity method investment in Elwood, including an additional impairment.

In April 2011, Dominion announced it would pursue a sale of Kewaunee since it was not able to move forward with its original plan to grow its nuclear fleet in the Midwest to take advantage of economies of scale. Dominion was unable to find a buyer for the facility. In addition, the power purchase agreements for the two utilities that contracted to buy Kewaunee’s generation expired in December 2013 at a time of low wholesale electricity prices in the region. At September 30, 2012, Dominion expected that it would permanently cease generation operations at Kewaunee in 2013 and commence decommissioning of the facility. As a result, Dominion evaluated Kewaunee for impairment since it was more likely than not that Kewaunee would be retired before the end of its previously estimated useful life. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of Kewaunee’s long-lived assets. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs including estimates of future power and other commodity prices.

As a result of this evaluation in September 2012, Dominion recorded impairment and other charges of $435 million ($281 million after-tax) largely reflected in other operations and maintenance expense in its Consolidated Statement of Income. This primarily reflects a $378 million ($244 million after-tax) charge for the full impairment of Kewaunee’s long-lived assets, a write down of materials and supplies inventories of $33 million ($21 million after-tax), and a $24 million ($16 million after-tax) charge related to severance costs.

The decision to decommission Kewaunee was approved by Dominion’s Board of Directors in October 2012 after consideration of the factors discussed above, which made it uneconomic for Kewaunee to continue operations. Kewaunee ceased operations and decommissioning activities commenced in May 2013.

In the second quarter of 2012, an agreement was reached to sell Salem Harbor and the assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell. This resulted in a pre-tax charge of $27 million ($16 million after-tax), which is included in loss from discontinued operations in Dominion’s Consolidated Statement of Income. This was considered a Level 2 fair value measurement as it was based on the negotiated sales price. Salem Harbor was sold in the third quarter of 2012.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion’s and Dominion Gas’ pension and other postretirement benefit plans are presented in Note 21.

DOMINION

The following table presents Dominion’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

 

      Level 1      Level 2      Level 3      Total  
(millions)                            

At December 31, 2014

           

Assets:

           

Derivatives:

           

Commodity

   $ 3       $ 567       $ 125       $ 695   

Interest rate

             24                 24   

Investments(1):

           

Equity securities:

           

U.S.:

           

Large Cap

     2,669                         2,669   

Other

     6                         6   

Non-U.S.:

           

Large Cap

     12                         12   

Fixed Income:

           

Corporate debt instruments

             441                 441   

U.S. Treasury securities and agency debentures

     419         190                 609   

State and municipal

             395                 395   

Other

             74                 74   

Cash equivalents and other

     3         10                 13   

Total assets

   $ 3,112       $ 1,701       $ 125       $ 4,938   

Liabilities:

           

Derivatives:

           

Commodity

   $ 3       $ 571       $ 18       $ 592   

Interest rate

             202                 202   

Total liabilities

   $ 3       $ 773       $ 18       $ 794   

At December 31, 2013

           

Assets:

           

Derivatives:

           

Commodity

   $ 3       $ 718       $ 32       $ 753   

Interest rate

             137                 137   

Investments(1):

           

Equity securities:

           

U.S.:

           

Large Cap

     2,417                         2,417   

Other

     79                         79   

Non-U.S.:

           

Large Cap

     13                         13   

Fixed Income:

           

Corporate debt instruments

             345                 345   

U.S. Treasury securities and agency debentures

     415         175                 590   

State and municipal

             343                 343   

Other

             3                 3   

Cash equivalents and other

             103                 103   

Restricted cash equivalents

             8                 8   

Total assets

   $ 2,927       $ 1,832       $ 32       $ 4,791   

Liabilities:

           

Derivatives:

           

Commodity

   $ 3       $ 1,051       $ 48       $ 1,102   

Total liabilities

   $ 3       $ 1,051       $ 48       $ 1,102   

 

(1) Includes investments held in the nuclear decommissioning and rabbi trusts.
 

 

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The following table presents the net change in Dominion’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:

 

      2014     2013     2012  
(millions)                   

Balance at January 1,

   $ (16   $ 25      $ (71

Total realized and unrealized gains (losses):

      

Included in earnings

     97        (9     (15

Included in other comprehensive income (loss)

     7        1        101   

Included in regulatory assets/liabilities

     109        (9     30   

Settlements

     (88     (23     47   

Transfers out of Level 3

     (2     (1     (67

Balance at December 31,

   $ 107      $ (16   $ 25   

The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date

   $ 6      $      $ 42   

The following table presents Dominion’s gains and losses included in earnings in the Level 3 fair value category:

 

     Operating
Revenue
    Electric Fuel
and Energy
Purchases
    Purchased
Gas
    Total  
(millions)                        

Year Ended December 31, 2014

       

Total gains (losses) included in earnings

  $ 4      $ 97      $ (4   $ 97   

The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date

    4        1        1        6   

Year Ended December 31, 2013

       

Total gains (losses) included in earnings

  $ 11      $ (19   $ (1   $ (9

The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date

    1               (1       

Year Ended December 31, 2012

       

Total gains (losses) included in earnings

  $ 35      $ (50   $      $ (15

The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date

    42                      42   
 

 

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VIRGINIA POWER

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2014. The range and weighted average are presented in dollars for market price inputs and percentages for credit spreads.

 

      Fair Value
(millions)
     Valuation Techniques      Unobservable Input      Range      Weighted  Average(1)  

Assets:

              

Physical and Financial Forwards and Futures:

              

FTRs

   $ 44         Discounted Cash Flow         Market Price (per MWh)(3)         (1) – 21         3   

Natural gas(2)

     62         Discounted Cash Flow         Market Price (per Dth)(3)         (2) – 7         (1
                         Credit Spread(4)         1% – 5%         2

Total assets

   $ 106                                       

Liabilities:

              

Physical and Financial Forwards and Futures:

              

FTRs

   $ 4         Discounted Cash Flow         Market Price (per MWh)(3)         (21) – 21           

Total liabilities

   $ 4                                       

 

(1) Averages weighted by volume.
(2) Includes basis.
(3) Represents market prices beyond defined terms for Levels 1 and 2.
(4) Represents credit spreads unrepresented in published markets.

 

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Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

 

Significant Unobservable
Inputs
   Position    Change to Input    Impact on Fair Value
Measurement
 

Market Price

   Buy    Increase (decrease)      Gain (loss)   

Market Price

   Sell    Increase (decrease)      Loss (gain)   

Credit Spread

   Asset    Increase (decrease)      Loss (gain)   

The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

 

      Level 1      Level 2      Level 3      Total  
(millions)                            

At December 31, 2014

           

Assets:

           

Derivatives:

           

Commodity

   $       $ 7       $ 106       $ 113   

Investments(1):

           

Equity securities:

           

U.S.:

           

Large Cap

     1,157                         1,157   

Fixed Income:

           

Corporate debt instruments

             250                 250   

U.S. Treasury securities and agency debentures

     137         61                 198   

State and municipal

             211                 211   

Other

             23                 23   

Total assets

   $ 1,294       $ 552       $ 106       $ 1,952   

Liabilities:

           

Derivatives:

           

Commodity

   $       $ 11       $ 4       $ 15   

Interest rate

             72                 72   

Total liabilities

   $       $ 83       $ 4       $ 87   

At December 31, 2013

           

Assets:

           

Derivatives:

           

Commodity

   $       $ 3       $ 2       $ 5   

Interest rate

             48                 48   

Investments(1):

           

Equity securities:

           

U.S.:

           

Large Cap

     1,021                         1,021   

Other

     36                         36   

Fixed Income:

           

Corporate debt instruments

             191                 191   

U.S. Treasury securities and agency debentures

     146         66                 212   

State and municipal

             164                 164   

Cash equivalents and other

             31                 31   

Restricted cash equivalents

             8                 8   

Total assets

   $ 1,203       $ 511       $ 2       $ 1,716   

Liabilities:

           

Derivatives:

           

Commodity

   $       $ 3       $ 9       $ 12   

Total liabilities

   $       $ 3       $ 9       $ 12   

 

(1) Includes investments held in the nuclear decommissioning and rabbi trusts.

 

The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:

 

      2014     2013     2012  
(millions)                   

Balance at January 1,

   $ (7   $ 2      $ (28

Total realized and unrealized gains (losses):

      

Included in earnings

     96        (17     (50

Included in regulatory assets/liabilities

     109        (9     30   

Settlements

     (96     17        50   

Balance at December 31,

   $ 102      $ (7   $ 2   

The gains and losses included in earnings in the Level 3 fair value category were classified in electric fuel and other energy-related purchases expense in Virginia Power’s Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2014, 2013 and 2012.

DOMINION GAS

The following table presents Dominion Gas’ assets and liabilities for commodity and interest rate derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

 

      Level 1      Level 2      Level 3      Total  
(millions)       

At December 31, 2014

  

Assets:

  

Commodity

   $       $       $ 2       $ 2   

Total assets

   $       $       $ 2       $ 2   

Liabilities:

  

Interest rate

   $       $ 9       $       $ 9   

Total liabilities

   $       $ 9       $       $ 9   

At December 31, 2013

  

Assets:

  

Commodity

   $       $       $ 6       $ 6   

Interest rate

             34                 34   

Total assets

   $       $ 34       $ 6       $ 40   

Liabilities:

  

Commodity

   $       $ 13       $ 12       $ 25   

Total liabilities

   $       $ 13       $ 12       $ 25   

 

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

The following table presents the net change in Dominion Gas’ derivative assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:

 

      2014     2013     2012  
(millions)                   

Balance at January 1,

   $ (6   $ (12   $ (98

Total realized and unrealized gains (losses):

      

Included in earnings

     2        1        (15

Included in other comprehensive income (loss)

     10        3        86   

Settlements

     (4     2        15   

Balance at December 31,

   $ 2      $ (6   $ (12

The gains and losses included in earnings in the Level 3 fair value category were classified in operating revenue in Dominion Gas’ Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2014, 2013 and 2012.

Fair Value of Financial Instruments

Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, restricted cash (which is recorded in other current assets), customer and other receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies’ financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

 

At December 31,   2014     2013  
     Carrying
Amount
    Estimated
Fair  Value(1)
    Carrying
Amount
    Estimated
Fair Value(1)
 
(millions)                        

Dominion

       

Long-term debt, including securities due within one year(2)

  $ 19,723      $ 21,881      $ 18,396      $ 19,887   

Junior subordinated notes(3)

    1,374        1,396        1,373        1,394   

Remarketable subordinated notes(3)

    2,083        2,362        1,080        1,192   

Subsidiary preferred stock(4)

                  257        261   

Virginia Power

       

Long-term debt, including securities due within one year(3)

  $ 8,937      $ 10,293      $ 8,032      $ 8,897   

Preferred stock(4)

                  257        261   

Dominion Gas

       

Long-term debt(3)

  $ 2,594      $ 2,672      $ 1,198      $ 1,169   

 

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.
(2) Carrying amount includes amounts which represent the unamortized discount and/or premium. At December 31, 2014, and 2013, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt, of approximately $19 million and $55 million, respectively.
(3) Carrying amount includes amounts which represent the unamortized discount and/or premium.
(4) Includes deferred issuance expenses of $2 million at December 31, 2013. See Note 18 for information about the redemption of preferred stock in 2014.
 

 

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NOTE 7. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES

The Companies are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as currency exchange and interest rate risks of their business operations. The Companies use derivative instruments to manage exposure to these risks, and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes. As discussed in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivatives are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives.

Derivative assets and liabilities are presented gross on the Companies’ Consolidated Balance Sheets. Dominion’s and Virginia Power’s derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Dominion Gas’ derivative contracts include over-the-

counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions.

In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and in some cases other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on the Companies’ Consolidated Balance Sheets, as well as letters of credit and other forms of security, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure.

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

DOMINION

Balance Sheet Presentation

The tables below present Dominion’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:

 

      December 31, 2014      December 31, 2013  
      Gross
Amounts of
Recognized
Assets
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Assets
Presented in the
Consolidated
Balance Sheet
     Gross
Amounts of
Recognized
Assets
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Assets
Presented in the
Consolidated
Balance Sheet
 
(millions)                                   

Interest rate contracts:

              

Over-the-counter

   $ 24       $       $ 24       $ 137       $       $ 137   

Commodity contracts:

              

Over-the-counter

     382                 382         240                 240   

Exchange

     298                 298         506                 506   

Total derivatives, subject to a master netting or similar arrangement

     704                 704         883                 883   

Total derivatives, not subject to a master netting or similar arrangement

     15                 15         7                 7   

Total

   $ 719       $       $ 719       $ 890       $       $ 890   

 

              December 31, 2014              December 31, 2013  
              Gross Amounts Not Offset in the
Consolidated Balance Sheet
             Gross Amounts Not Offset in the
Consolidated Balance Sheet
 
      Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet
     Financial
Instruments
     Cash
Collateral
Received
     Net
Amounts
     Net Amounts of
Assets Presented in
the Consolidated
Balance Sheet
     Financial
Instruments
     Cash
Collateral
Received
     Net
Amounts
 
(millions)                                                 

Interest rate contracts:

                    

Over-the-counter

   $ 24       $ 16       $       $ 8       $ 137       $       $       $ 137   

Commodity contracts:

                    

Over-the-counter

     382         34         34         314         240         63                 177   

Exchange

     298         298                         506         505                 1   

Total

   $ 704       $ 348       $ 34       $ 322       $ 883       $ 568       $       $ 315   

 

      December 31, 2014      December 31, 2013  
      Gross
Amounts of
Recognized
Liabilities
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet
     Gross
Amounts of
Recognized
Liabilities
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet
 
(millions)                                   

Interest rate contracts:

              

Over-the-counter

   $ 202       $       $ 202       $       $       $   

Commodity contracts:

              

Over-the-counter

     87                 87         262                 262   

Exchange

     493                 493         838                 838   

Total derivatives, subject to a master netting or similar arrangement

     782                 782         1,100                 1,100   

Total derivatives, not subject to a master netting or similar arrangement

     12                 12         2                 2   

Total

   $ 794       $       $ 794       $ 1,102       $       $ 1,102   

 

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              December 31, 2014              December 31, 2013  
              Gross Amounts Not Offset
in the Consolidated Balance
Sheet
             Gross Amounts Not Offset in
the Consolidated Balance
Sheet
 
      Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet
     Financial
Instruments
     Cash
Collateral
Paid
     Net
Amounts
     Net Amounts of
Liabilities Presented
in the Consolidated
Balance Sheet
     Financial
Instruments
     Cash Collateral
Paid
     Net Amounts  
(millions)                                                        

Interest rate contracts:

                       

Over-the-counter

   $ 202       $ 16       $       $ 186       $       $       $       $   

Commodity contracts:

                       

Over-the-counter

     87         34         1         52         262         63         69         130   

Exchange

     493         298         195                 838         505         333           

Total

   $ 782       $ 348       $ 196       $ 238       $ 1,100       $ 568       $ 402       $ 130   

 

Volumes

The following table presents the volume of Dominion’s derivative activity as of December 31, 2014. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

 

      Current      Noncurrent  

Natural Gas (bcf):

     

Fixed price(1)

     52         13   

Basis

     227         575   

Electricity (MWh):

     

Fixed price

     14,689,432         6,148,800   

FTRs

     35,786,150           

Capacity (MW)

     10,700         7,600   

Liquids (Gals)(2)

     39,984,000         1,260,000   

Interest rate

   $ 1,300,000,000       $ 4,450,000,000   

 

(1) Includes options.
(2) Includes NGLs and oil.

Ineffectiveness and AOCI

For the years ended December 31, 2014, 2013 and 2012, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at December 31, 2014:

 

      AOCI
After-Tax
    Amounts Expected to
be Reclassified
to Earnings during
the next 12
Months After-Tax
    Maximum
Term
 
(millions)                   

Commodities:

      

Gas

   $ (8   $ (7     27 months   

Electricity

     56        46        24 months   

Other

                   17 months   

Interest rate

     (226     (6     384 months   

Total

   $ (178   $ 33           

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Dominion’s derivatives and where they are presented in its Consolidated Balance Sheets:

 

      Fair Value  -
Derivatives
under
Hedge
Accounting
     Fair Value -
Derivatives
not under
Hedge
Accounting
     Total
Fair
Value
 
(millions)                     

At December 31, 2014

        

ASSETS

        

Current Assets

        

Commodity

   $ 281       $ 242       $ 523   

Interest rate

     13                 13   

Total current derivative assets

     294         242         536   

Noncurrent Assets

        

Commodity

     71         101         172   

Interest rate

     11                 11   

Total noncurrent derivative assets(1)

     82         101         183   

Total derivative assets

   $ 376       $ 343       $ 719   

LIABILITIES

        

Current Liabilities

        

Commodity

   $ 224       $ 267       $ 491   

Interest rate

     100                 100   

Total current derivative liabilities

     324         267         591   

Noncurrent Liabilities

        

Commodity

     55         46         101   

Interest rate

     102                 102   

Total noncurrent derivative liabilities(2)

     157         46         203   

Total derivative liabilities

   $ 481       $ 313       $ 794   

At December 31, 2013

        

ASSETS

        

Current Assets

        

Commodity

   $ 49       $ 522       $ 571   

Interest rate

     116                 116   

Total current derivative assets

     165         522         687   

Noncurrent Assets

        

Commodity

     28         154         182   

Interest rate

     21                 21   

Total noncurrent derivative assets(1)

     49         154         203   

Total derivative assets

   $ 214       $ 676       $ 890   

LIABILITIES

        

Current Liabilities

        

Commodity

   $ 267       $ 561       $ 828   

Total current derivative liabilities

     267         561         828   

Noncurrent Liabilities

        

Commodity

     119         155         274   

Total noncurrent derivative liabilities(2)

     119         155         274   

Total derivative liabilities

   $ 386       $ 716       $ 1,102   

 

(1) Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheets.
(2) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheets.

The following tables present the gains and losses on Dominion’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:

 

Derivatives in cash flow hedging relationships   Amount of
Gain (Loss)
Recognized
in AOCI on
Derivatives
(Effective
Portion)(1)
    Amount of
Gain (Loss)
Reclassified
from AOCI
to Income
    Increase
(Decrease) in
Derivatives
Subject to
Regulatory
Treatment(2)
 
(millions)                  
Year Ended December 31, 2014                     

Derivative Type and Location of Gains (Losses)

     

Commodity:

     

Operating revenue

    $ (130  

Purchased gas

      (13  

Electric fuel and other energy-related purchases

            7           

Total commodity

  $ 245      $ (136   $ (4

Interest rate(3)

    (208     (16     (81

Total

  $ 37      $ (152   $ (85
Year Ended December 31, 2013                     

Derivative Type and Location of Gains (Losses)

     

Commodity:

     

Operating revenue

    $ (58  

Purchased gas

      (47  

Electric fuel and other energy-related purchases

            (10        

Total commodity

  $ (481   $ (115   $ 5   

Interest rate(3)

    77        (15     81   

Total

  $ (404   $ (130   $ 86   
Year Ended December 31, 2012                     

Derivative Type and Location of Gains (Losses)

     

Commodity:

     

Operating revenue

    $ 188     

Purchased gas

      (75  

Electric fuel and other energy-related purchases

            (17        

Total commodity

  $ 71      $ 96      $ 10   

Interest rate(3)

    (84     (2     (35

Total

  $ (13   $ 94      $ (25

 

(1) Amounts deferred into AOCI have no associated effect in Dominion’s Consolidated Statements of Income.
(2) Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income.
(3) Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges.

 

Derivatives not designated as hedging

instruments

  Amount of Gain (Loss) Recognized in
Income on Derivatives(1)
 
Year Ended December 31,   2014     2013     2012  
(millions)                  

Derivative Type and Location of Gains (Losses)

     

Commodity:

     

Operating revenue

  $ (310   $ (45   $ 168   

Purchased gas

    (51     (9     (14

Electric fuel and other energy-related purchases

    113        (29     (40

Interest rate(2)

                  17   

Total

  $ (248   $ (83   $ 131   
 

 

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Table of Contents

 

 

 

(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income.
(2) Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges.

VIRGINIA POWER

Balance Sheet Presentation

The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:

 

      December 31, 2014      December 31, 2013  
      Gross
Amounts of
Recognized
Assets
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet
     Gross
Amounts of
Recognized
Assets
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet
 
(millions)                                          

Interest rate contracts:

                 

Over-the-counter

   $       $       $       $ 48       $       $ 48   

Commodity contracts:

                 

Over-the-counter

     106                 106         4                 4   

Exchange

                             1                 1   

Total derivatives, subject to a master netting or similar arrangement

     106                 106         53                 53   

Total derivatives, not subject to a master netting or similar arrangement

     7                 7                           

Total

   $ 113       $       $ 113       $ 53       $       $ 53   

 

              December 31, 2014                      December 31, 2013          
              Gross Amounts Not Offset
in the Consolidated Balance
Sheet
                     Gross Amounts Not Offset in
the Consolidated Balance
Sheet
         
      Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet
     Financial
Instruments
     Cash
Collateral
Received
     Net
Amounts
     Net Amounts of
Assets Presented in
the Consolidated
Balance Sheet
     Financial
Instruments
     Cash Collateral
Received
     Net Amounts  
(millions)                                                        

Interest rate contracts:

                       

Over-the-counter

   $       $       $       $       $ 48       $       $       $ 48   

Commodity contracts:

                       

Over-the-counter

     106         4                 102         4         4                   

Exchange

                                     1                         1   

Total

   $ 106       $ 4       $       $ 102       $ 53       $ 4       $       $ 49   

 

      December 31, 2014      December 31, 2013  
      Gross
Amounts of
Recognized
Liabilities
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet
     Gross
Amounts of
Recognized
Liabilities
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet
 
(millions)                                          

Interest rate contracts:

                 

Over-the-counter

   $ 72       $       $ 72       $       $       $   

Commodity contracts:

                 

Over-the-counter

     8                 8         12                 12   

Total derivatives, subject to a master netting or similar arrangement

     80                 80         12                 12   

Total derivatives, not subject to a master netting or similar arrangement

     7                 7                           

Total

   $ 87       $       $ 87       $ 12       $       $ 12   

 

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Table of Contents

Combined Notes to Consolidated Financial Statements, Continued

 

 

 

              December 31, 2014                      December 31, 2013          
              Gross Amounts Not Offset
in the Consolidated Balance
Sheet
                    

Gross Amounts Not Offset

in the Consolidated Balance
Sheet

         
      Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet
     Financial
Instruments
     Cash
Collateral
Paid
     Net
Amounts
     Net Amounts of
Liabilities Presented
in the Consolidated
Balance Sheet
     Financial
Instruments
     Cash Collateral
Paid
     Net Amounts  
(millions)                                                        

Interest rate contracts:

                       

Over-the-counter

   $ 72       $       $       $ 72       $       $       $       $   

Commodity contracts:

                       

Over-the-counter

     8         4                 4         12         4         7         1   

Total

   $ 80       $ 4       $       $ 76       $ 12       $ 4       $ 7       $ 1   

 

Volumes

The following table presents the volume of Virginia Power’s derivative activity at December 31, 2014. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

 

      Current      Noncurrent  

Natural Gas (bcf):

     

Fixed price

     7           

Basis

     51         493   

Electricity (MWh):

     

FTRs

     33,709,386           

Capacity (MW)

     10,700         7,600   

Interest rate

   $ 550,000,000       $ 900,000,000   

Ineffectiveness

For the years ended December 31, 2014, 2013 and 2012, gains or losses on hedging instruments determined to be ineffective were not material.

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:

 

     

Fair Value -

Derivatives

under

Hedge

Accounting

    

Fair Value -

Derivatives

not under

Hedge

Accounting

    

Total

Fair

Value

 
(millions)                     

At December 31, 2014

        

ASSETS

        

Current Assets

        

Commodity

   $       $ 51       $ 51   

Total current derivative assets(1)

             51         51   

Noncurrent Assets

        

Commodity

             62         62   

Total noncurrent derivative assets(2)

             62         62   

Total derivative assets

   $       $ 113       $ 113   

LIABILITIES

        

Current Liabilities

        

Commodity

   $ 3       $ 12       $ 15   

Interest rate

     45                 45   

Total current derivative liabilities

     48         12         60   

Noncurrent Liabilities

        

Interest rate

     27                 27   

Total noncurrent derivative liabilities(3)

     27                 27   

Total derivative liabilities

   $ 75       $ 12       $ 87   

At December 31, 2013

        

ASSETS

        

Current Assets

        

Commodity

   $ 2       $ 3       $ 5   

Interest rate

     48                 48   

Total current derivative assets(1)

     50         3         53   

Total derivative assets

   $ 50       $ 3       $ 53   

LIABILITIES

        

Current Liabilities

        

Commodity

   $ 1       $ 11       $ 12   

Total current derivative liabilities

     1         11         12   

Total derivative liabilities

   $ 1       $ 11       $ 12   

 

(1) Current derivative assets are presented in other current assets in Virginia Power’s Consolidated Balance Sheets.
(2) Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Power’s Consolidated Balance Sheets.
(3) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheets.
 

 

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The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:

 

Derivatives in cash flow hedging

relationships

  

Amount of

Gain (Loss)

Recognized
in AOCI on

Derivatives

(Effective

Portion)(1)

   

Amount of

Gain (Loss)

Reclassified

from AOCI

to Income

   

Increase

(Decrease) in

Derivatives

Subject to

Regulatory

Treatment(2)

 
(millions)                   
Year Ended December 31, 2014                      

Derivative Type and Location of Gains (Losses)

      

Commodity:

      

Electric fuel and other energy-related purchases

           $ 5           

Total commodity

   $ 4      $ 5      $ (4

Interest rate(3)

     (10            (81

Total

   $ (6   $ 5      $ (85
Year Ended December 31, 2013                      

Derivative Type and Location of Gains (Losses)

      

Commodity:

      

Electric fuel and other energy-related purchases

           $           

Total commodity

   $      $      $ 5   

Interest rate(3)

     9               81   

Total

   $ 9      $      $ 86   
Year Ended December 31, 2012                      

Derivative Type and Location of Gains (Losses)

      

Commodity:

      

Electric fuel and other energy-related purchases

           $ (4        

Total commodity

   $ (2   $ (4   $ 10   

Interest rate(3)

     (6            (35

Total

   $ (8   $ (4   $ (25
(1) Amounts deferred into AOCI have no associated effect in Virginia Power’s Consolidated Statements of Income.
(2) Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.
(3) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges.

 

Derivatives not designated as hedging

instruments

   Amount of Gain (Loss) Recognized in
Income on Derivatives(1)
 
Year Ended December 31,    2014      2013     2012  
(millions)                    

Derivative Type and Location of Gains (Losses)

       

Commodity(2)

   $ 105       $ (16   $ (50

Total

   $ 105       $ (16   $ (50

 

(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.
(2) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.
 

 

DOMINION GAS

Balance Sheet Presentation

The tables below present Dominion Gas’ derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:

 

      December 31, 2014      December 31, 2013  
      Gross
Amounts of
Recognized
Assets
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet
    

Gross

Amounts of
Recognized
Assets

     Gross Amounts
Offset in the
Consolidated
Balance Sheet
    

Net Amounts of
Assets Presented

in the Consolidated
Balance Sheet

 
(millions)                                          

Interest rate contracts:

                 

Over-the-counter

   $       $       $       $ 34       $       $ 34   

Commodity contracts:

                 

Over-the-counter

     2                 2         6                 6   

Total derivatives, subject to a master netting or similar arrangement

   $ 2       $       $ 2       $ 40       $       $ 40   

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

              December 31, 2014                      December 31, 2013          
             

Gross Amounts Not Offset
in the Consolidated Balance

Sheet

                    

Gross Amounts Not Offset

in the Consolidated Balance

Sheet

         
      Net Amounts of
Assets Presented
in the Consolidated
Balance Sheet
     Financial
Instruments
     Cash
Collateral
Received
     Net
Amounts
     Net Amounts of
Assets Presented in
the Consolidated
Balance Sheet
     Financial
Instruments
     Cash Collateral
Received
     Net Amounts  
(millions)                                                        

Interest rate contracts:

                       

Over-the-counter

   $       $       $       $       $ 34       $       $       $ 34   

Commodity contracts:

                       

Over-the-counter

     2                         2         6         6                   

Total

   $ 2       $       $       $ 2       $ 40       $ 6       $       $ 34   

 

      December 31, 2014      December 31, 2013  
      Gross
Amounts of
Recognized
Liabilities
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet
     Gross
Amounts of
Recognized
Liabilities
     Gross Amounts
Offset in the
Consolidated
Balance Sheet
     Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet
 
(millions)                                          

Interest rate contracts:

                 

Over-the-counter

   $ 9       $       $ 9       $       $       $   

Commodity contracts:

                 

Over-the-counter

                             25                 25   

Total derivatives, subject to a master netting or similar arrangement

   $ 9       $       $ 9       $ 25       $       $ 25   

 

              December 31, 2014                      December 31, 2013          
              Gross Amounts Not Offset
in the Consolidated Balance
Sheet
                    

Gross Amounts Not Offset

in the Consolidated Balance
Sheet

         
      Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet
     Financial
Instruments
     Cash
Collateral
Paid
     Net
Amounts
    

Net Amounts of

Liabilities Presented
in the Consolidated
Balance Sheet

     Financial
Instruments
     Cash Collateral
Paid
     Net Amounts  
(millions)                                                        

Interest rate contracts:

                       

Over-the-counter

   $ 9       $       $       $ 9       $       $       $       $   

Commodity contracts:

                       

Over-the-counter

                                     25         6                 19   

Total

   $ 9       $       $       $ 9       $ 25       $ 6       $       $ 19   

 

Volumes

The following table presents the volume of Dominion Gas’ derivative activity at December 31, 2014. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

 

      Current      Noncurrent  

NGLs (Gals)

     32,340,000           

Interest rate

   $       $ 250,000,000   

Ineffectiveness and AOCI

For the years ended December 31, 2014, 2013 and 2012, gains or losses on hedging instruments determined to be ineffective were not material.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Gas’ Consolidated Balance Sheet at December 31, 2014:

 

      AOCI
After-Tax
    Amounts Expected
to be Reclassified
to Earnings during
the next 12
Months After-Tax
     Maximum
Term
 
(millions)                    

Commodities:

       

Natural Gas

   $      $         3 months   

NGLs

                    12 months   

Interest rate

     (20             360 months   

Total

   $ (20   $            

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.

 

 

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Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Dominion Gas’ derivatives and where they are presented in its Consolidated Balance Sheets:

 

     

Fair Value -

Derivatives

under

Hedge

Accounting

    

Fair Value -

Derivatives

not under

Hedge

Accounting

    

Total

Fair

Value

 
(millions)                     

At December 31, 2014

        

ASSETS

        

Current Assets

        

Commodity

   $ 2       $       $ 2   

Total current derivative assets(1)

     2                 2   

Total derivative assets

   $ 2       $       $ 2   

LIABILITIES

        

Noncurrent Liabilities

        

Interest rate

   $ 9       $       $ 9   

Total noncurrent derivative liabilities(2)

     9                 9   

Total derivative liabilities

   $ 9       $       $ 9   

At December 31, 2013

        

ASSETS

        

Current Assets

        

Commodity

   $ 6       $       $ 6   

Interest rate

     34                 34   

Total current derivative assets(1)

     40                 40   

Total derivative assets

   $ 40       $       $ 40   

LIABILITIES

        

Current Liabilities

        

Commodity

   $ 25       $       $ 25   

Total current derivative liabilities(3)

     25                 25   

Total derivative liabilities

   $ 25       $       $ 25   

 

(1) Current derivative assets are presented in other current assets in Dominion Gas’ Consolidated Balance Sheets.
(2) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Gas’ Consolidated Balance Sheets.
(3) Current derivative liabilities are presented in other current liabilities in Dominion Gas’ Consolidated Balance Sheets.

The following tables present the gains and losses on Dominion Gas’ derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:

 

Derivatives in cash flow hedging

relationships

  

Amount of Gain

(Loss)

Recognized in

AOCI on

Derivatives

(Effective

Portion)(1)

   

Amount of

Gain (Loss)

Reclassified

from AOCI to

Income

 
(millions)             
Year Ended December 31, 2014               

Derivative Type and Location of Gains (Losses)

    

Commodity:

    

Operating revenue

     $ 2   

Purchased gas

             (14

Total commodity

   $ 12      $ (12

Interest rate(2)

     (62     (1

Total

   $ (50   $ (13
Year Ended December 31, 2013               

Derivative Type and Location of Gains (Losses)

    

Commodity:

    

Operating revenue

     $ (2

Purchased gas

             (14

Total commodity

   $ (2   $ (16

Interest rate(2)

     68          

Total

   $ 66      $ (16
Year Ended December 31, 2012               

Derivative Type and Location of Gains (Losses)

    

Commodity:

    

Operating revenue

     $ (15

Purchased gas

             (18

Total commodity

   $ 64      $ (33

Interest rate(2)

     (41       

Total

   $ 23      $ (33

 

(1) Amounts deferred into AOCI have no associated effect in Dominion Gas’ Consolidated Statements of Income.
(2) Amounts recorded in Dominion Gas’ Consolidated Statements of Income are classified in interest and related charges.
 

 

 

NOTE 8. EARNINGS PER SHARE

The following table presents the calculation of Dominion’s basic and diluted EPS:

 

      2014      2013      2012  
(millions, except EPS)                     

Net income attributable to Dominion

   $ 1,310       $ 1,697       $ 302   

Average shares of common stock outstanding-Basic

     582.7         578.7         572.9   

Net effect of dilutive securities(1)

     1.8         0.8         1.0   

Average shares of common stock outstanding-Diluted

     584.5         579.5         573.9   

Earnings Per Common Share-Basic

   $ 2.25       $ 2.93       $ 0.53   

Earnings Per Common Share-Diluted

   $ 2.24       $ 2.93       $ 0.53   

 

(1) Dilutive securities consist primarily of contingently convertible senior notes and the 2013 Equity Units for 2014 and contingently convertible senior notes for 2013 and 2012. Dominion redeemed all of its contingently convertible senior notes in 2014. See Note 17 for more information.

The 2014 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the year ended December 31, 2014, as the dilutive stock price threshold was not met. The 2013 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the year ended December 31, 2013. See Note 17 for more information. There were no potentially dilutive securities excluded from the calculation of diluted EPS for the year ended December 31, 2012.

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

 

NOTE 9. INVESTMENTS

DOMINION

Equity and Debt Securities

RABBI TRUST SECURITIES

Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled $110 million and $107 million at December 31, 2014 and 2013, respectively. Cost-method investments held in Dominion’s rabbi trusts totaled $6 million and $10 million at December 31, 2014 and 2013, respectively.

DECOMMISSIONING TRUST SECURITIES

Dominion holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below:

 

     

Amortized

Cost

    

Total

Unrealized

Gains(1)

    

Total

Unrealized

Losses(1)

   

Fair

Value

 
(millions)                           

2014

          

Marketable equity securities:

          

U.S. large cap

   $ 1,273       $ 1,353       $      $ 2,626   

Marketable debt securities:

          

Corporate debt instruments

     424         19         (2     441   

U.S. Treasury securities and agency debentures

     597         13         (4     606   

State and municipal

     332         23                355   

Other

     66                        66   

Cost method investments

     86                        86   

Cash equivalents and other(2)

     16                        16   

Total

   $ 2,794       $ 1,408       $ (6 )(3)    $ 4,196   

2013

          

Marketable equity securities:

          

U.S.:

          

Large Cap

   $ 1,183       $ 1,194       $      $ 2,377   

Other

     49         23                72   

Marketable debt securities:

          

Corporate debt instruments

     332         16         (3     345   

U.S. Treasury securities and agency debentures

     589         8         (10     587   

State and municipal

     297         11         (5     303   

Other

     3                        3   

Cost method investments

     106                        106   

Cash equivalents and other(2)

     110                        110   

Total

   $ 2,669       $ 1,252       $ (18 )(3)    $ 3,903   

 

(1) Included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
(2) Includes pending sales of securities of $3 million and $11 million at December 31, 2014 and 2013, respectively.
(3) The fair value of securities in an unrealized loss position was $379 million and $604 million at December 31, 2014 and 2013, respectively.

 

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at December 31, 2014 by contractual maturity is as follows:

 

      Amount  
(millions)       

Due in one year or less

   $ 169   

Due after one year through five years

     390   

Due after five years through ten years

     426   

Due after ten years

     483   

Total

   $ 1,468   

Presented below is selected information regarding Dominion’s marketable equity and debt securities held in nuclear decommissioning trust funds:

 

Year Ended December 31,    2014      2013      2012  
(millions)                     

Proceeds from sales

   $ 1,235       $ 1,476       $ 1,356   

Realized gains(1)

     171         157         98   

Realized losses(1)

     30         33         33   

 

(1) Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.
 

 

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Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:

 

Year Ended December 31,    2014     2013     2012  
(millions)                   

Total other-than-temporary impairment losses(1)

   $ 21      $ 31      $ 26   

Losses recorded to nuclear decommissioning trust regulatory liability

     (5     (13     (10

Losses recognized in other comprehensive income (before taxes)

     (3     (10     (2

Net impairment losses recognized in earnings

   $ 13      $ 8      $ 14   

 

(1) Amounts include other-than-temporary impairment losses for debt securities of $3 million, $18 million and $4 million at December 31, 2014, 2013 and 2012, respectively.

VIRGINIA POWER

Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below:

 

     

Amortized

Cost

    

Total

Unrealized

Gains(1)

    

Total

Unrealized

Losses(1)

   

Fair

Value

 
(millions)                           

2014

          

Marketable equity securities:

          

U.S. large cap

   $ 563       $ 594       $      $ 1,157   

Marketable debt securities:

          

Corporate debt instruments

     242         9         (1     250   

U.S. Treasury securities and agency debentures

     197         3         (2     198   

State and municipal

     197         13                210   

Other

     23                        23   

Cost method investments

     86                        86   

Cash equivalents and other(2)

     6                        6   

Total

   $ 1,314       $ 619       $ (3 )(3)    $ 1,930   

2013

          

Marketable equity securities:

          

U.S.:

          

Large Cap

   $ 506       $ 514       $      $ 1,020   

Other

     25         11                36   

Marketable debt securities:

          

Corporate debt instruments

     185         8         (2     191   

U.S. Treasury securities and agency debentures

     214         1         (3     212   

State and municipal

     163         4         (4     163   

Cost method investments

     106                        106   

Cash equivalents and other(2)

     37                        37   

Total

   $ 1,236       $ 538       $ (9 )(3)    $ 1,765   

 

(1) Included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.
(2) Includes pending sales of securities of $6 million at December 31, 2014 and 2013.
(3) The fair value of securities in an unrealized loss position was $170 million and $299 million at December 31, 2014 and 2013, respectively.

The fair value of Virginia Power’s marketable debt securities at December 31, 2014, by contractual maturity is as follows:

 

      Amount  
(millions)       

Due in one year or less

   $ 40   

Due after one year through five years

     180   

Due after five years through ten years

     242   

Due after ten years

     219   

Total

   $ 681   

Presented below is selected information regarding Virginia Power’s marketable equity and debt securities.

 

Year Ended December 31,    2014      2013      2012  
(millions)                     

Proceeds from sales

   $ 549       $ 572       $ 626   

Realized gains(1)

     73         52         42   

Realized losses(1)

     12         14         11   

 

(1) Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

Virginia Power recorded other-than-temporary impairment losses on investments as follows:

 

Year Ended December 31,    2014     2013     2012  
(millions)                   

Total other-than-temporary impairment losses(1)

   $ 8      $ 15      $ 11   

Losses recorded to nuclear decommissioning trust regulatory liability

     (4     (13     (10

Losses recorded in other comprehensive income (before taxes)

     (2     (1       

Net impairment losses recognized in earnings

   $ 2      $ 1      $ 1   

 

(1) Amounts include other-than-temporary impairment losses for debt securities of $2 million, $9 million and $2 million at December 31, 2014, 2013 and 2012, respectively.

EQUITY METHOD INVESTMENTS

Dominion and Dominion Gas

Investments that Dominion and Dominion Gas account for under the equity method of accounting are as follows:

 

Company   Ownership%     Investment
Balance
    Description
As of December 31,          2014     2013       
(millions)                      

Dominion

       

Blue Racer Midstream, LLC

    50   $ 671      $ 510      Midstream gas and
related services

Fowler I Holdings LLC

    50     134        149      Wind-powered merchant
generation facility

NedPower Mount Storm LLC

    50     128        131      Wind-powered merchant
generation facility

Iroquois Gas Transmission System, LP

    24.72     107        105      Gas transmission system

Other(1)

    various        41        21       

Total

          $ 1,081      $ 916       

Dominion Gas

       

Iroquois Gas Transmission System, LP

    24.72   $ 107      $ 105      Gas transmission system

Total

          $ 107      $ 105       

 

(1) Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018. Includes Dominion’s investment in Atlantic Coast Pipeline. See Note 15 for more information.
 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

Dominion’s equity earnings on its investments totaled $46 million, $14 million and $25 million in 2014, 2013 and 2012, respectively. Dominion received distributions from these investments of $60 million, $33 million and $58 million in 2014, 2013, and 2012, respectively. As of December 31, 2014 and 2013, the carrying amount of Dominion’s investments exceeded its share of underlying equity in net assets by approximately $126 million and $36 million, respectively. $87 million of the differences relate to basis differences from Dominion’s investments in Blue Racer and wind projects, which are being amortized over the useful lives of the underlying assets. The remaining $39 million of differences reflect equity method goodwill and are not being amortized.

Dominion Gas’ equity earnings on its investment totaled $21 million, $22 million and $23 million in 2014, 2013 and 2012, respectively. Dominion Gas received distributions from its investment of $20 million, $19 million and $25 million in 2014, 2013, and 2012, respectively. As of December 31, 2014 and 2013, the carrying amount of Dominion Gas’ investment exceeded its share of underlying equity in net assets by approximately $8 million. The differences reflect equity method goodwill and are not being amortized.

Equity earnings are recorded in other income in Dominion’s and Dominion Gas’ Consolidated Statements of Income.

BLUE RACER

In December 2012, Dominion formed a joint venture 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.

In December 2012, East Ohio sold two pipeline systems to an affiliate who then contributed those systems to Blue Racer. East Ohio received consideration of $248 million, consisting of $61 million in cash proceeds and the extinguishment of affiliated long term debt of $187 million. The transaction resulted in a gain of approximately $176 million ($110 million after-tax) that is recognized in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. Dominion recorded a 50% interest in Blue Racer and cash proceeds of $115 million for the contribution of the assets to the joint venture. Dominion recognized a gain of $72 million ($43 million after-tax), net of transaction fees of $9 million, which is recorded in other operations and maintenance expense in Dominion’s Consolidated Statements of Income.

In March 2013, DTI sold Line TL-404 to an affiliate, that subsequently sold line TL-404 to Blue Racer for cash proceeds of approximately $47 million. The sale resulted in a gain of approximately $25 million ($14 million after-tax) net of a $2 million write-off of goodwill, and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statements of Income.

Phase 1 of Natrium was completed in the second quarter of 2013 and was contributed by Dominion to Blue Racer in the third quarter of 2013, resulting in an increased equity method

investment in Blue Racer of $473 million. Also in the third quarter of 2013, DTI sold Line TPL-2A to an affiliate, that subsequently sold Line TPL-2A to Blue Racer, and sold Line TL-388 to Blue Racer and received approximately $78 million in cash proceeds. The sales resulted in an approximately $74 million ($41 million after-tax) gain which is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statements of Income.

In the fourth quarter of 2013, DTI sold the Western System to an affiliate, that subsequently sold the Western System to Blue Racer for cash proceeds of approximately $30 million. The sale resulted in a gain of approximately $3 million ($2 million after-tax) for DTI and $4 million ($2 million after-tax) for Dominion and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statement of Income.

Dominion NGL Pipelines, LLC was contributed in January 2014 by Dominion to Blue Racer, prior to commencement of service, resulting in an increased equity method investment of $155 million, including $6 million of goodwill allocated from Dominion’s goodwill balance to its equity method investment in Blue Racer.

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. The sale resulted in a gain of approximately $59 million ($35 million after-tax for Dominion Gas and $34 million after-tax for Dominion) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statement of Income.

Dominion

ATLANTIC COAST PIPELINE

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. Subsidiaries and affiliates of all four members plan to be customers of the pipeline under 20-year contracts, pending regulatory approvals. PSNC Energy also plans to be a customer of the pipeline under a 20-year contract, pending regulatory approvals. Atlantic Coast Pipeline is considered an equity method investment as Dominion has the ability to exercise significant influence, but not control, over the investee. See Note 15 for more information.

 

 

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NOTE 10. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:

 

At December 31,    2014      2013  
(millions)              

Dominion

     

Utility:

     

Generation

   $ 15,193       $ 14,018   

Transmission

     9,897         8,686   

Distribution

     12,354         11,714   

Storage

     2,350         2,190   

Nuclear fuel

     1,411         1,375   

Gas gathering and processing

     791         787   

General and other

     845         812   

Other-including plant under construction

     3,633         3,261   

Total utility

     46,474         42,843   

Nonutility:

     

Merchant generation-nuclear

     1,267         1,153   

Merchant generation-other

     2,023         1,328   

Nuclear fuel

     860         770   

Other-including plant under construction

     782         875   

Total nonutility

     4,932         4,126   

Total property, plant and equipment

   $ 51,406       $ 46,969   

Virginia Power

     

Utility:

     

Generation

   $ 15,193       $ 14,018   

Transmission

     5,884         4,959   

Distribution

     9,526         9,103   

Nuclear fuel

     1,411         1,375   

General and other

     697         668   

Other-including plant under construction

     2,464         2,719   

Total utility

     35,175         32,842   

Nonutility-other

     5         6   

Total property, plant and equipment

   $ 35,180       $ 32,848   

Dominion Gas

     

Utility:

     

Transmission

   $ 3,690       $ 3,407   

Distribution

     2,530         2,333   

Storage

     1,466         1,314   

Gas gathering and processing

     786         783   

General and other

     111         103   

Plant under construction

     179         175   

Total utility

     8,762         8,115   

Nonutility:

     

E&P properties being amortized and other

     140         125   

Total nonutility

     140         125   

Total property, plant and equipment

   $ 8,902       $ 8,240   

There were no significant E&P properties under development, as defined by the SEC, excluded from Dominion Gas’ amortization at December 31, 2014. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.

Jointly-Owned Power Stations

Dominion’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2014 is as follows:

 

     

Bath

County

Pumped

Storage

Station(1)

   

North

Anna
Units 1
and 2(1)

   

Clover

Power

Station(1)

   

Millstone

Unit 3(2)

 
(millions, except percentages)                         

Ownership interest

     60     88.4     50     93.5

Plant in service

   $ 1,039      $ 2,426      $ 573      $ 1,104   

Accumulated depreciation

     (542     (1,137     (206     (290

Nuclear fuel

            627               480   

Accumulated amortization of nuclear fuel

            (486            (342

Plant under construction

     11        114        11        71   

 

(1) Units jointly owned by Virginia Power.
(2) Unit jointly owned by Dominion.

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.

Assignments of Marcellus 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 of its 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 an overriding royalty interest in gas produced from the acreage. In 2013, DTI received approximately $100 million in cash proceeds, resulting in an approximately $20 million ($12 million after-tax) gain, recorded to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. During the twelve months ended December 31, 2014, DTI received $16 million in additional cash proceeds resulting from post-closing adjustments. At December 31, 2014, deferred revenue totaled approximately $85 million, which is expected to be recognized over the remaining term of the agreement.

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 November 2014, DTI closed on the agreement and received proceeds of approximately $60 million associated with an initial conveyance of approximately 12,000 acres, resulting in an approximately $60 million ($36 million after-tax) gain, recorded to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.

In November 2014, DTI signed an agreement with a natural gas producer to convey approximately 11,000 acres of Marcellus

 

 

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Shale development rights underneath one of its natural gas storage fields. The agreement provides for a payment to DTI, subject to customary adjustments, of approximately $27 million, and an overriding royalty interest in gas produced from the acreage. DTI expects to close on the agreement in March 2015.

 

 

NOTE 11. GOODWILL AND INTANGIBLE ASSETS

Goodwill

The changes in Dominion’s and Dominion Gas’ carrying amount and segment allocation of goodwill are presented below:

 

     

Dominion

Generation

   

Dominion

Energy

    DVP     

Corporate
and

Other(1)

     Total  
(millions)                                 

Dominion

         

Balance at December 31, 2012(2)

   $ 1,503      $ 701      $ 926       $       $ 3,130   

Asset disposition adjustment

     (19 )(3)      (25 )(4)                      (44

Balance at December 31, 2013(2)

   $ 1,484      $ 676      $ 926       $       $ 3,086   

Asset disposition adjustment

     (32 )(3)      (10 )(4)                      (42

Balance at December 31, 2014(2)

   $ 1,452      $ 666      $ 926       $       $ 3,044   

Dominion Gas

            

Balance at December 31, 2012(2)

   $      $ 552      $       $       $ 552   

Asset disposition adjustment

            (7 )(4)                      (7

Balance at December 31, 2013(2)

   $      $ 545      $       $       $ 545   

Asset disposition adjustment

            (3 )(4)                      (3

Balance at December 31, 2014(2)

   $      $ 542      $       $       $ 542   

 

(1) Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.
(2) Goodwill amounts do not contain any accumulated impairment losses.
(3) See Note 3 for a discussion of Dominion’s dispositions and related goodwill write-offs.
(4) Related to assets sold or contributed to an affiliate or Blue Racer.

Other Intangible Assets

The Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion’s amortization expense for intangible assets was $71 million, $72 million and $82 million for 2014, 2013 and 2012, respectively. In 2014, Dominion acquired $115 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 15 years. Amortization expense for Virginia Power’s intangible assets was $24 million for 2014 and $22 million each year for 2013 and 2012. In 2014, Virginia Power acquired $45 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 14 years. Dominion Gas’ amortization expense for intangible assets was $17 million, $16 million and $15 million for 2014, 2013 and 2012, respectively. In 2014, Dominion Gas acquired $8 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 7 years. The components of intangible assets are as follows:

 

At December 31,    2014      2013  
     

Gross

Carrying

Amount

    

Accumulated

Amortization

    

Gross

Carrying

Amount

    

Accumulated

Amortization

 
(millions)                            

Dominion

           

Software, licenses and other

   $ 877       $ 312       $ 867       $ 308   

Emissions allowances

     10         5         3         2   

Total

   $ 887       $ 317       $ 870       $ 310   

Virginia Power

           

Software, licenses and other

   $ 286       $ 81       $ 271       $ 78   

Total

   $ 286       $ 81       $ 271       $ 78   

Dominion Gas

           

Software, licenses and other

   $ 192       $ 113       $ 180       $ 98   

Total

   $ 192       $ 113       $ 180       $ 98   

Annual amortization expense for these intangible assets is estimated to be as follows:

 

      2015      2016      2017      2018      2019  
(millions)                                   

Dominion

   $ 72       $ 67       $ 58       $ 45       $ 36   

Virginia Power

   $ 21       $ 18       $ 15       $ 12       $ 8   

Dominion Gas

   $ 17       $ 16       $ 13       $ 11       $ 11   
 

 

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NOTE 12. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities include the following:

 

At December 31,

   2014      2013  
(millions)              

Dominion

     

Regulatory assets:

     

Deferred rate adjustment clause costs(1)

   $ 124       $ 89   

Deferred cost of fuel used in electric generation(2)

     79           

Deferred nuclear refueling outage costs(3)

     44           

Unrecovered gas costs(4)

     36         50   

Other

     64         78   

Regulatory assets-current

     347         217   

Unrecognized pension and other postretirement benefit costs(5)

     1,050         706   

Deferred rate adjustment clause costs(1)

     250         287   

Income taxes recoverable through future rates(6)

     133         155   

Derivatives(7)

     101         16   

Other

     108         64   

Regulatory assets-non-current

     1,642         1,228   

Total regulatory assets

   $ 1,989       $ 1,445   

Regulatory liabilities:

     

PIPP(8)

   $ 71       $ 76   

Other

     99         52   

Regulatory liabilities-current(9)

     170         128   

Provision for future cost of removal and AROs(10)

     1,072         1,028   

Nuclear decommissioning trust(11)

     815         693   

Deferred cost of fuel used in electric generation(2)

     6         90   

Other

     98         190   

Regulatory liabilities-non-current

     1,991         2,001   

Total regulatory liabilities

   $ 2,161       $ 2,129   

Virginia Power

     

Regulatory assets:

     

Deferred rate adjustment clause costs(1)

   $ 117       $ 62   

Deferred cost of fuel used in electric generation(2)

     79           

Deferred nuclear refueling outage costs(3)

     44           

Other

     58         66   

Regulatory assets-current

     298         128   

Deferred rate adjustment clause costs(1)

     179         227   

Derivatives(7)

     101         16   

Income taxes recoverable through future rates(6)

     100         124   

Other

     59         50   

Regulatory assets-non-current

     439         417   

Total regulatory assets

   $ 737       $ 545   

Regulatory liabilities:

     

Other

   $ 90       $ 41   

Regulatory liabilities-current

     90         41   

Provision for future cost of removal(10)

     852         807   

Nuclear decommissioning trust(11)

     815         693   

Deferred cost of fuel used in electric generation(2)

     6         90   

Other

     10         7   

Regulatory liabilities-non-current

     1,683         1,597   

Total regulatory liabilities

   $ 1,773       $ 1,638   

Dominion Gas

     

Regulatory assets:

     

Unrecovered gas costs(4)

   $ 29       $ 40   

Deferred rate adjustment clause costs(1)

     7         27   

UEX Rider(12)

             11   

Other

     2         1   

At December 31,

   2014      2013  
(millions)              

Regulatory assets-current

     38         79   

Unrecognized pension and other postretirement benefit costs(5)

     242         194   

Deferred rate adjustment clause costs(1)

     71         59   

Income taxes recoverable through future rates(6)

     24         24   

Other

     42         8   

Regulatory assets-non-current

     379         285   

Total regulatory assets

   $ 417       $ 364   

Regulatory liabilities:

     

PIPP(8)

   $ 71       $ 76   

Other

     4         3   

Regulatory liabilities-current

     75         79   

Provision for future cost of removal and AROs(10)

     172         177   

Unrecognized pension and other postretirement benefit costs(5)

             18   

Other

     20         8   

Regulatory liabilities-non-current

     192         203   

Total regulatory liabilities

   $ 267       $ 282   

 

  (1) Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects for Virginia Power. Reflects deferrals of costs associated with certain current and prospective rider projects for Dominion Gas. See Note 13 for more information.
  (2) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Dominion’s and Virginia Power’s generation operations. See Note 13 for more information. For 2014 and 2013, amount includes approximately $5 million related to DOE claims.
  (3) Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months.
  (4) Reflects unrecovered gas costs at regulated gas operations, which are recovered through filings with the applicable regulatory authority.
  (5) Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain of Dominion’s rate-regulated subsidiaries.
  (6) Amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes.
  (7) As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.
  (8) Under PIPP, eligible customers can make reduced payments based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rider according to East Ohio tariff provisions. See Note 13 for more information.
  (9) Current regulatory liabilities are presented in other current liabilities in Dominion’s Consolidated Balance Sheets.
(10) Rates charged to customers by the Companies’ regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.
(11) Reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related AROs.
(12) Represents East Ohio’s deferrals for the UEX Rider which are recovered through rates which are filed annually. Most of East Ohio’s bad debt expense is recovered either through the UEX Rider or the PIPP Rider.
 
  See Note 13 for more information.

 

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At December 31, 2014, approximately $218 million of Dominion’s, $165 million of Virginia Power’s and $45 million of Dominion Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. The majority of these expenditures are expected to be recovered within the next two years.

 

 

NOTE 13. REGULATORY MATTERS

Regulatory Matters Involving Potential Loss Contingencies

As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For matters for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.

FERC—ELECTRIC

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. 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. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in the wholesale market. 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.

Rates

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.

In March 2010, ODEC and NCEMC filed a complaint with FERC against Virginia Power claiming that approximately $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. In February 2012, Virginia Power submitted to FERC a settlement agreement to resolve all issues set for hearing. The settlement was accepted by FERC in May 2012 and provides for payment by Virginia Power to the transmission customer parties collectively of $250,000 per year for ten years and resolves all matters other than allocation of the incremental cost of certain underground transmission facilities.

In March 2014, FERC issued an order excluding from Virginia Power’s transmission rates for wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable for non-Virginia wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities because the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to benefit the citizens of Virginia. The order is retroactively effective as of March 2010 and will cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC determined that there was not sufficient evidence on the record to determine the magnitude of the underground increment and ordered a hearing to determine the appropriate amount of undergrounding cost to be allocated to each wholesale transmission customer in Virginia. While Virginia Power cannot predict the outcome of the hearing, it is not expected to have a material effect on results of operations.

Other Regulatory Matters

ELECTRIC REGULATION IN VIRGINIA

The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers.

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 also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.

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, it may adversely affect its results of operations, financial condition and cash flows.

 

 

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2013 Biennial Review

Pursuant to the Regulation Act, in March 2013, Virginia Power submitted its base rate filings and accompanying schedules in support of the Virginia Commission’s 2013 biennial review of Virginia Power’s rates, terms and conditions, as well as of Virginia Power’s earnings for 2011 and 2012 test periods. The Virginia Power earnings test analysis reviewed by the Virginia Commission reflected an ROE of 10.30% on its generation and distribution services earnings for the combined test periods.

In November 2013, the Virginia Commission issued its 2013 Biennial Review Order. After deciding eleven contested earnings test adjustments, the Virginia Commission ruled that Virginia Power earned on average an ROE of approximately 10.25% on its generation and distribution services for the combined 2011 and 2012 test periods. Because this ROE was more than 50 basis points below Virginia Power’s authorized ROE of 10.9%, the Virginia Commission authorized the deferred recovery, for earnings test purposes, of $23 million in costs related to asset impairments with early retirement decisions, severe weather events, and natural disasters to be amortized over the 2013 calendar year. The Virginia Commission did not order a base rate increase because Virginia Power had previously waived its right to any such increase, and because it determined that Virginia Power had a revenue sufficiency of approximately $280 million when projecting the annual revenues generated by base rates to the revenues required to cover costs of service and earn a fair return. As part of its revenue sufficiency determination, the Virginia Commission also made findings on eleven rate case adjustments, in addition to changes to the cost of capital and capital structure, which resulted in changes to Virginia Power’s rate year revenues and expenses, and Virginia Power’s rate base for generation and distribution, for the rate year beginning January 1, 2014. Virginia Power incurred a $55 million ($37 million after-tax) charge in connection with the 2013 Biennial Review Order.

In its 2013 Biennial Review Order, the Virginia Commission also set the ROE that will be used in Virginia Power’s 2015 biennial review earnings test analysis for earnings on generation and distribution services for the combined 2013 and 2014 test periods, and that will be applied to Riders R, S, W, B, BW, C1A, and C2A. Pursuant to the Regulation Act, Virginia Power’s authorized ROE can be no lower than the average of the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., subject to certain limitations as described in the Regulation Act. Following this statutory peer group analysis, the Virginia Commission determined that the peer group floor ROE for Virginia Power was 9.89%. It further held, declining to increase or decrease Virginia Power’s combined rate of return based on performance, that Virginia Power’s ROE for earnings test purposes in its 2015 biennial review and for rate adjustment clause purposes is 10.0%, consistent with its determination that Virginia Power’s market cost of equity is 10.0%.

Virginia Fuel Expenses

In May 2014, Virginia Power submitted its annual fuel factor filing to the Virginia Commission to recover an estimated $1.9 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2014. Virginia Power also offered to defer recovery of 50% of its total estimated $268 million jurisdictional deferred fuel balance to the 2015-2016 fuel year, thereby

recovering $134 million of its jurisdictional deferred fuel balance for the rate year beginning July 1, 2014. In September 2014, the Virginia Commission approved Virginia Power’s increased fuel rate, which was already in effect on an interim basis since July 1, 2014. The new rate includes approval of Virginia Power’s offer to defer recovery of 50% its jurisdictional deferred fuel balance and represents an annual fuel revenue increase of approximately $300 million.

Rate Adjustment Clauses

Below is a discussion of significant riders associated with various Virginia Power projects:

Ÿ  

The Virginia Commission previously approved Rider T1. In July 2014, the Virginia Commission approved an approximately $538 million revenue requirement for the rate year beginning September 1, 2014, which represents an approximately $134 million increase over the previous year.

Ÿ  

The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2014, Virginia Power proposed an approximately $244 million revenue requirement for the rate year beginning April 1, 2015. This case is pending.

Ÿ  

The Virginia Commission previously approved Rider W in conjunction with Warren County. In February 2015, the Virginia Commission approved an approximately $135 million revenue requirement for the rate year beginning April 1, 2015.

Ÿ  

The Virginia Commission previously approved Rider BW in connection with Brunswick County. In October 2014, Virginia Power proposed a total revenue requirement of approximately $111 million for the rate year beginning September 1, 2015. This case is pending.

Ÿ  

The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In August 2014, Virginia Power proposed a total revenue requirement of approximately $47 million for the rate year beginning May 1, 2015. Virginia Power further proposed three new energy efficiency programs for Virginia Commission approval with a requested five-year cost cap of approximately $106 million for those programs. This case is pending.

Ÿ  

The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In June 2014, Virginia Power proposed an approximately $84 million revenue requirement for the rate year beginning April 1, 2015. This case is pending.

Ÿ  

Virginia legislation which provides for the recovery of costs to move certain electric distribution lines underground became effective in July 2014. In October 2014, Virginia Power filed for approval of Rider U, which proposes a revenue requirement of approximately $28 million during the initial rate year beginning September 1, 2015. This case is pending.

Ÿ  

The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2014, Virginia Power proposed an approximately $13 million revenue requirement for the rate year beginning April 1, 2015. This case is pending.

Ÿ  

In January 2015, Virginia Power applied for a CPCN to construct and operate a new 20 MW utility-scale solar facility near its existing Remington Power Station in Fauquier County, Virginia. Virginia Power also applied for approval of

 

 

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Rider US-1 to recover the costs of the facility. The total cost of the Remington Solar Facility is approximately $47 million (excluding financing costs). This case is pending.

Brunswick County

In August 2013, three motions for reconsideration were filed with the Virginia Commission, asking that it reconsider its August 2013 final order approving a CPCN for construction of Brunswick County. In November 2013, the Virginia Commission denied reconsideration. Three appeals were filed with the Supreme Court of Virginia, but two were withdrawn. In September 2014, the Supreme Court of Virginia issued an opinion affirming the Virginia Commission’s decision in the remaining appeal.

Electric Transmission Project

In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry Switching Station in Surry County to a new Skiffes Creek Switching Station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek Switching Station to Virginia Power’s existing Whealton Substation in the City of Hampton. In February 2014, the Virginia Commission granted reconsideration requested by Virginia Power and issued an Order Amending Certificate. Several appeals were filed with the Supreme Court of Virginia and oral arguments were heard in January 2015. The appeals are pending.

North Anna

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In April 2013, Virginia Power decided to replace the reactor design previously selected for a potential unit with ESBWR technology. Virginia Power filed the first of its two-part amendment to the COL application with the NRC in July 2013 to reflect the ESBWR technology and filed the second part of the amendment in December 2013. The COL is expected in 2016. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

In June 2012, the U.S. Court of Appeals for the D.C. Circuit vacated and remanded a 2010 NRC decision and related rulemaking that generically assessed the environmental impacts of spent fuel storage after expiration of a reactor’s license until a repository became available. In August 2012, the NRC partially granted a petition filed by BREDL and other petitioners in a number of ongoing licensing proceedings, including the North Anna COL proceedings, to withhold issuance of licenses until completion of action on the remand, and held proposed contentions accompanying the petition in abeyance. In August 2014, the NRC approved a new final rule codifying the NRC’s further generic assessment of environmental impacts of continued storage of spent fuel and lifted the suspension of final licensing decisions in pending cases and dismissed pending contentions on the subject, including the proposed contention filed by BREDL.

In September 2014, BREDL filed a new petition with the NRC again seeking suspension of final decision making in the COL proceeding, along with motions to reopen and file a new contention. The new filings assert that the NRC must make a safety finding on the feasibility and capacity of geologic disposal of spent fuel as a prerequisite to issuance of a license. The filings alleged that because these safety findings are no longer made as part of the NRC’s new continued storage rule, such findings must now be made in individual licensing proceedings. In January 2015, BREDL filed another petition in the COL proceeding asking the NRC to order supplementation of the final environmental impact statement for North Anna 3 to incorporate the NRC’s generic assessment of the impacts of continued spent fuel storage, so that BREDL could then challenge that assessment. BREDL’s September 2014 filings and January 2015 petition are substantially the same as filings made by various other intervenor groups in other licensing proceedings pending before the NRC. Resolution of these filings is not expected to affect the schedule for issuance of the COL.

North Anna and Offshore Wind Legislation

In April 2014, legislation was enacted in Virginia that permits Virginia Power to recover 70% of the costs previously deferred or capitalized related to the development of a third nuclear unit located at North Anna and offshore wind facilities through December 31, 2013 as part of the 2013 and 2014 base rates. Virginia Power had deferred or capitalized costs totaling approximately $577 million for these projects as of December 31, 2013, substantially all of which relate to North Anna. For the 70% portion of these previously deferred or capitalized costs allocable to customers in Virginia, Virginia Power recognized such amounts that are now recoverable in 2013 and 2014 base rates as charges against net income beginning in the second quarter of 2014 and for the remainder of the year. During 2014, Virginia Power recognized $374 million ($248 million after-tax) in charges against income representing the cumulative recovery of costs from January 2013 through December 2014, which are primarily included in other operations and maintenance expense in the Consolidated Statements of Income. The remaining deferred or capitalized costs, as well as costs incurred after December 31, 2013, continue to be eligible for inclusion in a future rate adjustment clause.

Regulation Act Legislation

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. 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. Virginia Power is scheduled to file its next biennial review, covering 2013 and 2014, in March 2015. The legislation allows this review to proceed for the sole purpose of determining whether any refunds are due to customers based on earnings performance during the 2013 and 2014 test periods. In addition the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility’s ROE for use in connection with rate adjustment clauses and requires utilities to file integrated resource plans annually rather

 

 

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than biennially. The legislation requires Virginia Power to write-off $85 million of prior-period deferred fuel costs during the first quarter of 2015. In addition, the legislation requires the Virginia Commission to implement a fuel rate reduction for Virginia Power as soon as practicable based on this non-recovery as well as any over-recovery for the 2014-2015 fuel year and projected fuel expense for the 2015-2016 fuel year. The legislation also deems the construction or purchase of one or more utility-scale solar facilities located in Virginia up to 500 MW in total to be in the public interest.

NORTH CAROLINA REGULATION

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 Supreme Court of North Carolina 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.

In December 2014, the North Carolina Commission issued an order approving an approximately $17 million increase to the fuel component of Virginia Power’s electric rates for the rate year beginning January 1, 2015. This increase includes the approval of Virginia Power’s mitigation proposal to defer recovering 50% of its estimated $17 million jurisdictional deferred fuel balance to the 2016 fuel year, without interest.

OHIO REGULATION

PIR Program

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In February 2014, East Ohio filed an application requesting approval to adjust the PIR cost recovery rates for 2013 costs. The filing reflects gross plant investment for 2013 of $164 million, cumulative gross plant investment of $674 million and an estimated revenue requirement of $89 million. This application was approved by the Ohio Commission in April 2014.

In February 2015, East Ohio filed an application to adjust the PIR cost recovery for 2014 costs. The filing reflects gross plant investment for 2014 of $155 million, cumulative gross plant investment of $829 million and a revenue requirement of $108 million. This case is pending.

AMR Program

In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. In May 2014, AMR cost recovery rates became effective as approved by the Ohio Commission in April 2014. The approval includes a revenue requirement of $8 million, which represents an approximately $3 million increase over the previous year.

In January 2013, East Ohio filed with the Ohio Supreme Court an appeal of a rate reduction ordered by the Ohio Commission in October 2012 and a motion seeking a stay of the AMR cost recovery rate imposed. The Ohio Supreme Court granted the stay in March 2013 and East Ohio put the higher AMR cost recovery rate filed by East Ohio into effect. In July 2014, the Ohio Supreme Court ruled in East Ohio’s favor by agreeing that the rate reduction imposed by the Ohio Commission was unreasonable.

In February 2015, East Ohio filed its application with the Ohio Commission to adjust its AMR cost recovery charge to recover costs for calendar year 2014 associated with AMR deployment, which was completed in 2012. The filing reflects a projected revenue requirement of approximately $8 million. This case is pending.

The AMR program approved by the Ohio Commission is now complete. Although no further capital investment will be added, East Ohio is approved to recover depreciation, property taxes, carrying charges and a return until East Ohio has another rate case.

PIPP Plus Program

Under the Ohio PIPP Plus Program, eligible customers can make reduced payments based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP payment plan amount is deferred and collected under the PIPP Rider in accordance with the rules of the Ohio Commission. In July 2014, East Ohio’s annual update of the PIPP Rider was automatically approved by the Ohio Commission after a 45-day waiting period from the date of the filing. The increased rider rate reflects the refund over the next year of an over-recovery of accumulated arrearages of approximately $82 million as of March 31, 2014, net of projected deferred program costs of approximately $96 million for the period from April 2014 through June 2015.

UEX Rider

East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In July 2014, the Ohio Commission approved a decrease to East Ohio’s UEX Rider, which reflects the elimination of the over-recovered balance of accumulated bad debt expense of approximately $8 million as of March 31, 2014, and recovery of prospective bad debt expense projected to total approximately $25 million for the twelve-month period from April 2014 to March 2015.

House Bill 95

Ohio enacted utility reform legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future. In July 2014, the Ohio Commission approved East Ohio’s application requesting authority to

 

 

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implement a capital expenditure program for 2014 capital expenditures totaling $110 million.

FERC REGULATION

DTI Fuel Settlement

In mid-2013, DTI received concerns about its fuel retainage percentages and apparent over-recovery of fuel costs during certain time periods reflected in its annual fuel reports. In December 2013, DTI submitted for FERC approval a stipulation and agreement addressing, among other things, reductions in its fuel retainage percentages and a rate moratorium through 2016. In February 2014, FERC approved the stipulation and agreement.

The revised fuel retainage percentages became effective January 1, 2014. DTI began assessing the reduced fuel retainage percentages on March 1, 2014, and as a result provided refunds totaling nearly $10 million. The refunds reflect, with interest, the value of the difference between the actual quantities of fuel retained for the months of January and February and the quantities that would have been retained using the reduced percentages.

 

 

NOTE 14. ASSET RETIREMENT OBLIGATIONS

AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of the Companies’ long-lived assets. Dominion’s and Virginia Power’s AROs are primarily associated with the decommissioning of their nuclear generation facilities and also include those for the future abatement of asbestos expected to be disturbed in their generation facilities. Dominion Gas’ AROs primarily include plugging and abandonment of gas and oil wells and the interim retirement of natural gas gathering, transmission, distribution and storage pipeline components.

The Companies have also identified, but not recognized, AROs related to retirement of Dominion’s LNG facility, Dominion Gas’ gas storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in Dominion’s and Virginia Power’s generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement

date for these assets. The changes to AROs during 2013 and 2014 were as follows:

 

      Amount  
(millions)       

Dominion

  

AROs at December 31, 2012(1)

   $ 1,705   

Obligations incurred during the period

     13   

Obligations settled during the period

     (68

Revisions in estimated cash flows(2)

     (129

Accretion

     86   

Other

     (29

AROs at December 31, 2013(1)

   $ 1,578   

Obligations incurred during the period

     40   

Obligations settled during the period

     (82

Revisions in estimated cash flows(3)

     102   

Accretion

     81   

Other

     (5

AROs at December 31, 2014(1)

   $ 1,714   

Virginia Power

  

AROs at December 31, 2012

   $ 705   

Obligations incurred during the period

     2   

Obligations settled during the period

     (2

Revisions in estimated cash flows(2)

     (52

Accretion

     38   

Other

     (2

AROs at December 31, 2013

   $ 689   

Obligations incurred during the period

     28   

Obligations settled during the period

     (1

Revisions in estimated cash flows(3)

     108   

Accretion

     37   

Other

     (6

AROs at December 31, 2014(4)

   $ 855   

Dominion Gas

  

AROs at December 31, 2012

   $ 133   

Obligations incurred during the period

     8   

Obligations settled during the period

     (13

Accretion

     8   

Other

     1   

AROs at December 31, 2013(5)(6)

   $ 137   

Obligations incurred during the period

     2   

Obligations settled during the period

     (8

Accretion

     8   

Other

     8   

AROs at December 31, 2014(5)(6)

   $ 147   

 

(1) Includes $64 million, $94 million and $81 million reported in other current liabilities at December 31, 2012, 2013, and 2014, respectively.
(2) Primarily reflects lower anticipated nuclear decommissioning costs.
(3) Relates primarily to a shift of the delayed planned date on which the DOE is expected to begin accepting spent nuclear fuel.
(4) Includes $7 million reported in other current liabilities at December 31, 2014.
(5) Includes $2 million and $7 million reported in other current liabilities at December 31, 2013 and 2014, respectively.
(6) Includes $135 million and $140 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2013 and 2014, respectively.

Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 2014 and 2013, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $4.2 billion and $3.9 billion, respectively. At

 

 

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December 31, 2014 and 2013, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.9 billion and $1.8 billion, respectively.

 

 

NOTE 15. VARIABLE INTEREST ENTITIES

The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.

Dominion

Through August 2013, Dominion leased the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. In August 2013, the lease expired and Dominion purchased Fairless for $923 million from Juniper per the terms of the lease agreement. However, as Dominion had previously consolidated Juniper, the purchase was accounted for as an equity transaction to acquire the noncontrolling interests from Juniper for $923 million, while Dominion retained control of Fairless. The acquisition resulted in the removal of securities due within one year-VIE and noncontrolling interests from Dominion’s Consolidated Balance Sheet during 2013.

Dominion has an initial 45% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the nature of this entity. Dominion concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion has concluded that it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. Dominion is obligated to provide capital contributions based on its ownership percentage. Dominion’s maximum exposure to loss is limited to its current and future investment.

Dominion Gas

DTI has been engaged to oversee the construction of, and to subsequently operate and maintain, the projects undertaken by Atlantic Coast Pipeline based on the overall direction and oversight of Atlantic Coast Pipeline’s members. An affiliate of DTI holds a membership interest in Atlantic Coast Pipeline, therefore DTI is considered to have a variable interest in Atlantic Coast Pipeline. The members of Atlantic Coast Pipeline hold the power to direct the construction, operations and maintenance activities of the entity. DTI has concluded it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance. DTI has no obligation to absorb any losses of the VIE. See Note 24 for information about associated related party receivable balances.

Virginia Power

Virginia Power has long-term power and capacity contracts with five non-utility generators with an aggregate summer generation capacity of approximately 870 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $639 million as of December 31, 2014. Virginia Power paid $223 million, $217 million, and $214 million for electric capacity and $138 million, $98 million, and $83 million for electric energy to these entities for the years ended December 31, 2014, 2013 and 2012, respectively.

Virginia Power and Dominion Gas

Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of approximately $335 million and $106 million, $331 million and $115 million, and $328 million and $107 million for the years ended December 31, 2014, 2013 and 2012, respectively. Virginia Power and Dominion Gas determined that each is not the most closely associated entity with DRS and therefore neither is the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power and Dominion Gas. Virginia Power and Dominion Gas have no obligation to absorb more than their allocated shares of DRS costs.

 

 

NOTE 16. SHORT-TERM DEBT AND CREDIT AGREEMENTS

The Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.

 

 

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Dominion

Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:

 

      Facility
Limit
     Outstanding
Commercial
Paper
    Outstanding
Letters of
Credit
     Facility
Capacity
Available
 
(millions)                           

At December 31, 2014

          

Joint revolving credit facility(1)

   $ 4,000       $ 2,664      $       $ 1,336   

Joint revolving credit facility(2)

     500         111        48         341   

Total

   $ 4,500       $ 2,775 (3)    $ 48       $ 1,677   

At December 31, 2013

          

Joint revolving credit facility(1)

   $ 3,000       $ 1,927      $       $ 1,073   

Joint revolving credit facility(2)

     500                11         489   

Total

   $ 3,500       $ 1,927 (3)    $ 11       $ 1,562   

 

(1) In May 2014, this credit facility was amended and restated. The facility limit was increased from $3 billion to $4 billion and the maturity date was extended from September 2018 to April 2019. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.
(2) In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.
(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were 0.38% and 0.33% at December 31, 2014 and 2013, respectively.

Virginia Power

Virginia Power’s short-term financing is supported by two joint revolving credit facilities with Dominion and Dominion Gas. These credit facilities are being used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

Virginia Power’s share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion and Dominion Gas were as follows:

 

     Facility
Sub-limit
    Outstanding
Commercial
Paper
    Outstanding
Letters of
Credit
    Facility
Sub-limit
Capacity
Available
 
(millions)                        

At December 31, 2014

       

Joint revolving credit facility(1)

  $ 1,250      $ 1,250      $      $   

Joint revolving credit facility(2)

    250        111               139   

Total

  $ 1,500      $ 1,361 (3)    $      $ 139   

At December 31, 2013

       

Joint revolving credit facility(1)

  $ 1,000      $ 842      $      $ 158   

Joint revolving credit facility(2)

    250               1        249   

Total

  $ 1,250      $ 842 (3)    $ 1      $ 407   

 

(1) In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. This
  credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year. In July 2014, Virginia Power increased its sub-limit from $1.0 billion to $1.25 billion. In January 2015, Virginia Power increased its sub-limit on this facility from $1.25 billion to $1.5 billion.
(2) In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.
(3) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.36% and 0.33% at December 31, 2014 and 2013, respectively.

In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility. In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. As of December 31, 2014, this facility supports approximately $119 million of certain variable rate tax-exempt financings of Virginia Power.

Dominion Gas

Dominion Gas’s short-term financing is supported by the two joint revolving credit facilities discussed above with Dominion and Virginia Power, to which Dominion Gas was added as a borrower in May 2014. Dominion Gas’ current sub-limit under the $4 billion credit facility is $500 million, all of which was available at December 31, 2014, and can be increased or decreased multiple times per year, up to a maximum of $1 billion. Dominion Gas’ current sub-limit under the $500 million credit facility is $0 and can also be increased or decreased multiple times per year. The maturity date for both facilities is April 2019. In December 2014, Dominion Gas entered into a commercial paper program pursuant to which it began accessing the commercial paper markets in January 2015. Dominion Gas’ current sub-limit under the $4 billion credit facility of $500 million is being used to support these commercial paper issuances.

 

 

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NOTE 17. LONG-TERM DEBT

 

At December 31,   

2014
Weighted-

average

Coupon(1)

    2014     2013  
(millions, except percentages)                   

Dominion Gas Holdings, LLC:

      

Unsecured Senior Notes:

      

1.05% and 2.5%, due 2016 and 2019

     1.82   $ 850      $ 400   

3.55% to 4.8%, due 2023 to 2044

     4.15     1,750        800   

Dominion Gas Holdings, LLC total principal

     $ 2,600      $ 1,200   

Unamortized discount

             (6     (2

Dominion Gas Holdings, LLC total long-term debt

           $ 2,594      $ 1,198   

Virginia Electric and Power Company:

      

Unsecured Senior Notes:

      

1.2% to 8.625%, due 2015 to 2019

     5.06   $ 2,471      $ 2,488   

2.75% to 8.875%, due 2022 to 2044

     5.07     5,592        4,643   

Tax-Exempt Financings(2):

      

Variable rates, due 2016 to 2041

     0.93     606        606   

0.70% to 5.6%, due 2022 to 2040

     2.86     266        306   

Virginia Electric and Power Company total principal

     $ 8,935      $ 8,043   

Securities due within one year

     5.39     (211     (58

Unamortized discount and premium, net

             2        (11

Virginia Electric and Power Company total long-term debt

           $ 8,726      $ 7,974   

Dominion Resources, Inc.:

      

Unsecured Senior Notes:

      

Variable rates, due 2014 and 2015

     0.36   $ 400      $ 400   

1.25% to 8.875%, due 2014 to 2019

     3.17     3,150        4,391   

2.75% to 7.0%, due 2021 to 2044(3)

     4.93     4,449        3,499   

Unsecured Convertible Senior Notes, 2.125%, due 2023

              43   

Tax-Exempt Financing, variable rate, due 2041

     1.10     75        75   

Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 8.4%, due 2031

     8.40     10        10   

Enhanced Junior Subordinated Notes:

      

5.75% to 8.375%, due 2054 to 2066

     6.28     985        985   

Variable rate, due 2066

     2.54     380        380   

Remarketable Subordinated Notes, 1.07% to 1.50%, due 2019 to 2021

     1.30     2,100        1,100   

Unsecured Debentures and Senior Notes(4):

      

5.0% due 2014

              600   

6.8% and 6.875%, due 2026 and 2027

     6.81     89        89   

Dominion Energy, Inc.:

      

Tax-Exempt Financing, 2.375%, due 2033

     2.38     27        27   

Dominion Gas Holdings, LLC total principal (from above)

       2,600        1,200   

Virginia Electric and Power Company total principal (from above)

             8,935        8,043   

Dominion Resources, Inc. total principal

           $ 23,200      $ 20,842   

Fair value hedge valuation(5)

       19        55   

Securities due within one year(6)

     3.30     (1,375     (1,519

Unamortized discount and premium, net

             (39     (48

Dominion Resources, Inc. total long-term debt

           $ 21,805      $ 19,330   

 

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2014.
(2) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. Certain variable rate tax-exempt financings are supported by a $120 million credit facility that terminates in April 2019.
(3) At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015. As a result, at December 31, 2014, the notes were included in Securities due within one year in the Consolidated Balance Sheets.
(4) Represents debt assumed by Dominion from the merger of its former CNG subsidiary.
(5) Represents the valuation of certain fair value hedges associated with Dominion’s fixed rate debt.
(6) Includes $4 million fair value hedge valuation in 2014 and $14 million of fair value hedge valuation in 2013.

 

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Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2014, were as follows:

 

      2015     2016     2017     2018     2019     Thereafter     Total  
(millions, except percentages)                                                  

Dominion Gas

   $      $ 400      $      $      $ 450      $ 1,750      $ 2,600   

Weighted-average Coupon

             1.05                     2.50     4.15        

Virginia Power

   $ 211      $ 476      $ 679      $ 850      $ 350      $ 6,369      $ 8,935   

Weighted-average Coupon

     5.39     5.24     5.43     4.17     5.00     4.64        

Dominion

              

Unsecured Senior Notes(1)

   $ 861      $ 1,308      $ 1,354      $ 1,350      $ 2,000      $ 11,878      $ 18,751   

Tax-Exempt Financings

            19        75                      880        974   

Unsecured Junior Subordinated Notes Payable to Affiliated Trusts

                                        10        10   

Enhanced Junior Subordinated Notes

                                        1,365        1,365   

Remarketable Subordinated Notes

                                 550        1,550        2,100   

Total

   $ 861      $ 1,327      $ 1,429      $ 1,350      $ 2,550      $ 15,683      $ 23,200   

Weighted-average Coupon

     2.14     2.86     3.27     4.99     3.09     4.39        

 

(1) At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015. As a result, at December 31, 2014, the notes were included in Securities due within one year in the Consolidated Balance Sheets.

 

The Companies short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2014, there were no events of default under these covenants.

Senior Note Redemptions

As part of Dominion’s Liability Management Exercise, in December 2014, Dominion redeemed the following outstanding series of senior notes: 2005 Series C 5.15% Senior Notes due 2015, 2004 Series A 5.20% Senior Notes due 2016, 2006 Series A 5.60% Senior Notes due 2016, 2007 Series A 6.0% Senior Notes due 2017, and 2008 Series D 8.875% Senior Notes due 2019 with an aggregate outstanding principal of approximately $1.9 billion. The aggregate redemption price paid in December 2014 was approximately $2.2 billion and represents the principal amount outstanding, accrued and unpaid interest and the applicable make-whole premium of $263 million. Total charges for the Liability Management Exercise of $284 million, including the make-whole premium, were recognized and recorded in interest expense in Dominion’s Consolidated Statements of Income. Proceeds from Dominion’s issuance of senior notes in November 2014 were used to offset the payment of the redemption price. Also see Convertible Securities called for redemption below.

Convertible Securities

As part of Dominion’s Liability Management Exercise, in November 2014, Dominion provided notice to redeem all $22 million of outstanding contingent convertible senior notes. The senior notes were eligible for conversion during any calendar quarter when the closing price of Dominion’s common stock was equal to or higher than 120% of the conversion price for at least 20 out of the last 30 consecutive trading days of the preceding quarter, when the notes were called for redemption by Dominion and upon the occurrence of certain other conditions. During 2014, the senior notes were eligible for conversion. During the first, second and third quarters of 2014, approximately $21 million of the notes were converted by holders into $23 million of common stock. In lieu of redemption, holders elected to convert

the remaining $22 million of notes in December 2014 into $26 million of common stock. Proceeds from Dominion’s issuance of senior notes in November 2014 were used to offset the portion of the conversions paid in cash. At December 31, 2014, all of the senior notes have been converted and none remain outstanding.

Junior Subordinated Notes Payable to Affiliated Trusts

In previous years, Dominion established several subsidiary capital trusts, each as a finance subsidiary of Dominion, which holds 100% of the voting interests. The trusts sold capital securities representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trusts. In exchange for the funds realized from the sale of the capital securities and common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trusts, Dominion issued various junior subordinated notes. The junior subordinated notes constitute 100% of each capital trust’s assets. Each trust must redeem its capital securities when their respective junior subordinated notes are repaid at maturity or if redeemed prior to maturity.

In January 2013, Dominion repaid its $258 million 7.83% unsecured junior subordinated debentures and redeemed all 250 thousand units of the $250 million 7.83% Dominion Resources Capital Trust I capital securities due December 1, 2027. The securities were redeemed at a price of $1,019.58 per capital security plus accrued and unpaid distributions.

Interest charges related to Dominion’s junior subordinated notes payable to affiliated trusts were $1 million for the years ended December 31, 2014 and 2013 and $21 million for the year ended December 31, 2012.

Enhanced Junior Subordinated Notes

In June 2006 and September 2006, Dominion issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids bear interest at 7.5% per year until June 30, 2016. Thereafter, they will bear interest at the three-month LIBOR plus 2.825%, reset quarterly. The September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly.

 

 

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In June 2009, Dominion issued $685 million of 8.375% June 2009 hybrids. The June 2009 hybrids were listed on the NYSE under the symbol DRU.

In October 2014, Dominion issued $685 million of October 2014 hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly.

Dominion may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.

Dominion executed RCCs in connection with its issuance of the June 2006 hybrids, the September 2006 hybrids, and the June 2009 hybrids. Under the terms of the RCCs, Dominion covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. In September 2011, Dominion amended the RCCs of the June 2006 hybrids and September 2006 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock issuances from 180 days to 365 days. In July 2014, Dominion amended the RCC of the June 2009 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock or other equity-like issuances from 180 days to 365 days. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.

In 2012, Dominion launched a tender offer to purchase up to $150 million of September 2006 hybrids. Dominion purchased and canceled approximately $88 million of the September 2006 hybrids primarily as a result of this tender offer, which expired in

2012. As part of Dominion’s Liability Management Exercise, in October 2014, Dominion redeemed all $685 million of the June 2009 hybrids plus accrued interest with the net proceeds from the issuance of the October 2014 hybrids. The redemption and all purchases were conducted in compliance with the RCCs.

Remarketable Subordinated Notes

In June 2013, Dominion issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B 6% Equity Units, initially in the form of Corporate Units. In July 2014, Dominion issued $1 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbols DCUA, DCUB and DCUC, respectively.

Each Corporate Unit consists of a stock purchase contract and 1/20 interest in a RSN issued by Dominion. The stock purchase contracts obligate the holders to purchase shares of Dominion common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is $50 per Corporate Unit and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion common stock near the settlement date. The RSNs are pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.

Dominion makes quarterly interest payments on the RSNs and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. Dominion may defer payments on the stock purchase contracts and the RSNs for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, Dominion may not make any cash distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the RSNs.

Dominion has recorded the present value of the stock purchase contract payments as a liability offset by a charge to equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, Dominion applies the treasury stock method to the Equity Units.

 

 

Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion will issue between 8.4 million and 9.9 million shares of its common stock in both April 2016 and July 2016 and between 11.5 million and 14.3 million shares in July 2017. A total of 40.3 million shares of Dominion’s common stock has been reserved for issuance in connection with the stock purchase contracts.

Selected information about Dominion’s Equity Units is presented below:

 

Issuance Date    Units
Issued
     Total Net
Proceeds
     Total
Long-term
Debt
     RSN Annual
Interest Rate
    Stock Purchase
Contract Annual
Rate
    Stock Purchase
Contract Liability(1)
     Stock Purchase
Settlement Date
     RSN Maturity
Date
 
(millions, except interest rates)                                                      

6/7/2013

     11       $ 533.5       $ 550.0         1.070     5.055   $ 76.7         4/1/2016         4/1/2021   

6/7/2013

     11       $ 553.5       $ 550.0         1.180     4.820   $ 79.3         7/1/2016         7/1/2019   

7/1/2014

     20       $ 982.0       $ 1,000.0         1.500     4.875   $ 142.8         7/1/2017         7/1/2020   

 

(1) Payments of $66 million and $17 million were made in 2014 and 2013, respectively. The stock purchase contract liability was $216 million and $139 million at December 31, 2014 and 2013, respectively.

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

Dominion Gas Financing

In June 2014, Dominion Gas commenced an offer to exchange $1.2 billion principal amount of unsecured senior notes that were issued in a private placement in October 2013. The exchange offer satisfied Dominion Gas’ obligations under a registration rights agreement entered into in connection with the issuance of the Dominion Gas 2013 Senior Notes. The exchange offer did not represent a new financing transaction and there were no proceeds to Dominion Gas when the offer settled in August 2014.

 

 

 

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NOTE 18. PREFERRED STOCK

Dominion is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2014 or 2013.

Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference, and had 2.59 million preferred shares issued and outstanding at December 31, 2013.

During 2014, Virginia Power redeemed all outstanding series of its preferred stock. Upon redemption, each series was no longer outstanding for any purpose and dividends ceased to accumulate. Presented below is a summary of the preferred stock redemptions:

 

Dividend    Total
Shares
    

Redemption
Price per
Share

 
     (thousands)  

$5.00

     107       $ 112.50 (1) 

4.04

     13         102.27 (1) 

4.20

     15         102.50 (1) 

4.12

     32         103.73 (1) 

4.80

     73         101.00 (1) 

7.05

     500         100.00 (1) 

6.98

     600         100.00 (1) 

Flex Money Market Preferred 12/02, Series A

     1,250         100.00 (2) 

Total

     2,590            

 

(1) As part of Dominion’s Liability Management Exercise, in September 2014, Virginia Power provided irrevocable notice to redeem all shares outstanding for each series of preferred stock. In October 2014, the stock was redeemed at the applicable price per share plus accumulated and unpaid dividends.
(2) In February 2014, Virginia Power provided irrevocable notice to redeem the stock. In March 2014, the stock was redeemed at the applicable price per share plus accumulated and unpaid dividends at a rate reset in March 2011 of 6.12%. Dividends ceased accumulating on the stock upon payment of the redemption price, thus the rate was not reset in March 2014.

 

 

NOTE 19. EQUITY

Issuance of Common Stock

DOMINION

Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2014, Dominion began purchasing its common stock on the open market for these plans. In April 2014, Dominion began issuing new common shares for these direct stock purchase plans.

During 2014, Dominion issued approximately 3.8 million shares of common stock through various programs. Dominion received cash proceeds of $205 million from the issuance of 2.9 million of such shares through Dominion Direct and employee savings plans.

In December 2014, Dominion filed an SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at-the-market program. Also in December 2014, Dominion entered into four separate sales agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion and the sales agents and in conformance with applicable securities laws. At December 31, 2014, a total of 7 million shares of Dominion’s common stock was reserved for issuance in connection with this program. In 2015, Dominion provided sales instructions to one of the sales agents and has issued 2.7 million shares through at-the-market issuances and received cash proceeds of $207 million, net of fees and commissions paid of $2 million. Following these issuances, Dominion has the ability to issue up to $291 million of stock under the 2014 sales agency agreements.

VIRGINIA POWER

In 2014, 2013 and 2012, Virginia Power did not issue any shares of its common stock to Dominion.

DOMINION GAS

On September 30, 2013, Dominion contributed its wholly-owned subsidiaries DTI, East Ohio and Dominion Iroquois to Dominion Gas in exchange for 100% of its limited liability company membership interests.

Shares Reserved for Issuance

At December 31, 2014, Dominion had approximately 56 million shares reserved and available for issuance for Dominion Direct®, employee stock awards, employee savings plans, director stock compensation plans, an at-the-market program and issuance in connection with stock purchase contracts. See Note 17 for more information.

Repurchase of Common Stock

Dominion did not repurchase any shares in 2014 or 2013 and does not plan to repurchase shares during 2015, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization.

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

Accumulated Other Comprehensive Income (Loss)

Presented in the table below is a summary of AOCI by component:

 

At December 31,    2014     2013  
(millions)             

Dominion

    

Net deferred losses on derivatives-hedging activities, net of tax of $116 and $196

   $ (178   $ (288

Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(333) and $(307)

     548        474   

Net unrecognized pension and other postretirement benefit costs, net of tax of $530 and $365

     (782     (510

Other comprehensive loss from equity method investees, net of tax of $3 and $—

     (4       

Total AOCI

   $ (416   $ (324

Virginia Power

    

Net deferred losses on derivatives-hedging activities, net of tax of $4 and $—

   $ (7   $   

Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(35) and $(30)

     57        48   

Total AOCI

   $ 50      $ 48   

Dominion Gas

    

Net deferred gains (losses) on derivatives-hedging activities, net of tax of $11 and $(1)

   $ (20   $ 3   

Net unrecognized pension and other postretirement benefit costs, net of tax of $46 and $43

     (66     (61

Total AOCI

   $ (86   $ (58

DOMINION

The following table presents Dominion’s changes in AOCI by component, net of tax:

 

     Deferred gains
and losses on
derivatives-
hedging
activities
   

Unrealized

gains and
losses on
investment
securities

    Unrecognized
pension and
other
postretirement
benefit costs
   

Other
comprehensive
loss from

equity method
investees

    Total  
(millions)                              

Year Ended December 31, 2014

         

Beginning balance

  $ (288   $ 474      $ (510   $      $ (324

Other comprehensive income before reclassifications: gains (losses)

    17        128        (305     (4     (164

Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)

    93        (54     33               72   

Net current period other comprehensive income (loss)

    110        74        (272     (4     (92

Ending balance

  $ (178   $ 548      $ (782   $ (4   $ (416

Year Ended December 31, 2013

         

Beginning balance

  $ (122   $ 326      $ (1,081   $      $ (877

Other comprehensive income before reclassifications: gains (losses)

    (243     203        516               476   

Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)

    77        (55     55               77   

Net current period other comprehensive income (loss)

    (166     148        571               553   

Ending balance

  $ (288   $ 474      $ (510   $      $ (324

 

(1) See table below for details about these reclassifications.
 

 

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The following table presents Dominion’s reclassifications out of AOCI by component:

 

Details about AOCI components    Amounts reclassified
from AOCI
   

Affected line item in the

Consolidated Statements of
Income

(millions)           

Year Ended December 31, 2014

    

Deferred (gains) and losses on derivatives-hedging activities:

    

Commodity contracts

   $ 130      Operating revenue
     13      Purchased gas
     (7   Electric fuel and other
energy-related purchases

Interest rate contracts

     16      Interest and related
charges

Total

     152     

Tax

     (59   Income tax expense

Total, net of tax

   $ 93       

Unrealized (gains) and losses on investment securities:

    

Realized (gain) loss on sale of securities

   $ (100   Other income

Impairment

     13      Other income

Total

     (87  

Tax

     33      Income tax expense

Total, net of tax

   $ (54    

Unrecognized pension and other postretirement benefit costs:

    

Prior-service costs (credits)

   $ (12   Other operations and
maintenance

Actuarial losses

     69      Other operations and
maintenance

Total

     57     

Tax

     (24   Income tax expense

Total, net of tax

   $ 33       

Year Ended December 31, 2013

    

Deferred (gains) and losses on derivatives-hedging activities:

    

Commodity contracts

   $ 58      Operating revenue
     47      Purchased gas
     10      Electric fuel and other
energy-related purchases

Interest rate contracts

     15      Interest and related
charges

Total

     130     

Tax

     (53   Income tax expense

Total, net of tax

   $ 77       
Details about AOCI components    Amounts reclassified
from AOCI
   

Affected line item in the

Consolidated Statements of
Income

(millions)           

Unrealized (gains) and losses on investment securities:

    

Realized (gain) loss on sale of securities

   $ (98   Other
income

Impairment

     8      Other
income

Total

     (90  

Tax

     35      Income tax
expense

Total, net of tax

   $ (55    

Unrecognized pension and other postretirement benefit costs:

    

Prior-service costs (credits)

   $ (8   Other
operations
and
maintenance

Actuarial losses

     102      Other
operations
and
maintenance

Total

     94     

Tax

     (39   Income tax
expense

Total, net of tax

   $ 55       
 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

VIRGINIA POWER

The following table presents Virginia Power’s changes in AOCI by component, net of tax:

 

      Deferred gains
and losses on
derivatives-
hedging
activities
    Unrealized gains
and losses on
investment
securities
    Total  
(millions)                   

Year Ended December 31, 2014

      

Beginning balance

   $      $ 48      $ 48   

Other comprehensive income before reclassifications: gains (losses)

     (4     15        11   

Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)

     (3     (6     (9

Net current period other comprehensive income (loss)

     (7     9        2   

Ending balance

   $ (7   $ 57      $ 50   

Year Ended December 31, 2013

      

Beginning balance

   $ (6   $ 31      $ 25   

Other comprehensive income before reclassifications: gains (losses)

     6        20        26   

Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)

            (3     (3

Net current period other comprehensive income (loss)

     6        17        23   

Ending balance

   $      $ 48      $ 48   

 

(1) See table below for details about these reclassifications.

The following table presents Virginia Power’s reclassifications out of AOCI by component:

 

Details about AOCI components   

Amounts

reclassified
from AOCI

    Affected line item in the
Consolidated Statements  of
Income
(millions)           

Year Ended December 31, 2014

    

(Gains) losses on cash flow hedges:

    

Commodity contracts

   $ (5   Electric fuel and other energy related purchases

Total

     (5  

Tax

     2      Income tax expense

Total, net of tax

   $ (3    

Unrealized (gains) and losses on investment securities:

    

Realized (gain) loss on sale of securities

   $ (10   Other income

Total

     (10  

Tax

     4      Income tax expense

Total, net of tax

   $ (6    

Year Ended December 31, 2013

    

Unrealized (gains) and losses on investment securities:

    

Realized (gain) loss on sale of securities

   $ (6   Other income

Impairment

     1      Other income

Total

     (5  

Tax

     2      Income tax expense

Total, net of tax

   $ (3    
 

 

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DOMINION GAS

The following table presents Dominion Gas’ changes in AOCI by component, net of tax:

 

      Deferred gains
and losses on
derivatives-
hedging
activities
   

Unrecognized

pension and
other
postretirement
benefit costs

    Total  
(millions)                   

Year Ended December 31, 2014

      

Beginning balance

   $ 3      $ (61   $ (58

Other comprehensive income before reclassifications: gains (losses)

     (31     (10     (41

Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)

     8        5        13   

Net current period other comprehensive income (loss)

     (23     (5     (28

Ending balance

   $ (20   $ (66   $ (86

Year Ended December 31, 2013

      

Beginning balance

   $ (47   $ (93   $ (140

Other comprehensive income before reclassifications: gains (losses)

     39        26        65   

Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)

     11        6        17   

Net current period other comprehensive income (loss)

     50        32        82   

Ending balance

   $ 3      $ (61   $ (58

 

(1) See table below for details about these reclassifications.

The following table presents Dominion Gas’ reclassifications out of AOCI by component:

 

Details about AOCI
components
   Amounts reclassified
from AOCI
    Affected line item in the
Consolidated Statements of Income
(millions)           

Year Ended December 31, 2014

    

Deferred (gains) and losses on derivatives-hedging activities:

    

Commodity contracts

   $ (2   Operating revenue
     14      Purchased gas
       1      Interest and related charges

Total

     13     

Tax

     (5   Income tax expense

Total, net of tax

   $ 8       

Unrecognized pension and other postretirement benefit costs:

    

Prior service costs

   $ 1      Other operations and maintenance

Actuarial losses

     7      Other operations and maintenance

Total

     8     

Tax

     (3   Income tax expense

Total, net of tax

   $ 5       

Year Ended December 31, 2013

    

Deferred (gains) and losses on derivatives-hedging activities: Commodity contracts

   $ 2      Operating revenue
       14      Purchased gas

Total

     16     

Tax

     (5   Income tax expense

Total, net of tax

   $ 11       

Unrecognized pension and other postretirement benefit costs:

    

Prior service costs

   $ 1      Other operations and maintenance

Actuarial losses

     9      Other operations and maintenance

Total

     10     

Tax

     (4   Income tax expense

Total, net of tax

   $ 6       
 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

Stock-Based Awards

The 2005 and 2014 Incentive Compensation Plans permit stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of these plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. At December 31, 2014, approximately 31 million shares were available for future grants under these plans.

Dominion measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion’s results for the years ended December 31, 2014, 2013 and 2012 include $39 million, $31 million, and $25 million, respectively, of compensation costs and $14 million, $11 million, and $8 million, respectively of income tax benefits related to Dominion’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. Excess tax benefits are classified as a financing cash flow. During the years ended December 31, 2014, 2013, and 2012, Dominion realized less than $1 million, less than $1 million and $10 million, respectively, of excess tax benefits from the vesting of restricted stock awards and exercise of stock options.

RESTRICTED STOCK

Restricted stock grants are made to officers under Dominion’s LTIP and may also be granted to certain key non-officer employees from time to time. The fair value of Dominion’s restricted stock awards is equal to the closing price of Dominion’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2014, 2013 and 2012:

 

      Shares    

Weighted

- average

Grant Date

Fair Value

 
     (thousands)        

Nonvested at December 31, 2011

     1,301      $ 37.37   

Granted

     390        51.14   

Vested

     (596     33.31   

Cancelled and forfeited

     (10     42.99   

Nonvested at December 31, 2012

     1,085      $ 44.46   

Granted

     312        54.70   

Vested

     (356     39.00   

Cancelled and forfeited

     (34     51.11   

Nonvested at December 31, 2013

     1,007      $ 49.35   

Granted

     354        67.98   

Vested

     (278     44.50   

Cancelled and forfeited

     (18     53.61   

Nonvested at December 31, 2014

     1,065      $ 56.74   

As of December 31, 2014, unrecognized compensation cost related to nonvested restricted stock awards totaled $27 million and is expected to be recognized over a weighted-average period of 1.8 years. The fair value of restricted stock awards that vested was $19 million, $20 million, and $30 million in 2014, 2013 and 2012, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion stock and the applicable federal, state and local tax withholding rates.

GOAL-BASED STOCK

Goal-based stock awards are granted under Dominion’s LTIP to officers who have not achieved a certain targeted level of share ownership, in lieu of cash-based performance grants. Goal-based stock awards may also be made to certain key non-officer employees from time to time. Current outstanding goal-based shares include awards granted to officers in February 2013 and February 2014.

The issuance of awards is based on the achievement of two performance metrics during a two-year period: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The actual number of shares issued will vary between zero and 200% of targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is equal to the closing price of Dominion’s stock on the date of grant. Goal-based stock awards granted to key non-officer employees convert to restricted stock at the end of the two-year performance period and generally vest three years from the original grant date. Awards to officers vest at the end of the two-year performance period. All goal-based stock awards are settled by issuing new shares.

The following table provides a summary of goal-based stock activity for the years ended December 31, 2014, 2013 and 2012:

 

     

Targeted

Number of

Shares

   

Weighted

- average

Grant

Date Fair

Value

 
     (thousands)        

Nonvested at December 31, 2011

     12      $ 39.19   

Granted

     1        52.48   

Vested

     (9     37.46   

Nonvested at December 31, 2012

     4      $ 45.60   

Granted

     4        54.17   

Vested

     (2     43.54   

Cancelled and forfeited

     (1     43.54   

Nonvested at December 31, 2013

     5      $ 53.85   

Granted

     13        68.83   

Vested

     (1     52.48   

Nonvested at December 31, 2014

     17      $ 65.15   

At December 31, 2014, the targeted number of shares expected to be issued under the February 2013 and February 2014 awards was approximately 17 thousand. In January 2015, the CGN Committee determined the actual performance against metrics established for the February 2013 awards with a performance period that ended December 31, 2014. Based on that determination, the total number of shares to be issued under the February 2013 goal-based stock awards was approximately 7 thousand.

 

 

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As of December 31, 2014, unrecognized compensation cost related to nonvested goal-based stock awards was not material.

CASH-BASED PERFORMANCE GRANTS

Cash-based performance grants are made to Dominion’s officers under Dominion’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.

In February 2011, a cash-based performance grant was made to officers. A portion of the grant, representing $6 million was paid in December 2012, based on the achievement of two performance metrics during 2011 and 2012: ROIC and TSR relative to that of a peer group of companies. The total amount of the award under the grant was $8 million and the remaining $2 million of the grant was paid in February 2013.

In February 2012, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $8 million was paid in December 2013, based on the achievement of two performance metrics during 2012 and 2013: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total amount of the award under the grant was $12 million and the remaining portion of the grant was paid in January 2014.

In February 2013, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $14 million was paid in December 2014, based on the achievement of two performance metrics during 2013 and 2014: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total expected award under the grant is $21 million and the remaining portion of the grant is expected to be paid by March 15, 2015. At December 31, 2014, a liability of $7 million had been accrued for the remaining portion of the award.

In February 2014, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2016 based on the achievement of two performance metrics during 2014 and 2015: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. At December 31, 2014, the targeted amount of the grant was $13 million and a liability of $3 million had been accrued for this award.

 

 

NOTE 20. DIVIDEND RESTRICTIONS

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2014, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

The Ohio Commission may prohibit any public service company, including East Ohio, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2014, the Ohio Commission had not restricted the payment of dividends by East Ohio.

Certain agreements associated with the Companies’ credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Companies’ ability to pay dividends or receive dividends from their subsidiaries at December 31, 2014.

See Note 17 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes and equity units, initially in the form of corporate units.

 

 

NOTE 21. EMPLOYEE BENEFIT PLANS

Dominion and Dominion Gas - Defined Benefit Plans

Dominion provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Gas participates in a number of the Dominion-sponsored retirement plans. Under the terms of its benefit plans, Dominion reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension program also provides benefits to certain retired executives under a company-sponsored nonqualified employee benefit plan. The nonqualified plan is funded through contributions to a grantor trust. Dominion also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service.

Pension benefits for Dominion Gas employees not represented by collective bargaining units are covered by the Dominion Pension Plan, a defined benefit pension plan sponsored by Dominion that provides benefits to multiple Dominion subsidiaries. Pension benefits for Dominion Gas employees represented by collective bargaining units are covered by separate pension plans for East Ohio and, for DTI, a plan that provides benefits to employees of both DTI and Hope. Employee compensation is the basis for allocating pension costs and obligations between DTI and Hope and determining East Ohio’s share of total pension costs.

Retiree healthcare and life insurance benefits for Dominion Gas employees not represented by collective bargaining units are covered by the Dominion Retiree Health and Welfare Plan, a plan sponsored by Dominion that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Retiree healthcare and life insurance benefits for Dominion Gas employees represented by collective bargaining units are covered by separate other postretirement benefit plans for East Ohio and, for DTI, a plan that provides benefits to both DTI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DTI and Hope and determining East Ohio’s share of total other postretirement benefit costs.

Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates, mortality rates and the rate of compensation increases.

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

Dominion uses December 31 as the measurement date for all of its employee benefit plans, including those in which Dominion Gas participates. Dominion uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost, for all pension plans, including those in which Dominion Gas participates. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.

Dominion’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Aggregate actual returns for Dominion’s pension and other postretirement plan assets were $706 million in 2014 and $959 million in 2013, versus expected returns of $610 million and $554 million, respectively. Aggregate actual returns for pension and other postretirement benefit plan assets for Dominion Gas employees represented by collective bargaining units were $157 million in 2014 and $214 million in 2013, versus expected returns of $138 million and $125 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

The Medicare Act introduced a federal subsidy to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Dominion determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D. Dominion received a federal subsidy of $4 million and $5 million for 2014 and 2013, respectively. Dominion Gas received a federal subsidy of $1 million for each of 2014 and 2013. Effective January 1, 2013, Dominion changed its method of receiving the subsidy under Medicare Part D for retiree prescription drug coverage from the Retiree Drug Subsidy to the EGWP. This change reduced other postretirement benefit costs by approximately $20 million annually beginning in 2012. As a result of the adoption of the EGWP, Dominion will begin to receive an increased level of Medicare Part D subsidies, in the form of reduced costs rather than a direct reimbursement, over the next few years.

In October 2014, the Society of Actuaries published new mortality tables and mortality improvement scales. Such tables and scales are used to develop mortality assumptions for use in determining pension and other postretirement benefit liabilities and expense. Following evaluation of the new tables, Dominion changed its assumption for mortality rates to reflect a generational improvement scale. As a result of this change in assumption, at December 31, 2014 Dominion and Dominion Gas (for employ-

ees represented by collective bargaining units) increased their pension benefit obligations by $131 million and $10 million, respectively, and increased their accumulated postretirement benefit obligations by $32 million and $7 million, respectively. This change is expected to increase net periodic benefit cost for Dominion and Dominion Gas (for employees represented by collective bargaining units) by approximately $25 million and $3 million, respectively, for 2015.

Dominion remeasured all of its pension and other postretirement benefit plans in the second quarter of 2013. The remeasurement resulted in a reduction in the pension benefit obligation of approximately $354 million and a reduction in the accumulated postretirement benefit obligation of approximately $78 million. For Dominion Gas employees represented by collective bargaining units, the remeasurement resulted in a reduction in the pension benefit obligation of approximately $28 million and a reduction in the accumulated postretirement benefit obligation of approximately $9 million. The impact of the remeasurement on net periodic benefit (credit) cost was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by approximately $36 million, excluding the impacts of curtailments, and for Dominion Gas employees represented by collective bargaining units by approximately $2 million. The discount rate used for the remeasurement was 4.80% for the pension plans and 4.70% for the other postretirement benefit plans. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.

In the fourth quarter of 2013, Dominion remeasured its other postretirement benefit plans as a result of a plan amendment that changed medical coverage for certain Medicare-eligible retirees effective April 2014. The remeasurement resulted in a reduction in the accumulated postretirement benefit obligation of approximately $220 million. The impact of the remeasurement on net periodic benefit (credit) cost was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by approximately $8 million. The amendment is expected to reduce net periodic benefit cost by $40 million to $60 million for each of the next five years. The discount rate used for the remeasurement was 4.80%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.

In the third quarter of 2014, East Ohio remeasured its other postretirement benefit plan as a result of an amendment that changed medical coverage upon the attainment of age 65 for certain future retirees effective January 1, 2016. For employees represented by collective bargaining units, the remeasurement resulted in an increase in the accumulated postretirement benefit obligation of approximately $22 million. The impact of the remeasurement on net periodic benefit credit was recognized prospectively from the remeasurement date and reduced net periodic benefit credit for 2014, for employees represented by collective bargaining units, by less than $1 million. The discount rate used for the remeasurement was 4.20% and the expected long-term rate of return used was 8.50%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2013.

 

 

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Funded Status

The following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status for Dominion and Dominion Gas (for employees represented by collective bargaining units):

 

      Pension Benefits     Other Postretirement Benefits  
Year Ended December 31,    2014     2013     2014     2013  
(millions, except percentages)                         

DOMINION

        

Changes in benefit obligation:

        

Benefit obligation at beginning of year

   $ 5,625      $ 6,125      $ 1,360      $ 1,719   

Service cost

     114        131        32        43   

Interest cost

     290        271        67        73   

Benefits paid

     (236     (229     (78     (75

Actuarial (gains) losses during the year

     887        (650     177        (170

Plan amendments(1)

            1        9        (220

Settlements and curtailments(2)

     (13     (24            (16

Special termination benefits

                          1   

Medicare Part D reimbursement

                   4        5   

Benefit obligation at end of year

   $ 6,667      $ 5,625      $ 1,571      $ 1,360   

Changes in fair value of plan assets:

        

Fair value of plan assets at beginning of year

   $ 6,113      $ 5,553      $ 1,315      $ 1,156   

Actual return on plan assets

     601        781        105        178   

Employer contributions

     15        8        12        12   

Benefits paid

     (236     (229     (30     (31

Settlements(2)

     (13                     

Fair value of plan assets at end of year

   $ 6,480      $ 6,113      $ 1,402      $ 1,315   

Funded status at end of year

   $ (187   $ 488      $ (169   $ (45

Amounts recognized in the Consolidated Balance Sheets at December 31:

        

Noncurrent pension and other postretirement benefit assets

   $ 946      $ 913      $ 10      $ 29   

Other current liabilities

     (13     (15     (3     (3

Noncurrent pension and other postretirement benefit liabilities

     (1,120     (410     (176     (71

Net amount recognized

   $ (187   $ 488      $ (169   $ (45

Significant assumptions used to determine benefit obligations as of December 31:

        

Discount rate(3)

     4.40%        5.20%/5.30%        4.40%        5.00%/5.10%   

Weighted average rate of increase for compensation

     4.22%        4.21%        4.22%        4.22%   

Expected long-term rate of return on plan assets

     8.75%        8.50%        8.50%        7.75%   

DOMINION GAS

        

Changes in benefit obligation:

        

Benefit obligation at beginning of year

   $ 563      $ 607      $ 269      $ 287   

Service cost

     12        13        6        7   

Interest cost

     28        27        13        12   

Benefits paid

     (29     (27     (16     (17

Actuarial (gains) losses during the year

     64        (57     38        (21

Plan amendments

                   9          

Medicare Part D reimbursement

                   1        1   

Benefit obligation at end of year

   $ 638      $ 563      $ 320      $ 269   

Changes in fair value of plan assets:

        

Fair value of plan assets at beginning of year

   $ 1,403      $ 1,254      $ 273      $ 242   

Actual return on plan assets

     136        176        21        38   

Employer contributions

                   10        10   

Benefits paid

     (29     (27     (16     (17

Fair value of plan assets at end of year

   $ 1,510      $ 1,403      $ 288      $ 273   

Funded status at end of year

   $ 872      $ 840      $ (32   $ 4   

Amounts recognized in the Consolidated Balance Sheets at December 31:

        

Noncurrent pension and other postretirement benefit assets

   $ 872      $ 840      $      $ 19   

Noncurrent pension and other postretirement benefit liabilities(4)

                   (32     (15

Net amount recognized

   $ 872      $ 840      $ (32   $ 4   

Significant assumptions used to determine benefit obligations as of December 31:

        

Discount rate

     4.40%        5.20%        4.40%        5.00%   

Weighted average rate of increase for compensation

     3.93%        3.93%        3.93%        3.93%   

Expected long-term rate of return on plan assets

     8.75%        8.50%        8.50%        7.75%   

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

(1) 2013 other postretirement benefits amount relates to a plan amendment that changed medical coverage for certain Medicare-eligible retirees.
(2) 2014 amounts relate primarily to a settlement charge for certain executives. 2013 amounts relate primarily to the decommissioning of Kewaunee.
(3) 2013 pension and other postretirement benefits discount rates: 5.20% and 5.00% for the gas union plans and 5.30% and 5.10% for the nonunion and other union plans, respectively.
(4) Reflected in other deferred credits and other liabilities in Dominion Gas’ Consolidated Balance Sheets.

The ABO for all of Dominion’s defined benefit pension plans was $6.0 billion and $5.1 billion at December 31, 2014 and 2013, respectively. The ABO for the defined benefit pension plans covering Dominion Gas employees represented by collective bargaining units was $604 million and $534 million at December 31, 2014 and 2013, respectively.

Under its funding policies, Dominion evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion determines the amount of contributions for the current year, if any, at that time. During 2014, Dominion and Dominion Gas made no contributions to the qualified defined benefit pension plans and no contributions are currently expected in 2015. In July 2012, the MAP 21 Act was signed into law. This Act includes an increase in the interest rates used to determine plan sponsors’ pension contributions for required funding purposes. In 2014, the HATFA of 2014 was signed into law. Similar to the MAP 21 Act, the HATFA of 2014 adjusts the rules for calculating interest rates used in determining funding obligations. It is estimated that the new interest rates will reduce required pension contributions through 2019. Dominion believes that required pension contributions will rise subsequent to 2019, resulting in an estimated $200 million reduction in net cumulative required contributions over a 10-year period.

Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion’s subsidiaries, including Dominion Gas, fund other postretirement benefit costs through VEBAs. Dominion’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion’s contributions to VEBAs, all of which pertained to Dominion Gas employees, totaled $12 million for both 2014 and 2013, and Dominion expects to contribute approximately $12 million to the Dominion VEBAs in 2015, all of which pertains to Dominion Gas employees.

Dominion and Dominion Gas do not expect any pension or other postretirement plan assets to be returned during 2015.

The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets for Dominion and Dominion Gas (for employees represented by collective bargaining units):

 

      Pension Benefits      Other Postretirement
Benefits
 
As of December 31,    2014      2013      2014      2013  
(millions)                            

DOMINION

           

Benefit obligation

   $ 5,970       $ 4,978       $ 1,564       $ 1,233   

Fair value of plan assets

     4,838         4,553         1,385         1,158   

DOMINION GAS

           

Benefit obligation

   $       $       $ 320       $ 147   

Fair value of plan assets

                     288         132   

The following table provides information on the ABO and fair value of plan assets for Dominion’s pension plans with an ABO in excess of plan assets:

 

As of December 31,    2014      2013  
(millions)              

Accumulated benefit obligation

   $ 5,370       $ 114   

Fair value of plan assets

     4,838           

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans:

 

      Estimated Future Benefit Payments  
      Pension Benefits      Other Postretirement
Benefits
 
(millions)              

DOMINION

     

2015

   $ 272       $ 91   

2016

     284         94   

2017

     300         98   

2018

     320         101   

2019

     333         102   
2020-2024    1,925      523  

DOMINON GAS

     

2015

   $ 34       $ 18   

2016

     35         19   

2017

     37         20   

2018

     38         21   

2019

     39         22   

2020-2024

     204         111   

Plan Assets

Dominion’s overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. As a participating employer in various pension plans sponsored by Dominion, Dominion Gas is subject to Dominion’s investment policies for such plans. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for Dominion’s pension funds are 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the United States.

 

 

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Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the United States including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity REITs and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.

Dominion also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.

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 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. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.

For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

The fair values of Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) pension plan assets by asset category are as follows:

 

      Fair Value Measurements  
      Pension Plans  
At December 31,    2014      2013  
      Level 1      Level 2      Level 3      Total      Level 1      Level 2      Level 3      Total  
(millions)                                                        

DOMINION

                       

Cash equivalents

   $ 13       $ 25       $       $ 38       $ 53       $ 126       $       $ 179   

U.S. equity:

                       

Large Cap

     1,313                         1,313         1,220                         1,220   

Other

     530                         530         514                         514   

Non-U.S. equity:

                       

Large Cap

     234                         234         308                         308   

Other

     403                         403         391                         391   

Common/collective trust funds(1)

             1,595                 1,595                 1,387                 1,387   

Fixed income:

                       

Corporate debt instruments

     45         666                 711         43         451                 494   

U.S. Treasury securities and agency debentures

     74         342                 416         2         229                 231   

State and municipal

     10         60                 70         69         107                 176   

Other securities

     6         80                 86         7         50                 57   

Real estate:

                       

REITs

     40                         40         32                         32   

Partnerships

                     209         209                         227         227   

Other alternative investments:

                       

Private equity

                     518         518                         530         530   

Debt

                     144         144                         180         180   

Hedge funds

                     162         162                         187         187   

Total(2)

   $ 2,668       $ 2,768       $ 1,033       $ 6,469       $ 2,639       $ 2,350       $ 1,124       $ 6,113   

DOMINION GAS

                       

Cash equivalents

   $ 3       $ 6       $       $ 9       $ 12       $ 29       $       $ 41   

U.S. equity:

                       

Large Cap

     306                         306         280                         280   

Other

     124                         124         118                         118   

Non-U.S. equity:

                       

Large Cap

     54                         54         72                         72   

Other

     94                         94         90                         90   

Common/collective trust funds(3)

             372                 372                 318                 318   

Fixed income:

                       

Corporate debt instruments

     11         155                 166         10         103                 113   

U.S. Treasury securities and agency debentures

     17         80                 97         1         52                 53   

State and municipal

     2         14                 16         16         24                 40   

Other securities

     1         19                 20         2         11                 13   

Real estate:

                       

REITs

     9                         9         7                         7   

Partnerships

                     48         48                         52         52   

Other alternative investments:

                       

Private equity

                     121         121                         122         122   

Debt

                     34         34                         41         41   

Hedge funds

                     38         38                         43         43   

Total(4)

   $ 621       $ 646       $ 241       $ 1,508       $ 608       $ 537       $ 258       $ 1,403   
(1) Common/Collective Trust Funds include $360 million and $560 million of John Hancock insurance contracts held at December 31, 2014 and 2013, respectively. See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund.
(2) Includes net assets related to pending sales of securities of $31 million, net accrued income of $18 million, and excludes net assets related to pending purchases of securities of $38 million at December 31, 2014.
(3) See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund.
(4) Includes net assets related to pending sales of securities of $7 million, net accrued income of $4 million, and excludes net assets related to pending purchases of securities of $9 million at December 31, 2014.

 

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The fair values of Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) other postretirement plan assets by asset category are as follows:

 

      Fair Value Measurements  
      Other Postretirement Plans  
At December 31,    2014      2013  
      Level 1      Level 2      Level 3      Total      Level 1      Level 2      Level 3      Total  
(millions)                                                        

DOMINION

                       

Cash equivalents

   $ 1       $ 7       $       $ 8       $ 3       $ 14       $       $ 17   

U.S. equity:

                       

Large Cap

     514                         514         472                         472   

Other

     28                         28         26                         26   

Non-U.S. equity:

                       

Large Cap

     102                         102         111                         111   

Other

     21                         21         20                         20   

Common/collective trust funds(1)

             555                 555                 502                 502   

Fixed income:

                       

Corporate debt instruments

     3         35                 38         2         23                 25   

U.S. Treasury securities and agency debentures

     4         18                 22                 12                 12   

State and municipal

     1         3                 4         4         5                 9   

Other securities

             4                 4                 3                 3   

Real estate:

                       

REITs

     2                         2         2                         2   

Partnerships

                     19         19                         19         19   

Other alternative investments:

                       

Private equity

                     58         58                         60         60   

Debt

                     18         18                         27         27   

Hedge funds

                     9         9                         10         10   

Total

   $ 676       $ 622       $ 104       $ 1,402       $ 640       $ 559       $ 116       $ 1,315   

DOMINION GAS

                       

Cash equivalents

   $       $ 2       $       $ 2       $       $ 3       $       $ 3   

U.S. equity-Large Cap

     113                         113         104                         104   

Non-U.S. equity-Large Cap

     26                         26         26                         26   

Common/collective trust funds(2)

             129                 129                 119                 119   

Real estate-partnerships

                     2         2                         2         2   

Other alternative investments:

                       

Private equity

                     12         12                         12         12   

Debt

                     4         4                         7         7   

Total

   $ 139       $ 131       $ 18       $ 288       $ 130       $ 122       $ 21       $ 273   

 

(1) Common/Collective Trust Funds include $19 million and $29 million of John Hancock insurance contracts held at December 31, 2014 and 2013, respectively. See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund.
(2) See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund.

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

The following table presents the changes in pension and other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category for Dominion and Dominion Gas (for employees represented by collective bargaining units):

 

      Fair Value Measurements using Significant Unobservable Inputs (Level 3)  
      Pension Plans     Other Postretirement Plans  
      Real
Estate
    Private
Equity
    Debt     Hedge
Funds
    Total     Real
Estate
    Private
Equity
    Debt      Hedge
Funds
     Total  
(millions)                                                               

DOMINION

                      

Balance at December 31, 2011

   $ 304      $ 448      $ 243      $ 290      $ 1,285      $ 24      $ 63      $ 36       $ 14       $ 137   

Actual return on plan assets:

                      

Relating to assets still held at the reporting date

     21        46        17        21        105        1        3        4         1         9   

Relating to assets sold during the period

     (8     (41     (11     (2     (62            (1                     (1

Purchases

     35        79        15               129        2        6        1                 9   

Sales

     (31     (76     (72     (88     (267     (3     (13     (10      (4      (30

Balance at December 31, 2012

   $ 321      $ 456      $ 192      $ 221      $ 1,190      $ 24      $ 58      $ 31       $ 11       $ 124   

Actual return on plan assets:

                      

Relating to assets still held at the reporting date

     15        98        32        21        166        (2     6        3         1         8   

Relating to assets sold during the period

     (36     (48     (34     (4     (122     1        3                1         5   

Purchases

     6        115        32               153        1        7        2                 10   

Sales

     (79     (91     (42     (51     (263     (5     (14     (9      (3      (31

Balance at December 31, 2013

   $ 227      $ 530      $ 180      $ 187      $ 1,124      $ 19      $ 60      $ 27       $ 10       $ 116   

Actual return on plan assets:

                      

Relating to assets still held at the reporting date

     40        70        12        4        126        4        7        2                 13   

Relating to assets sold during the period

     (18     (67     (26     (4     (115     (1     (7     (3              (11

Purchases

            135        10               145               13        1                 14   

Sales

     (40     (150     (32     (25     (247     (3     (15     (9      (1      (28

Balance at December 31, 2014

   $ 209      $ 518      $ 144      $ 162      $ 1,033      $ 19      $ 58      $ 18       $ 9       $ 104   

DOMINION GAS

                      

Balance at December 31, 2011

   $ 68      $ 99      $ 54      $ 64      $ 285      $ 3      $ 15      $ 10       $       $ 28   

Actual return on plan assets:

                      

Relating to assets still held at the reporting date

     6        12        4        4        26               (1     (1              (2

Relating to assets sold during the period

     (2     (9     (2            (13            2        1                 3   

Purchases

     7        17        3               27               1                        1   

Sales

     (7     (16     (16     (18     (57            (4     (2              (6

Balance at December 31, 2012

   $ 72      $ 103      $ 43      $ 50      $ 268      $ 3      $ 13      $ 8       $       $ 24   

Actual return on plan assets:

                      

Relating to assets still held at the reporting date

     4        24        7        5        40        (1     2        1                 2   

Relating to assets sold during the period

     (8     (10     (7     (1     (26                                     

Purchases

     1        25        7               33               1                        1   

Sales

     (17     (20     (9     (11     (57            (4     (2              (6

Balance at December 31, 2013

   $ 52      $ 122      $ 41      $ 43      $ 258      $ 2      $ 12      $ 7       $       $ 21   

Actual return on plan assets:

                      

Relating to assets still held at the reporting date

     9        17        4        1        31               2        1                 3   

Relating to assets sold during the period

     (4     (15     (6     (1     (26            (1     (1              (2

Purchases

            30        2               32               2                        2   

Sales

     (9     (33     (7     (5     (54            (3     (3              (6

Balance at December 31, 2014

   $ 48      $ 121      $ 34      $ 38      $ 241      $ 2      $ 12      $ 4       $       $ 18   

 

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Investments in Common/Collective Trust Funds in Dominion’s pension and other postretirement plans, including those in which Dominion Gas participates, are stated at fair value as determined by the issuer of the Common/Collective Trust Funds based on the fair value of the underlying investments. The Common/Collective Trusts do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the Common/Collective Trust Funds have limited withdrawal or redemption rights during the term of the investment. Strategies of the Common/Collective Trust Funds are as follows:

Dominion and Dominion Gas

 

   

Wells Fargo Closed End Bond Trust-The Fund invests in stocks, bonds or a combination of both. Shares of the Fund are traded on a stock exchange and are subject to market risk like stocks, bonds and mutual funds. The Fund may invest in a less liquid portfolio of stocks and bonds because the fund does not need to sell securities to meet shareholder redemptions as mutual funds in order to keep a percentage of its portfolio in cash to pay back investors who withdraw shares.

   

JPMorgan Core Bond Trust-The Fund seeks to maximize total return by investing primarily in a diversified portfolio of intermediate- and long-term debt securities. The Fund invests primarily in investment-grade bonds; it generally maintains an average weighted maturity between four and 12 years. It may shorten its average weighted maturity if deemed appropriate for temporary defensive purposes.

   

SSgA Russell 2000 Value Index Common Trust-The Fund measures the performance of the small-cap value segment of the U.S. equity universe. The Russell 2000 Value Index is constructed to provide a comprehensive and unbiased barometer for the small-cap value segment. The Index is completely reconstituted annually to ensure larger stocks do not distort the performance and characteristics of the true small-cap opportunity set and that the represented companies continue to reflect value characteristics.

   

NT Common Short-Term Investment Fund-The Fund seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of approved money market instruments with short maturities. Liquidity is emphasized to provide for redemption of units at par on any business day. Principal preservation is a primary objective. Within quality, maturity, and sector diversification guidelines, investments are made in those securities with the most attractive yields.

Dominion

 

   

SSgA Daily MSCI Emerging Markets Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI Emerging Markets Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company).

   

SSgA Daily MSCI ACWI Ex-USA Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI ACWI Ex-USA Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company).

   

SSgA S&P 400 MidCap Index-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of its benchmark index (the Index) over the long term. The S&P MidCap 400 is comprised of approximately 400 U.S. mid-cap securities and accounts for approximately 7% coverage of the U.S. stock market capitalization. SSgA will typically attempt to invest in the equity securities comprising the Index, in approximately the same proportions as they are represented in the Index.

   

JPMorgan Chase Bank U.S. Active Core Plus Equity Fund-The Fund seeks to outperform the S&P 500 Index (the Benchmark), gross of fees, over a market cycle. The Fund invests primarily in a portfolio of long and short positions in equity securities of large and mid capitalization U.S. companies with characteristics similar to those of the Benchmark.

   

Mondrian International Small Cap Equity Fund-The Fund’s investment objective is long-term total return. The Fund primarily invests in equity securities of non-U.S. small capitalization companies that, in the investment manager’s opinion, are undervalued at the time of purchase based on fundamental value analysis employed by the investment manager.

   

NT Collective Russell 2000 Growth Index-The Fund seeks an investment return that approximates the overall performance of the common stocks included in the Russell 2000 Growth Index. The Fund primarily invests in common stocks of one or more companies that are deemed to be representative of the industry diversification of the entire Russell 2000 Growth Index.

   

NT Collective Short-Term Investment Fund-The Fund is composed of high-grade money market instruments with short-term maturities. The Fund’s objective is to provide an investment vehicle for cash reserves while offering a competitive rate of return. Liquidity is emphasized to provide for redemption of units on any business day. Principal preservation is also a prime objective. Admissions and withdrawals are made daily. Interest is accrued daily and distributed monthly.

Investments in Group Insurance Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate debt instruments, and state and municipal debt securities.

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

Net Periodic Benefit (Credit) Cost

Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in the Consolidated Statements of Income. The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans are as follows:

 

      Pension Benefits     Other Postretirement Benefits  
Year Ended December 31,    2014     2013     2012     2014     2013     2012  
(millions, except percentages)                                     

DOMINION

            

Service cost

   $ 114      $ 131      $ 116      $ 32      $ 43      $ 44   

Interest cost

     290        271        268        67        73        79   

Expected return on plan assets

     (499     (462     (430     (111     (92     (79

Amortization of prior service (credit) cost

     3        3        3        (28     (15     (13

Amortization of net actuarial loss

     111        165        132        2        7        6   

Settlements and curtailments(1)

     1        (2                   (15     (4

Special termination benefits

                                 1          

Net periodic benefit (credit) cost

   $ 20      $ 106      $ 89      $ (38   $ 2      $ 33   

Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:

            

Current year net actuarial (gain) loss

   $ 784      $ (968   $ 786      $ 183      $ (255   $ 139   

Prior service (credit) cost

            1               9        (215     1   

Settlements and curtailments(1)

     (1     (22                   (7     (2

Less amounts included in net periodic benefit cost:

            

Amortization of net actuarial loss

     (111     (165     (132     (2     (7     (6

Amortization of prior service credit (cost)

     (3     (3     (3     28        15        13   

Total recognized in other comprehensive income and regulatory assets and liabilities

   $ 669      $ (1,157   $ 651      $ 218      $ (469   $ 145   

Significant assumptions used to determine periodic cost:

            

Discount rate

     5.20%-5.30     4.40%-4.80     5.50     4.20%-5.10     4.40%-4.80     5.50

Expected long-term rate of return on plan assets

     8.75     8.50     8.50     8.50     7.75     7.75

Weighted average rate of increase for compensation

     4.21     4.21     4.21     4.22     4.22     4.22

Healthcare cost trend rate(2)

           7.00     7.00     7.00

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(2)

           5.00     4.60     4.60

Year that the rate reaches the ultimate trend rate(2)(3)

                             2018        2062        2061   

DOMINION GAS

            

Service cost

   $ 12      $ 13      $ 11      $ 6      $ 7      $ 7   

Interest cost

     28        27        28        13        12        14   

Expected return on plan assets

     (115     (106     (96     (23     (19     (16

Amortization of prior service (credit) cost

     1        1        1        (1     (3     (4

Amortization of net actuarial loss

     19        26        26               2        1   

Net periodic benefit (credit) cost

   $ (55   $ (39   $ (30   $ (5   $ (1   $ 2   

Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:

            

Current year net actuarial (gain) loss

   $ 43      $ (127   $ 35      $ 40      $ (40   $ 12   

Prior service cost

                          10                 

Less amounts included in net periodic benefit cost:

            

Amortization of net actuarial loss

     (19     (26     (26            (2     (1

Amortization of prior service credit (cost)

     (1     (1     (1     1        3        4   

Total recognized in other comprehensive income and regulatory assets and liabilities

   $ 23      $ (154   $ 8      $ 51      $ (39   $ 15   

Significant assumptions used to determine periodic cost:

            

Discount rate

     5.20     4.40%-4.80     5.50     4.20%-5.00     4.40%-4.70     5.50

Expected long-term rate of return on plan assets

     8.75     8.50     8.50     8.50     7.75     7.75

Weighted average rate of increase for compensation

     3.93     3.93     3.93     3.93     3.93     3.93

Healthcare cost trend rate(2)

           7.00     7.00     7.00

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(2)

           5.00     4.60     4.60

Year that the rate reaches the ultimate trend rate(2)(3)

                             2018        2062        2061   

 

(1) 2013 amounts relate primarily to the decommissioning of Kewaunee.
(2) Assumptions used to determine net periodic cost for the following year.
(3) The Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the ultimate trend rate much more quickly than previous models.

 

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The components of AOCI and regulatory assets and liabilities for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:

 

      Pension Benefits      Other
Postretirement
Benefits
 
At December 31,    2014      2013      2014     2013  
(millions)                           

DOMINION

          

Net actuarial (gain) loss

   $ 2,382       $ 1,709       $ 139      $ (40

Prior service (credit) cost

     7         10         (233     (271

Total(1)

   $ 2,389       $ 1,719       $ (94   $ (311

DOMINION GAS

          

Net actuarial loss

   $ 303       $ 279       $ 43      $ 3   

Prior service (credit) cost

     1         2         7        (4

Total(2)

   $ 304       $ 281       $ 50      $ (1

 

(1) As of December 31, 2014, of the $2.4 billion and $(94) million related to pension benefits and other postretirement benefits, $1.4 billion and $(81) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2013, of the $1.7 billion and $(311) million related to pension benefits and other postretirement benefits, $1.0 billion and $(156) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.
(2) As of December 31, 2014, of the $304 million related to pension benefits, $112 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $50 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2013, of the $281 million related to pension benefits, $104 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $(1) million related to other postretirement benefits is included entirely in regulatory assets and liabilities.

The following table provides the components of AOCI and regulatory assets and liabilities for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans as of December 31, 2014 that are expected to be amortized as components of net periodic benefit (credit) cost in 2015:

 

      Pension Benefits      Other Postretirement
Benefits
 
(millions)              

DOMINION

     

Net actuarial loss

   $ 160       $ 6   

Prior service (credit) cost

     2         (27

DOMINION GAS

     

Net actuarial loss

   $ 20       $ 2   

Prior service cost

     1           

The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion develops assumptions, which are then compared to the forecasts of an independent investment advisor (except for the expected long-term rates of return) to ensure reasonableness. An internal committee selects the final assumptions used for Dominion’s pension and other postretirement plans, including those in which Dominion Gas participates, including discount rates, expected long-term rates of return, healthcare cost trend rates and mortality rates.

Dominion determines the expected long-term rates of return on plan assets for its pension plans and other postretirement

benefit plans, including those in which Dominion Gas participates, by using a combination of:

   

Expected inflation and risk-free interest rate assumptions;

   

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

   

Expected future risk premiums, asset volatilities and correlations;

   

Forecasts of an independent investment advisor;

   

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

   

Investment allocation of 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, including those in which Dominion Gas participates.

Dominion develops its mortality assumption using plan-specific studies and projects mortality improvement using scales developed by the Society of Actuaries for all its plans, including those in which Dominion Gas participates.

Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion’s retiree healthcare plans, including those in which Dominion Gas participates. A one percentage point change in assumed healthcare cost trend rates would have had the following effects for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) other postretirement benefit plans:

 

      Other Postretirement Benefits  
      One percentage
point increase
     One percentage
point decrease
 
(millions)              

DOMINION

     

Effect on net periodic cost for 2015

   $ 26       $ (16

Effect on other postretirement benefit obligation at December 31, 2014

     186         (152

DOMINION GAS

     

Effect on net periodic cost for 2015

   $ 5       $ (4

Effect on other postretirement benefit obligation at December 31, 2014

     40         (30

Dominion Gas (Employees Not Represented by Collective Bargaining Units) and Virginia Power-Participation in Defined Benefit Plans

Virginia Power employees and Dominion Gas employees not represented by collective bargaining units are covered by the Dominion Pension Plan described above. As participating employers, Virginia Power and Dominion Gas are subject to Dominion’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. During 2014, Virginia Power and Dominion Gas made no contributions to the Dominion Pension Plan, and no contributions to this plan are currently expected in 2015. Virginia Power’s net periodic pension cost related to this plan was $75 million, $96 million and $72 million in 2014, 2013 and 2012, respectively. Dominion Gas’ net periodic pension credit related to this plan was $(37) million, $(27) million and $(25) million in 2014, 2013 and 2012, respectively. Net periodic pension (credit) cost is reflected in other operations

 

 

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and maintenance expense in their respective Consolidated Statements of Income. The funded status of various Dominion subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion subsidiaries. See Note 24 for Virginia Power and Dominion Gas amounts due to/from Dominion related to this plan.

Retiree healthcare and life insurance benefits, for Virginia Power employees and for Dominion Gas employees not represented by collective bargaining units, are covered by the Dominion Retiree Health and Welfare Plan described above. Virginia Power’s net periodic benefit (credit) cost related to this plan was $(18) million, $5 million and $13 million in 2014, 2013 and 2012, respectively. Dominion Gas’ net periodic benefit (credit) cost related to this plan was $(5) million, less than $1 million and $3 million for 2014, 2013 and 2012, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expenses in their respective Consolidated Statements of Income. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion subsidiaries. See Note 24 for Virginia Power and Dominion Gas amounts due to/from Dominion related to this plan.

Dominion holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power and Dominion Gas’ employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power and Dominion Gas will provide to Dominion for their shares of employee benefit plan contributions.

Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power and Dominion Gas fund other postretirement benefit costs through VEBAs. During 2014 and 2013, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2015. Dominion Gas’ contributions to VEBAs for employees not represented by collective bargaining units were $1 million and $2 million for 2014 and 2013, respectively.

Defined Contribution Plans

Dominion also sponsors defined contribution employee savings plans that cover substantially all employees. During 2014, 2013 and 2012, Dominion recognized $41 million, $40 million and $40 million, respectively, as employer matching contributions to these plans. Dominion Gas participates in these employee savings plans, both specific to Dominion Gas and that cover multiple Dominion subsidiaries. During 2014, 2013 and 2012, Dominion Gas recognized $7 million, $7 million and $6 million, respectively, as employer matching contributions to these plans. Virginia Power also participates in these employee savings plans. During 2014, 2013 and 2012, Virginia Power recognized $17 million, $16 million and $15 million, respectively, as employer matching contributions to these plans.

 

NOTE 22. COMMITMENTS AND CONTINGENCIES

As a result of issues generated in the ordinary course of business, the Companies are involved in legal proceedings before various courts and are periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial position, liquidity or results of operations of the Companies.

Environmental Matters

The Companies are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

AIR

The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements.

In December 2011, the EPA issued MATS for coal and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance will be required by April 16,

 

 

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2015, with certain limited exceptions. In June 2014, the VDEQ granted a one-year MATS compliance extension for two coal-fired units at Yorktown to defer planned retirements and allow for continued operation of the units to address reliability concerns while necessary electric transmission upgrades are being completed. During the fourth quarter of 2013, Virginia Power recorded charges totaling $26 million ($16 million after-tax) for certain exit activities associated with these coal units, including the cost of employee severance, vendor contract termination, and inventory not expected to be used or usable at other stations.

The EPA established CAIR with the intent to require significant reductions in SO2 and NOX emissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO2 and NOx emissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO2 and NOx emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NOx emissions caps, NOx emissions caps during the ozone season (May 1 through September 30) and annual SO2 emission caps with differing requirements for two groups of affected states.

Following numerous petitions by industry participants for review and a successful motion for stay, in October 2014, the U.S. Court of Appeals for the D.C. Circuit ordered that the EPA’s motion to lift the stay of CSAPR be granted. Further, the Court granted the EPA’s request to shift the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets (which would have gone into effect in 2012 and 2013) will apply in 2015 and 2016, and Phase 2 emissions budgets will apply in 2017 and beyond. CSAPR will replace CAIR beginning in January 2015. The cost to comply is not expected to be material to the Consolidated Financial Statements. Future outcomes of any additional litigation and/or any action to issue a revised rule could affect the assessment regarding cost of compliance.

In May 2012, the EPA issued final designations for the 75-ppb ozone air quality standard. A number of the Companies’ facilities are located in areas impacted by this standard. As part of the standard, states will be required to develop and implement plans to address sources emitting pollutants which contribute to the formation of ozone. In November 2014, the EPA issued a new proposal to revise the ozone standard and expects to finalize the rule in October 2015. The EPA is not expected to complete attainment designations for a new standard until 2017 and states will have until 2020 to develop plans to address the new standard. Until the states have developed implementation plans, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significant expenditures are required to implement additional controls, it could adversely affect the Companies’ results of operations and cash flows.

In August 2010, the EPA issued revised National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. The rule was amended in March 2011 and January 2013. The rule establishes emission standards for control of hazardous air pollutants for engines at smaller facilities, known

as area sources. As a result of these regulations, Dominion Gas installed emissions controls on several compressor engines. Dominion Gas has spent approximately $2 million to date and is evaluating further expenditures. Dominion Gas is unable to estimate the additional potential impacts on results of operations, financial condition and/or cash flows related to this matter.

In August 2012, the EPA issued the first NSPS impacting the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of volatile organic compound emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. Compliance with these rules is required for installations and wells constructed or reconstructed after August 23, 2011. The cost to comply with the NSPS will depend on the number of new wells and new equipment installations subject to the rule; therefore, Dominion Gas is unable to estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.

WATER

The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The Companies must comply with applicable aspects of the CWA programs at their operating facilities.

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two mgd, with a heightened entrainment analysis for those facilities over 125 mgd. Dominion and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. While the impacts of this rule could be material to Dominion’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.

In September 2010, Millstone’s NPDES permit was reissued under the CWA. The conditions of the permit require an evaluation of control technologies that could result in additional expenditures in the future. The report summarizing the results of

 

 

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the evaluation was submitted in August 2012 and is under review by the Connecticut Department of Energy and Environmental Protection. Dominion cannot currently predict the outcome of this review. In October 2010, the permit issuance was appealed to the state court by a private plaintiff. The permit is expected to remain in effect during the appeal. Dominion is currently unable to make an estimate of the potential financial statement impacts related to this matter.

SOLID AND HAZARDOUS WASTE

The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.

From time to time, Dominion, Virginia Power, or Dominion Gas may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion, Virginia Power, or Dominion Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. Except as noted below, the Companies do not believe this will have a material effect on results of operations, financial condition and/or cash flows.

In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. In November 2011, Virginia Power and a number of other parties notified the EPA that they are declining to undertake the work set forth in the UAO.

The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO. Virginia Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter.

Dominion has determined that it is associated with 17 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion Gas. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which the Companies are associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.

In December 2014, the EPA Administrator signed the final rule regulating the management of CCRs stored in impoundments (ash ponds) and landfills and designating those CCRs as nonhazardous wastes under Subtitle D of the RCRA. The final rule regulates CCR landfills, ash ponds that still receive and manage CCRs (existing ash ponds), and ash ponds that do not receive, but still store CCRs (inactive ash ponds). Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. Virginia Power is also evaluating other features at its facilities for potential applicability under the final CCR rule. It is likely that the final rule will cause Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time. After closure of these structures, Virginia Power will continue to perform required monitoring, corrective action, and post-closure care activities as necessary to comply with the final rule. While Virginia Power is still evaluating the cost of compliance, there could be a material impact to its financial position, results of operations or cash flows.

CLIMATE CHANGE LEGISLATION AND REGULATION

In October 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the D.C. Circuit Court’s June 2012 decision upholding the EPA’s regulation of GHG emissions from stationary sources under the CAA’s permitting programs. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the EPA’s ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. On July 24, 2014, the EPA issued a memorandum specifying that it will no longer apply or enforce federal regulations or EPA-approved PSD state implementation plan provisions that require new and modified stationary sources to obtain a PSD permit when GHGs are the only pollutant that would be emitted at levels that exceed the permitting thresholds. In addition, the EPA stated that it will continue to use the existing thresholds to apply to sources that are otherwise subject to PSD for conventional pollutants until it completes a new rulemaking either justifying and upholding those thresholds or setting new ones. Some states have issued interim guidance that follows

 

 

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the EPA guidance. Due to uncertainty regarding what additional actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the Court ruling under a new rulemaking, the Companies cannot predict the impact to their financial statements at this time.

In July 2011, the EPA signed a final rule deferring the need for PSD and Title V permitting for CO2 emissions for biomass projects. This rule temporarily deferred for a period of up to three years the consideration of CO2 emissions from biomass projects when determining whether a stationary source meets the PSD and Title V applicability thresholds, including those for the application of BACT. The deferral policy expired in July 2014. In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however, a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the CO2 deferral period. It is unclear how the court’s decision or the EPA’s final policy regarding the treatment of specific feedstock will affect biomass sources that were permitted during the deferral period; however, the expenditures to comply with any new requirements could be material to Dominion’s and Virginia Power’s financial statements.

Other Legal Matters

The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.

Appalachian Gateway

Following the completion of the Appalachian Gateway Project in 2012, DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DTI filed a complaint in U.S. District Court, Eastern District of Virginia for breach of contract, accounting and declaratory relief. The contractor filed a motion to dismiss, or in the alternative, a motion to transfer venue to Pennsylvania and/or West Virginia, where the pipelines were constructed. DTI filed an opposition to the contractor’s motion in August 2013. In November 2013, the court granted the contractor’s motion on the basis that DTI must first comply with the dispute resolution process. Pursuant to the ruling, DTI intends to mediate the matter. This case is pending. DTI has accrued a liability of approximately $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.

Ash Pond Closure Costs

In September 2014, Virginia Power received a notice from the SELC on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at the Possum Point Power Station. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point’s historical and active ash storage facilities. A similar notice from the SELC on behalf of Sierra Club was subsequently received related to Chesapeake. In December 2014, Virginia Power offered to close all of its coal ash ponds and

landfills at Possum Point, Chesapeake and Bremo to the SELC as settlement of the potential litigation. In January 2015, the SELC declined the offer as presented, however the issue is open to potential further negotiations. As a result of the settlement offer, Virginia Power recognized a charge of $121 million in other operations and maintenance expense in its Consolidated Statements of Income.

Cove Point

Dominion is constructing the Liquefaction Project at the Cove Point facility, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. In April 2013, Cove Point filed with FERC for permission to build liquefaction and other facilities related to the export of natural gas. In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project. In October 2014, several parties filed a motion with FERC to stay the order and requested rehearing. The order remains in effect pending consideration of the motion by FERC.

In April 2013, Cove Point filed an application with the Maryland Commission requesting authorization to construct a generating station in connection with the Liquefaction Project. In May 2014, the Maryland Commission granted the CPCN authorizing the construction of such generating station. The CPCN obligates Cove Point to make payments totaling approximately $48 million. These payments consist of $40 million to the Strategic Energy Investments Fund over a five-year period beginning in 2015 and $8 million to Maryland low income energy assistance programs over a twenty-year period expected to begin in 2018. In December 2014, upon receipt of applicable approvals to commence construction of the generating station, Dominion recorded the present value of the obligation as an increase to property, plant and equipment and a corresponding liability.

In June 2014, a party filed a notice of petition for judicial review of the CPCN with the Circuit Court for Baltimore City in Maryland. In September 2014, the party filed with the Maryland Commission a motion to stay the CPCN pending judicial review of the CPCN. In December 2014, the Circuit Court issued an order affirming the Maryland Commission’s grant of the CPCN and dismissing the appeal, and the motion for stay was denied by the Maryland Commission. In January 2015, the same party filed a Notice of Appeal of the Baltimore Circuit Court’s Order affirming the Maryland Commission’s grant of the CPCN with the Court of Special Appeals for the Circuit Court of Baltimore City. This appeal is pending.

Nuclear Matters

In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as INPO. Like other U.S. nuclear operators, Dominion has been gathering supporting data and participating in industry initiatives focused on the ability to respond to and mitigate the consequences of design-basis and beyond-design-basis events at its stations.

In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident

 

 

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and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3, with the Tier 1 recommendations consisting of actions which the staff determined should be started without unnecessary delay. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.

Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion require implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation. The orders require prompt implementation of the safety enhancements and completion of implementation within two refueling outages or by December 31, 2016, whichever comes first. Implementation of these enhancements is currently in progress. The information requests issued by the NRC request each reactor to reevaluate the seismic and flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. Dominion and Virginia Power do not currently expect that compliance with the NRC’s March 2012 orders and information requests will materially impact their financial position, results of operations or cash flows during the approximately four-year implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion and Virginia Power are currently unable to estimate the potential financial impacts related to compliance with Tier 2 and Tier 3 recommendations.

Nuclear Operations

NUCLEAR DECOMMISSIONING—MINIMUM FINANCIAL ASSURANCE

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. 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. The 2014 calculation for the NRC minimum financial assurance amount, aggregated for Dominion’s and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.9 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2014 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2014 U.S. Bureau of Labor Statistics indices. Dominion believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units.

Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover 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 a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion and Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. See Note 6 to the Consolidated Financial Statements for additional information on Kewaunee, and Note 9 for additional information on nuclear decommissioning trust investments.

NUCLEAR INSURANCE

The Price-Anderson Amendments Act of 1988 provides the public up to $13.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

The current levels of nuclear property insurance coverage for Dominion’s and Virginia Power’s nuclear units is as follows:

 

      Coverage  
(billions)       

Dominion

  

Millstone

   $ 1.70   

Kewaunee

     1.06   

Virginia Power(1)

  

Surry

   $ 1.70   

North Anna

     1.70   

 

(1) Surry and North Anna share a blanket property limit of $200 million.

Dominion’s and Virginia Power’s nuclear property insurance coverage for Millstone, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. Kewaunee meets the NRC minimum requirement of $1.06 billion. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $72 million and $42 million, respectively. Based on the severity of the

 

 

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incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

Millstone and Virginia Power also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, the Companies are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $20 million and $9 million, respectively.

ODEC, a part owner of North Anna, and Massachusetts Municipal and Green Mountain, part owners of Millstone’s Unit 3, are responsible to Dominion and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

SPENT NUCLEAR FUEL

Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by Dominion’s and Virginia Power’s contracts with the DOE. Dominion and Virginia Power have previously received damages award payments and settlement payments related to these contracts.

In 2012, Dominion and Virginia Power resolved additional claims for damages incurred at Millstone, Kewaunee, Surry and North Anna with the Authorized Representative of the Attorney General. Dominion and Virginia Power entered into settlement agreements that resolved claims for damages incurred through December 31, 2010, and also provided for periodic payments after that date for damages incurred through December 31, 2013.

By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone plants have been extended to provide for periodic payments for damages incurred through December 31, 2016. Possible extension of the Kewaunee settlement agreement is being evaluated.

In 2014, Virginia Power and Dominion received payments of $27 million for the resolution of claims incurred at North Anna and Surry for the period January 1, 2011 through December 31, 2012 and $17 million for the resolution of claims incurred at Millstone for the period of July 1, 2012 through June 30, 2013. In 2014, Dominion also received payments totaling $7 million for the resolution of claims incurred at Kewaunee for periods from January 1, 2011 through December 31, 2013. In 2013, Dominion received payment of $5 million for resolution of claims incurred at Millstone for the period January 1, 2011 through June 30, 2012.

Dominion and Virginia Power continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion’s receivables

for spent nuclear fuel-related costs totaled $69 million and $79 million at December 31, 2014 and 2013, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $41 million and $50 million at December 31, 2014 and 2013, respectively.

Pursuant to a November 2013 decision of the U.S Court of Appeals for the D.C. Circuit, in January 2014 the Secretary of the DOE sent a recommendation to the U.S. Congress to adjust to zero the current fee of $1 per MWh for electricity paid by civilian nuclear power generators for disposal of spent nuclear fuel. The processes specified in the Nuclear Waste Policy Act for adjustment of the fee have been completed, and as of May 2014, Dominion and Virginia Power are no longer required to pay the waste fee. In 2014, Dominion and Virginia Power recognized fees of $16 million and $10 million, respectively.

Dominion and Virginia Power will continue to manage their spent fuel until it is accepted by the DOE.

Long-Term Purchase Agreements

At December 31, 2014, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:

 

     2015     2016     2017     2018     2019     Thereafter     Total  
(millions)                                          

Purchased electric capacity(1)

  $ 313      $ 250      $ 158      $ 104      $ 65      $ 99      $ 989   

 

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2014, the present value of Virginia Power’s total commitment for capacity payments is $833 million. Capacity payments totaled $330 million, $345 million, and $337 million, and energy payments totaled $304 million, $236 million, and $214 million for the years ended 2014, 2013 and 2012, respectively.

Lease Commitments

The Companies’ lease various facilities, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2014 are as follows:

 

      2015      2016      2017      2018      2019      Thereafter      Total  
(millions)                                                 

Dominion

   $ 63       $ 57       $ 49       $ 43       $ 36       $ 79       $ 327   

Virginia Power

   $ 30       $ 26       $ 21       $ 18       $ 12       $ 26       $ 133   

Dominion Gas

   $ 28       $ 25       $ 23       $ 21       $ 19       $ 25       $ 141   

Rental expense for Dominion totaled $92 million, $101 million, and $112 million for 2014, 2013 and 2012, respectively. Rental expense for Virginia Power totaled $43 million, $42 million, and $48 million for 2014, 2013, and 2012, respectively. Rental expense for Dominion Gas totaled $35 million in 2014 and $15 million in each 2013 and 2012. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.

 

 

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Guarantees, Surety Bonds and Letters of Credit

DOMINION

At December 31, 2014, Dominion had issued $74 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2014, Dominion’s exposure under these guarantees was $49 million, primarily related to certain reserve requirements associated with non-recourse financing.

Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.

At December 31, 2014, Dominion had issued the following subsidiary guarantees:

 

      Stated Limit      Value(1)  
(millions)              

Subsidiary debt(2)

   $ 27       $ 27   

Commodity transactions(3)

     3,151         919   

Nuclear obligations(4)

     215         76   

Cove Point(5)

     1,910           

Solar(6)

     531         396   

Other(7)

     532         35   

Total

   $ 6,366       $ 1,453   

 

(1) Represents the estimated portion of the guarantee’s stated limit that is utilized as of December 31, 2014 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount.
(2) Guarantee of debt of a DEI subsidiary. In the event of default by the subsidiary, Dominion would be obligated to repay such amounts.
(3) Guarantees related to commodity commitments of certain subsidiaries, including subsidiaries of Virginia Power, Dominion Gas and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion would be obligated to satisfy such obligation. Dominion and its subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits.
(4) Guarantees related to certain DEI subsidiaries’ potential retrospective premiums that could be assessed if there is a nuclear incident under Dominion’s nuclear insurance programs and guarantees for a DEI subsidiary’s and Virginia Power’s commitment to buy nuclear fuel. Excludes Dominion’s agreement to provide up to $150 million and $60 million to two DEI subsidiaries to pay the operating expenses of Millstone (in the event of a prolonged outage) and Kewaunee, respectively, as part of satisfying certain NRC requirements concerned with ensuring adequate funding for the operations of nuclear power stations. The agreement for Kewaunee also provides for funds through the completion of decommissioning.
(5) Guarantees related to Cove Point, in support of terminal services, transportation and construction. Two of the guarantees have no stated limit, one guarantee has a $150 million limit, and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million.
(6) Includes guarantees to facilitate the development of solar projects including guarantees to support the issuance of full notice to proceed under EPC agreements. Includes certain guarantees that do not have stated limits. Also includes guarantees entered into by DEI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.
(7) Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $72 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits.

Additionally, at December 31, 2014, Dominion had purchased $133 million of surety bonds, including $64 million at Virginia Power and $30 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $48 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

As of December 31, 2014, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. The related debt matures in 2031. In the event of default by a conduit, Virginia Power would be obligated to repay such amounts, which are limited to the principal and interest then outstanding.

Indemnifications

As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2014, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.

 

 

NOTE 23. CREDIT RISK

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

 

 

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The Companies maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 2014 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

GENERAL

DOMINION

As a diversified energy company, Dominion transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.

Dominion’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of any collateral. At December 31, 2014, Dominion’s credit exposure totaled $228 million. Of this amount, investment grade counterparties, including those internally rated, represented 86%, and no single counterparty, whether investment grade or non-investment grade, exceeded $23 million of exposure.

VIRGINIA POWER

Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2014, Virginia Power’s exposure to potential concentrations of credit risk was not considered material.

DOMINION GAS

Dominion Gas transacts mainly with major companies in the energy industry and with residential and commercial energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion Gas does not believe that this geographic concentration contributes to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Gas is not exposed to a significant concentration of credit risk for receivables arising from gas utility operations.

In 2014, DTI provided service to 260 customers with approximately 94% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 41% of the total storage and transportation revenue and the thirty largest provided approximately 74% of the total storage and transportation revenue of approximately $718 million. Approximately 99% of the transmission capacity under contract on DTI’s pipeline is subscribed with long-term contracts (three years or greater). The remaining 1% is contracted on a year-to-year basis. Less than 1% of firm transportation capacity is currently unsubscribed. All storage services are subscribed under long-term contracts.

East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates established by the Ohio Commission. Approximately 98% of East Ohio revenues are derived from its regulated gas distribution services. While individual customers of East Ohio have had increased amounts of bad debt in recent years, management believes that this concentration and bad debt risk is mitigated by the regulatory framework established by the Ohio Commission. See Note 13 for further information about Ohio’s PIPP and UEX Riders that mitigate East Ohio’s overall credit risk.

CREDIT-RELATED CONTINGENT PROVISIONS

The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 2014 and 2013, Dominion would have been required to post an additional $20 million and $146 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion had posted $1 million in collateral at December 31, 2014 and $76 million in collateral at December 31, 2013, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

December 31, 2014 and 2013 was $49 million and $169 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and Dominion Gas were not material as of December 31, 2014 and 2013. See Note 7 for further information about derivative instruments.

 

 

NOTE 24. RELATED-PARTY TRANSACTIONS

Virginia Power and Dominion Gas engage in related party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s and Dominion Gas’ receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power and Dominion Gas are included in Dominion’s consolidated federal income tax return. A discussion of significant related party transactions follows.

VIRGINIA POWER

Transactions with Affiliates

Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 19 for more information. As of December 31, 2014 and 2013, Virginia Power’s derivative assets and liabilities with affiliates were not material.

Virginia Power participates in certain Dominion benefit plans as described in Note 21. At December 31, 2014 and 2013, Virginia Power’s amounts due to Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets, were $219 million and $144 million, respectively. At December 31, 2014, Virginia Power’s amounts due from Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred charges and other assets in the Consolidated Balance Sheets were $37 million and at December 31, 2013, amounts due to Dominion and reflected in noncurrent pension and other postretirement benefit liabilities were $3 million.

DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage.

Presented below are significant transactions with DRS and other affiliates:

 

Year Ended December 31,    2014      2013      2012  
(millions)                     

Commodity purchases from affiliates

   $ 543       $ 417       $ 368   

Services provided by affiliates(1)

     432         415         399   

Services provided to affiliates

     22         21         19   

 

(1) Includes capitalized expenditures.

Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were $427 million and $97 million in short-term demand note borrowings from Dominion as of December 31, 2014 and 2013, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion money pool for its nonregulated subsidiaries as of December 31, 2014 and 2013. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the years ended December 31, 2014, 2013 and 2012.

There were no issuances of Virginia Power’s common stock to Dominion in 2014, 2013 or 2012.

DOMINION GAS

Transactions with Affiliates

Dominion Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Gas provides transportation and storage services to affiliates. Dominion Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of December 31, 2014 and 2013, all of Dominion Gas’ commodity derivatives were with affiliates. See Notes 7 and 19 for more information. See Note 9 for information regarding sales of assets to an affiliate.

Dominion Gas participates in certain Dominion benefit plans as described in Note 21. At December 31, 2014 and 2013, Dominion Gas’ amounts due from Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets, were $614 million and $577 million, respectively. At December 31, 2014 and 2013, Dominion Gas’ liabilities to Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred credits and other liabilities in the Consolidated Balance Sheets were $7 million and $14 million, respectively.

 

Year Ended December 31,    2014      2013      2012  
(millions)                     

Purchases of natural gas and transportation and storage services from affiliates

   $ 34       $ 31       $ 14   

Sales of natural gas and transportation and storage services to affiliates

     84         109         64   

DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Gas. Dominion Gas provides certain services to affiliates, including technical services. The costs of these services follow:

 

Year Ended December 31,    2014      2013      2012  
(millions)                     

Services provided by affiliates(1)

   $ 106       $ 116       $ 107   

Services provided to affiliates

     17         4         3   

 

(1) Includes capitalized expenditures.
 

 

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The following table presents affiliated and related party activity reflected in Dominion Gas’ Consolidated Balance Sheets:

 

At December 31,    2014      2013  
(millions)              

Customer receivables from related parties(1)

   $ 22       $ 3   

Imbalances receivable from affiliates(2)

     3         6   

Imbalances payable to affiliates(3)

             1   

Affiliated notes receivable(4)

     9         5   

 

(1) Includes $17 million due from Atlantic Coast Pipeline, an affiliated VIE.
(2) Amounts are presented in other current assets in Dominion Gas’ Consolidated Balance Sheets.
(3) Amounts are presented in other current liabilities in Dominion Gas’ Consolidated Balance Sheets.
(4) Amounts are presented in other deferred charges and other assets in Dominion Gas’ Consolidated Balance Sheets.

Dominion Gas’ borrowings under the IRCA with Dominion totaled $384 million and $1.3 billion as of December 31, 2014 and 2013, respectively. Interest charges related to Dominion Gas’ total borrowings from Dominion were $4 million, $35 million and $61 million for the years ended December 31, 2014, 2013 and 2012, respectively.

 

 

NOTE 25. OPERATING SEGMENTS

The Companies are organized primarily on the basis of products and services sold in the U.S. 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(1)

  X     X
 

Gas distribution and storage

  X     X
 

Gas gathering and processing

  X     X
   

LNG import and storage

  X        

 

(1) Includes remaining producer services activities.

In addition to the operating segments above, the Companies also report a Corporate and Other segment.

DOMINION

The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued or sold. 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.

In January 2014, Dominion announced it would exit the electric retail energy marketing business. Dominion completed the sale in March 2014. As a result, the earnings impact from the electric retail energy marketing business has been included in the Corporate and Other Segment of Dominion for 2014 first quarter results of operations.

In the second quarter of 2013, Dominion commenced a restructuring of its producer services business, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates. The restructuring, which was completed in the first quarter of 2014, resulted in the termination of natural gas trading and certain energy marketing activities. As a result, the earnings impact from natural gas trading and certain energy marketing activities has been included in the Corporate and Other Segment of Dominion for 2014.

In 2014, Dominion reported after-tax net expense of $970 million in the Corporate and Other segment, with $544 million of these net expenses attributable to specific items related to its operating segments.

The net expenses for specific items in 2014 primarily related to the impact of the following items:

Ÿ  

$374 million ($248 million after-tax) 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, attributable to Dominion Generation;

Ÿ  

A $319 million ($193 million after-tax) net loss related to the producer services business discussed above, attributable to Dominion Energy; and

Ÿ  

A $121 million ($74 million after-tax) charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities, attributable to Dominion Generation.

In 2013, Dominion reported after-tax net expense of $452 million in the Corporate and Other segment, with $184 million of these net expenses attributable to specific items related to its operating segments.

The net expenses for specific items in 2013 primarily related to the impact of the following items:

Ÿ  

A $135 million ($92 million after-tax) net loss from discontinued operations of Brayton Point and Kincaid, including debt extinguishment of $64 million ($38 million after-tax) related to the sale, impairment charges of $48 million ($28 million after-tax), a $17 million ($18 million after-tax) loss on the sale which includes a $16 million write-off of goodwill, and a $6 million ($8 million after-tax) loss from operations, attributable to Dominion Generation; and

Ÿ  

A $182 million ($109 million after-tax) net loss, including a $55 million ($33 million after-tax) impairment charge related to certain natural gas infrastructure assets and a $127 million ($76 million after-tax) loss related to the producer services business discussed above, attributable to Dominion Energy; partially offset by

Ÿ  

An $81 million ($49 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.

 

 

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In 2012, Dominion reported after-tax net expense of $1.7 billion in the Corporate and Other segment, with $1.5 billion of these net expenses attributable to specific items related to its operating segments.

The net expenses for specific items in 2012 primarily related to the impact of the following items:

Ÿ  

A $1.7 billion ($1.1 billion after-tax) net loss from discontinued operations, including impairment charges, of Brayton Point and Kincaid, which were sold in 2013, attributable to Dominion Generation;

Ÿ  

A $467 million ($303 million after-tax) net loss, including impairment charges, primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013, attributable to Dominion Generation;

Ÿ  

An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP; and

Ÿ  

A $49 million ($22 million after-tax) loss from discontinued operations of State Line and Salem Harbor which were sold in 2012, attributable to Dominion Generation.

 

 

The following table presents segment information pertaining to Dominion’s operations:

 

Year Ended December 31,    DVP     

Dominion

Generation

   

Dominion

Energy

    

Corporate and

Other

   

Adjustments &

Eliminations

   

Consolidated

Total

 
(millions)                                       

2014

              

Total revenue from external customers

   $ 1,918       $ 7,665      $ 1,718       $ (12   $ 1,147      $ 12,436   

Intersegment revenue

     18         70        1,174         572        (1,834       

Total operating revenue

     1,936         7,735        2,892         560        (687     12,436   

Depreciation, depletion and amortization

     462         516        241         73               1,292   

Equity in earnings of equity method investees

             (18     54         10               46   

Interest income

             67        14         20        (33     68   

Interest and related charges

     205         240        11         770        (33     1,193   

Income taxes

     317         392        436         (693            452   

Net income (loss) attributable to Dominion

     502         1,101        677         (970            1,310   

Investment in equity method investees

             262        796         23               1,081   

Capital expenditures

     1,652         2,466        1,329         104               5,551   

Total assets (billions)

     13.0         24.2        12.7         8.7        (4.3     54.3   

2013

              

Total revenue from external customers

   $ 1,825       $ 8,445      $ 1,783       $ 3      $ 1,064      $ 13,120   

Intersegment revenue

     9         68        1,063         609        (1,749       

Total operating revenue

     1,834         8,513        2,846         612        (685     13,120   

Depreciation, depletion and amortization

     427         518        228         35               1,208   

Equity in earnings of equity method investees

             (14     21         7               14   

Interest income

             66        12         42        (66     54   

Interest and related charges

     175         220        26         522        (66     877   

Income taxes

     287         483        409         (287            892   

Loss from discontinued operations, net of tax

                            (92            (92

Net income (loss) attributable to Dominion

     475         1,031        643         (452            1,697   

Investment in equity method investees

             280        615         21               916   

Capital expenditures

     1,361         1,605        1,043         95               4,104   

Total assets (billions)

     11.9         22.0        12.1         8.5        (4.4     50.1   

2012

              

Total revenue from external customers

   $ 1,846       $ 8,170      $ 1,813       $ 155      $ 851      $ 12,835   

Intersegment revenue

     9         104        930         608        (1,651       

Total operating revenue

     1,855         8,274        2,743         763        (800     12,835   

Depreciation, depletion and amortization

     392         483        216         36               1,127   

Equity in earnings of equity method investees

             3        23         (1            25   

Interest income

     1         65        30         71        (106     61   

Interest and related charges

     187         177        47         511        (106     816   

Income taxes

     278         576        352         (395            811   

Loss from discontinued operations, net of tax

                            (1,125            (1,125

Net income (loss) attributable to Dominion

     439         1,021        551         (1,709            302   

Capital expenditures

     1,158         1,615        1,350         22               4,145   

 

 

Intersegment sales and transfers for Dominion are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation.

 

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VIRGINIA POWER

The majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s DVP and Dominion Generation segments.

The Corporate and Other Segment of Virginia Power 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.

In 2014, Virginia Power reported after-tax net expenses of $342 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2014 primarily related to the impact of the following:

Ÿ  

$374 million ($248 million after-tax) 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, attributable to Dominion Generation; and

Ÿ  

A $121 million ($74 million after-tax) charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities, attributable to Dominion Generation.

In 2013, Virginia Power reported after-tax net expenses of $47 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2013 primarily related to the impact of the following:

Ÿ  

A $40 million ($28 million after-tax) charge in connection with the 2013 Biennial Review Order, attributable to Dominion Generation.

In 2012, Virginia Power reported after-tax net expenses of $51 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2012 primarily related to the impact of the following:

Ÿ  

An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP.

 

 

The following table presents segment information pertaining to Virginia Power’s operations:

 

Year Ended December 31,    DVP     

Dominion

Generation

    

Corporate and

Other

   

Adjustments &

Eliminations

   

Consolidated

Total

 
(millions)                                 

2014

            

Operating revenue

   $ 1,928       $ 5,651       $      $      $ 7,579   

Depreciation and amortization

     462         416         37               915   

Interest income

             8                       8   

Interest and related charges

     205         203         3               411   

Income taxes

     317         416         (185            548   

Net income (loss)

     509         691         (342            858   

Capital expenditures

     1,651         1,456                       3,107   

Total assets (billions)

     13.2         16.4                (0.1     29.5   

2013

            

Operating revenue

   $ 1,826       $ 5,475       $ (6   $      $ 7,295   

Depreciation and amortization

     427         425         1               853   

Interest income

             6                       6   

Interest and related charges

     175         192         2               369   

Income taxes

     286         399         (26            659   

Net income (loss)

     483         702         (47            1,138   

Capital expenditures

     1,360         1,173                       2,533   

Total assets (billions)

     12.0         15.1                (0.1     27.0   

2012

            

Operating revenue

   $ 1,847       $ 5,379       $      $      $ 7,226   

Depreciation and amortization

     392         390                       782   

Interest income

     1         7                       8   

Interest and related charges

     186         199                       385   

Income taxes

     277         403         (27            653   

Net income (loss)

     448         653         (51            1,050   

Capital expenditures

     1,142         1,146                       2,288   

 

DOMINION GAS

The Corporate and Other Segment of Dominion Gas primarily includes specific items attributable to Dominion Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance and the effect of certain items recorded at Dominion Gas as a result of Dominion’s basis in the net assets contributed.

In 2014, Dominion Gas reported after-tax net expenses of $9 million in its Corporate and Other segment, with none of these net expenses attributable to specific items related to its operating segment.

In 2013, Dominion Gas reported after-tax net expenses of $49 million in the Corporate and Other segment, with $41 million of these net expenses attributable to specific items related to its operating segment.

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

The net expenses for specific items in 2013 primarily related to the impact of the following:

Ÿ  

$55 million ($33 million after-tax) of impairment charges related to certain natural gas infrastructure assets; and

Ÿ  

A $14 million ($8 million after-tax) charge primarily reflecting severance pay and other benefits related to workforce reductions.

 

In 2012, Dominion Gas reported after-tax net expenses of $10 million in its Corporate and Other segment, with none of these net expenses attributable to specific items related to its operating segment.

 

 

The following table presents segment information pertaining to Dominion Gas’ operations:

 

Year Ended December 31,    Dominion
Energy
    

Corporate and

Other

   

Consolidated

Total

 
(millions)                    

2014

       

Operating revenue

   $ 1,898       $      $ 1,898   

Depreciation and amortization

     197                197   

Equity in earnings of equity method investees

     21                21   

Interest income

     1                1   

Interest and related charges

     27                27   

Income taxes

     340         (6     334   

Net income (loss)

     521         (9     512   

Investment in equity method investees

     107                107   

Capital expenditures

     719                719   

Total assets (billions)

     9.2         0.6        9.8   

2013

       

Operating revenue

   $ 1,937       $      $ 1,937   

Depreciation and amortization

     188                188   

Equity in earnings of equity method investees

     22                22   

Interest income

     2                2   

Interest and related charges

     28                28   

Income taxes

     333         (32     301   

Net income (loss)

     510         (49     461   

Investment in equity method investees

     105                105   

Capital expenditures

     650                650   

Total assets (billions)

     8.5         0.6        9.1   

2012

       

Operating revenue

   $ 1,677       $      $ 1,677   

Depreciation and amortization

     176                176   

Equity in earnings of equity method investees

     23                23   

Interest income

     2                2   

Interest and related charges

     40                40   

Income taxes

     293         (5     288   

Net income (loss)

     469         (10     459   

Capital expenditures

     928                928   

 

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NOTE 26. QUARTERLY FINANCIAL AND COMMON STOCK DATA (UNAUDITED)

A summary of the Companies’ quarterly results of operations for the years ended December 31, 2014 and 2013 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

DOMINION

 

    

First

Quarter

   

Second

Quarter

   

Third

Quarter

   

Fourth

Quarter

    Year  
(millions, except per
share amounts)
                             
2014                              

Operating revenue

  $ 3,630      $ 2,813      $ 3,050      $ 2,943      $ 12,436   

Income from operations

    768        394        921        638        2,721   

Net income including noncontrolling interests

    385        161        531        249        1,326   

Income from continuing operations(1)

    379        159        529        243        1,310   

Net income attributable to Dominion

    379        159        529        243        1,310   

Basic EPS:

         

Income from continuing operations(1)

    0.65        0.27        0.91        0.42        2.25   

Net income attributable to Dominion

    0.65        0.27        0.91        0.42        2.25   

Diluted EPS:

         

Income from continuing operations(1)

    0.65        0.27        0.90        0.42        2.24   

Net income attributable to Dominion

    0.65        0.27        0.90        0.42        2.24   

Dividends declared per share

    0.60        0.60        0.60        0.60        2.40   

Common stock prices (intraday high-low)

  $

 

72.22 -

63.14

  

  

  $

 

73.75 -

67.06

  

  

  $
 
71.62 -
64.71
  
  
  $

 

80.89 -

65.53

  

  

  $

 

80.89 -

63.14

  

  

    

First

Quarter

   

Second

Quarter

   

Third

Quarter

   

Fourth

Quarter

    Year  
(millions, except per
share amounts)
                             

2013

         

Operating revenue

  $ 3,523      $ 2,980      $ 3,432      $ 3,185      $ 13,120   

Income from operations

    930        548        1,034        804        3,316   

Net income including noncontrolling interests

    502        208        575        435        1,720   

Income from continuing operations(1)

    494        272        592        431        1,789   

Income (loss) from discontinued operations(1)

    1        (70     (23            (92

Net income attributable to Dominion

    495        202        569        431        1,697   

Basic EPS:

         

Income from continuing operations(1)

    0.86        0.47        1.02        0.74        3.09   

Income (loss) from discontinued operations(1)

           (0.12     (0.04            (0.16

Net income attributable to Dominion

    0.86        0.35        0.98        0.74        2.93   

Diluted EPS:

         

Income from continuing operations(1)

    0.86        0.47        1.02        0.74        3.09   

Income (loss) from discontinued operations(1)

           (0.12     (0.04            (0.16

Net income attributable to Dominion

    0.86        0.35        0.98        0.74        2.93   

Dividends declared per share

    0.5625        0.5625        0.5625        0.5625        2.25   

Common stock prices (intraday high-low)

  $

 

58.25 -

51.92

  

  

  $

 

61.85 -

53.79

  

  

  $
 
64.04 -
55.51
  
  
  $

 

67.97 -

61.36

  

  

  $

 

67.97 -

51.92

  

  

 

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

Dominion’s 2014 results include the impact of the following significant items:

Ÿ  

Fourth quarter results include $172 million in after-tax charges associated with the Liability Management Exercise in 2014 and $74 million in after-tax costs related to Virginia Power’s settlement offer to incur future ash pond closure costs at certain utility generation facilities.

Ÿ  

Second quarter results include $191 million in 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.

Ÿ  

First quarter results include a $193 million after-tax reduction in revenues associated with the repositioning of Dominion’s producer services business which was completed in the first quarter of 2014.

 

 

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Combined Notes to Consolidated Financial Statements, Continued

 

 

 

Dominion’s 2013 results include the impact of the following significant items:

Ÿ  

Second quarter results include a $70 million after-tax net loss from discontinued operations of Brayton Point and Kincaid; and a $57 million after-tax net loss, including a $33 million after-tax impairment charge related to certain natural gas infrastructure assets and a $24 million after-tax loss related to the producer services business.

VIRGINIA POWER

Virginia Power’s quarterly results of operations were as follows:

 

     

First

Quarter

    

Second

Quarter

    

Third

Quarter

    

Fourth

Quarter

     Year  
(millions)                                   

2014

              

Operating revenue

   $ 1,983       $ 1,729       $ 2,053       $ 1,814       $ 7,579   

Income from operations

     613         205         594         312         1,724   

Net income

     324         69         314         151         858   

Balance available for common stock

     318         67         312         148         845   

2013

              

Operating revenue

   $ 1,781       $ 1,710       $ 2,059       $ 1,745       $ 7,295   

Income from operations

     530         463         679         408         2,080   

Net income

     287         265         387         199         1,138   

Balance available for common stock

     283         261         383         194         1,121   

Virginia Power’s 2014 results include the impact of the following significant items:

Ÿ  

Fourth quarter results include $74 million in after-tax costs related to Virginia Power’s settlement offer to incur future ash pond closure costs at certain utility generation facilities.

Ÿ  

Second quarter results include a $191 million after-tax charge 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.

Virginia Power’s 2013 results include the impact of the following significant item:

Ÿ  

Fourth quarter results include a $28 million after-tax charge resulting from impacts of the 2013 Biennial Review Order.

DOMINION GAS

Dominion Gas’ quarterly results of operations were as follows:

 

     

First

Quarter

    

Second

Quarter

    

Third

Quarter

    

Fourth

Quarter

     Year  
(millions)                                   

2014

              

Operating revenue

   $ 569       $ 428       $ 391       $ 510       $ 1,898   

Income from operations

     265         154         177         255         851   
Net income    164      93      107      148      512  

2013

              

Operating revenue

   $ 586       $ 430       $ 388       $ 533       $ 1,937   

Income from operations

     224         88         217         233         762   

Net income

     138         53         130         140         461   

Dominion Gas’ 2014 results include the impact of the following significant item:

Ÿ  

Fourth quarter results include a $36 million after-tax gain from agreements to convey Marcellus Shale development rights underneath several natural gas storage fields.

Dominion Gas’ 2013 results include the impact of the following significant item:

Ÿ  

Second quarter results include a $33 million after-tax charge resulting from the impairment of certain natural gas infrastructure assets.

 

 

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Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

 

 

Item 9A. Controls and Procedures

DOMINION

Senior management, including Dominion’s CEO and CFO, evaluated the effectiveness of Dominion’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion’s CEO and CFO have concluded that Dominion’s disclosure controls and procedures are effective. There were no changes in Dominion’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion’s internal control over financial reporting.

 

 

MANAGEMENTS ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Dominion Resources, Inc. (Dominion) understands and accepts responsibility for Dominion’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion does throughout all aspects of its business.

Dominion maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Audit Committee of the Board of Directors of Dominion, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion’s 2014 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2014, Dominion makes the following assertions:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated Dominion’s internal control over financial reporting as of December 31, 2014. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion maintained effective internal control over financial reporting as of December 31, 2014.

Dominion’s independent registered public accounting firm is engaged to express an opinion on Dominion’s internal control over financial reporting, as stated in their report which is included herein.

February 27, 2015

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Dominion Resources, Inc.

Richmond, Virginia

We have audited the internal control over financial reporting of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Dominion’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes

in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Dominion maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of Dominion and our report dated February 27, 2015 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2015

 

 

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VIRGINIA POWER

Senior management, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes in Virginia Power’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Power’s internal control over financial reporting.

 

 

MANAGEMENTS ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Virginia Electric and Power Company (Virginia Power) understands and accepts responsibility for Virginia Power’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Virginia Power continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.

Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s 2014 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2014, Virginia Power makes the following assertions:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated Virginia Power’s internal control over financial reporting as of December 31, 2014. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2014.

This annual report does not include an attestation report of Virginia Power’s registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.

February 27, 2015

 

 

DOMINION GAS

DISCLOSURE CONTROLS AND PROCEDURES

An evaluation of the effectiveness of the design and operation of Dominion Gas’ disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended) was carried out under the supervision and with the participation of management, including the CEO and CFO of Dominion Gas. Based upon that evaluation, the CEO and CFO of Dominion Gas concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2014, the end of the period covered by this report.

INTERNAL CONTROL OVER FINANCIAL REPORTING

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules that generally require every company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. In addition, an independent registered public accounting firm must attest to a company’s internal control over financial reporting. This first Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of Dominion Gas’ independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. Management will be required to provide an assessment of the effectiveness of Dominion Gas’ internal control over financial reporting as of December 31, 2015. Management’s report will not be subject to attestation by Dominion Gas’ independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, Dominion Gas’ internal control over financial reporting during the quarter ended December 31, 2014.

 

 

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Item 9B. Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

DOMINION

The following information for Dominion is incorporated by reference from the Dominion 2015 Proxy Statement, which will be filed on or around March 23, 2015:

Ÿ  

Information regarding the directors required by this item is found under the heading Election of Directors.

Ÿ  

Information regarding compliance with Section 16 of the Securities Exchange Act of 1934, as amended, required by this item is found under the heading Section 16(a) Beneficial Ownership Reporting Compliance.

Ÿ  

Information regarding the Dominion Audit Committee Financial expert(s) required by this item is found under the headings Director Independence and Committees and Meeting Attendance.

Ÿ  

Information regarding the Dominion Audit Committee required by this item is found under the headings The Audit Committee Report and Committees and Meeting Attendance.

Ÿ  

Information regarding Dominion’s Code of Ethics required by this item is found under the heading Corporate Governance and Board Matters.

The information concerning the executive officers of Dominion required by this item is included in Part I of this Form 10-K under the caption Executive Officers of Dominion. Each executive officer of Dominion is elected annually.

 

Item 11. Executive Compensation

DOMINION

The following information about Dominion is contained in the 2015 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the headings Compensation Discussion and Analysis and Executive Compensation; the information regarding Compensation Committee interlocks contained under the heading Compensation Committee Interlocks and Insider Participation; the Compensation, Governance and Nominating Committee Report; and the information regarding director compensation contained under the heading Non-Employee Director Compensation.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

DOMINION

The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the headings Share Ownership-Director and Officer Share Ownership and Significant Shareholders in the 2015 Proxy Statement is incorporated by reference.

The information regarding equity securities of Dominion that are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation-Equity Compensation Plans in the 2015 Proxy Statement is incorporated by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

DOMINION

The information regarding related party transactions required by this item found under the heading Related Party Transactions, and information regarding director independence found under the heading Director Independence, in the 2015 Proxy Statement is incorporated by reference.

Item 14. Principal Accountant Fees and Services

DOMINION

The information concerning principal accountant fees and services contained under the heading Auditors-Fees and Pre-Approval Policy in the 2015 Proxy Statement is incorporated by reference.

 

 

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VIRGINIA POWER AND DOMINION GAS

The following table presents fees paid to Deloitte & Touche LLP for services related to Virginia Power and Dominion Gas for the fiscal years ended December 31, 2014 and 2013.

 

Type of Fees    2014      2013  
(millions)              

Virginia Power

     

Audit fees

   $ 1.96       $ 1.89   

Audit-related fees

             0.02   

Tax fees

               

All other fees

               

Total fees

   $ 1.96       $ 1.91   

Dominion Gas

     

Audit fees

   $ 0.52       $   

Audit-related fees

     0.14           

Tax fees

               

All other fees

               

Total fees

   $ 0.66       $   
    

 

 

    

 

 

 

Audit Fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power’s and Dominion Gas’ annual consolidated financial statements, the review of financial statements included in Virginia Power’s and Dominion Gas’ quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC.

Audit-Related Fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Virginia Power’s and Dominion Gas’ consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and attest services not required by statute or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.

Virginia Power’s and Dominion Gas’ Boards of Directors have adopted the Dominion Audit Committee pre-approval policy for their independent auditor’s services and fees and have delegated the execution of this policy to the Dominion Audit Committee. In accordance with this delegation, each year the Dominion Audit Committee pre-approves a schedule that details the services to be provided for the following year and an estimated charge for such services. At its January 2015 meeting, the Dominion Audit Committee approved Virginia Power’s and Dominion Gas’ schedules of services and fees for 2015. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Audit Committee or a member of the Dominion Audit Committee.

The audit fees for Dominion Gas presented above for the year ended December 31, 2014, were for professional services rendered during the period subsequent to Dominion Gas becoming an SEC registrant. Total audit fees and audit-related fees incurred prior to Dominion Gas becoming an SEC registrant were $680 thousand and $70 thousand, respectively, and were paid by Dominion.

 

 

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Part IV

Item 15. Exhibits and Financial Statement Schedules

 

 

 

(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.

1. Financial Statements

See Index on page 56.

2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.

3. Exhibits (incorporated by reference unless otherwise noted)

 

Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
2    Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1, Form 8-K filed March 15, 2010, File No. 1-8489).      X         
3.1.a    Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).      X         
3.1.b    Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255).         X      
3.1.c    Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
3.2.a    Dominion Resources, Inc. Amended and Restated Bylaws, effective May 3, 2013 (Exhibit 3.1, Form 8-K filed May 3, 2013, File No. 1-8489).      X         
3.2.b    Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).         X      
3.2.c    Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
4    Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.      X         X         X   
4.1.a    See Exhibit 3.1.a above.      X         
4.1.b    See Exhibit 3.1.b above.         X      
4.2    Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indenture (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); Ninety-Second Supplemental Indenture, dated as of July 1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255).      X         X      
4.3    Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of Tenth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Twelfth Supplemental Indenture, dated January 1, 2006 (Exhibit 4.2, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Thirteenth Supplemental Indenture, dated as of January 1, 2006 (Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Form of Seventeenth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-      X         X      

 

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Exhibit

Number

  

Description

   Dominion      Virginia
Power
   Dominion
Gas
   First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No. 1-2255).         
4.4    Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a Form of Second Supplemental Indenture, dated January 1, 2001 (Exhibit 4.6, Form 8-K filed January 12, 2001, File No. 1-8489).      X         
4.5    Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2026); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027).      X         
4.6    Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of Sixteenth Supplemental Indenture, dated December 1, 2002 (Exhibit 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Form of Twenty-First Supplemental Indenture, dated March 1, 2003 (Exhibits 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Fifth Supplemental Indenture, dated January 1, 2004 (Exhibit 4.2, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Form of Twenty-Ninth Supplemental Indenture, dated June 1, 2005 (Exhibit 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-Second Supplemental Indenture, dated November 1, 2006 (Exhibit 4.2, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 30, 2007, File No. 1-8489); Forms of Thirty-Fifth and Thirty-Sixth Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2 and 4.3, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011 (Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 15, 2011, File No. 1-8489); Forty-Fifth      X         

 

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Exhibit

Number

  

Description

   Dominion      Virginia
Power
   Dominion
Gas
   Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Eighth Supplemental Indenture, dated March 1, 2014 (Exhibit 4.3, Form 8-K, filed March 24, 2014, File No. 1-8489); Forty-Ninth Supplemental Indenture, dated November 1, 2014 (Exhibit 4.3, Form 8-K, filed November 25, 2014, File No. 1-8489); Fiftieth Supplemental Indenture, dated November 1, 2014 (Exhibit 4.4, Form 8-K, filed November 25, 2014, File No. 1-8489); Fifty-First Supplemental Indenture, dated November 1, 2014 (Exhibit 4.5, Form 8-K, filed November 25, 2014, File No. 1-8489).         
4.7    Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196).      X         
4.8    Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489); Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2014, File No. 1-8489).      X         
4.9    Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).      X         
4.10    Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).      X         
4.11    Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated July 18, 2014 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2014 filed July 30, 2014, File No. 1-8489).      X         
4.12    Series A Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.7, Form 8-K filed June 7, 2013, File No. 1-8489).      X         
4.13    Series B Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.8, Form 8-K filed June 7, 2013, File No. 1-8489).      X         

 

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Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
4.14    2014 Series A Purchase Contract and Pledge Agreement, dated as of July 1, 2014, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.5, Form 8-K filed July 1, 2014, File No. 1-8489).      X         
4.15    Indenture, dated as of October 1, 2013, between Dominion Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form S-4 filed April 4, 2014, File No. 333-195066); First Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.2, Form S-4 filed April 4, 2014, File No. 333-195066); Second Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.3, Form S-4 filed April 4, 2014, File No. 333-195066); Third Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.4, Form S-4 filed April 4, 2014, File No. 333-195066); Fourth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.2, Form 8-K filed December 8, 2014, File No. 333-195066); Fifth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.3, Form 8-K filed December 8, 2014, File No. 333-195066); Sixth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.4, Form 8-K filed December 8, 2014, File No. 333-195066).      X            X   
10.1    DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489).      X         
10.2    DRS Services Agreement, dated as of January 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255).         X      
10.3    Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489).      X         X      
10.4    $4,000,000,000 Five-Year Amended and Restated Revolving Credit Agreement, dated May 19, 2014, among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, The Royal Bank of Scotland plc, Bank of America, N.A., Barclays Bank PLC and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein (Exhibit 10.1, Form 8-K filed May 19, 2014, File No. 1-8489 and File No. 1-2255).      X         X         X   
10.5    $500,000,000 Five-Year Amended and Restated Revolving Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, Keybank National Association, as Administrative Agent, U.S. Bank National Association, as Syndication Agent, and other lenders named therein (Exhibit 10.1, Form 8-K filed June 2, 2014, File No. 1-8489 and File No. 1-2255).      X         X         X   
10.6    Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003, File No. 1-8489 and File No. 1-2255).      X         X      
10.7*    Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489), as amended September 26, 2014 (Exhibit 10.1, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).      X         X         X   
10.8*    Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489).      X         X         X   
10.9*    Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company dated January 24, 2013 (effective for certain officers elected subsequent to February 1, 2013) (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2013 filed February 27, 2014, File No. 1-8489 and File No. 1-2255).      X         X         X   

 

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Table of Contents

 

 

Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
10.10*    Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489), as amended September 26, 2014 (Exhibit 10.2, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).      X         X         X   
10.11*    Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489).      X         X         X   
10.12*    Dominion Resources, Inc. New Executive Supplemental Retirement Plan, as amended and restated effective July 1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013 filed August 6, 2013 File No. 1-8489), as amended September 26, 2014 (Exhibit 10.3, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).      X         X         X   
10.13*    Dominion Resources, Inc. New Retirement Benefit Restoration Plan, as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255), as amended September 26, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).      X         X         X   
10.14*    Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489).      X         
10.15*    Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).      X         
10.16*    Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489).      X         
10.17*    Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489).      X         
10.18*    Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated May 7, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended June 30, 2014 filed July 30, 2014, File No. 1-8489 and File No. 1-2250).      X         X         X   
10.19*    Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489).      X         X         X   
10.20*    Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).      X         X         X   
10.21*    Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489).      X         X         X   
10.22*    Supplemental Retirement Agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255).      X         X         X   

 

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Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
10.23*    Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255).      X         X         X   
10.24*    Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255).      X         X         X   
10.25*    Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489).      X         X         X   
10.26*    Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective December 20, 2011 (Exhibit 10.32, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255).      X         X         X   
10.27*    2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489).      X         X         X   
10.28*    Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489).      X         X         X   
10.29*    Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489).      X         X         X   
10.30*    2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489).      X         X         X   
10.31*    Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489).      X         X         X   
10.32*    Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012, File No. 1-8489).      X         X         X   
10.33*    2012 Performance Grant Plan under the 2012 Long-Term Incentive Program approved January 19, 2012 (Exhibit 10.1, Form 8-K filed January 20, 2012, File No. 1-8489).      X         X         X   
10.34*    Form of Restricted Stock Award Agreement under the 2012 Long-term Incentive Program approved January 19, 2012 (Exhibit 10.2, Form 8-K filed January 20, 2012, File No. 1-8489).      X         X         X   
10.35*    2013 Performance Grant Plan under 2013 Long-Term Incentive Program approved January 24, 2013 (Exhibit 10.1, Form 8-K filed January 25, 2013, File No. 1-8489).      X         X         X   
10.36*    Form of Restricted Stock Award Agreement under the 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.2, Form 8-K filed January 25, 2013, File No. 1-8489).      X         X         X   
10.37*    Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010 (Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489).      X         X         X   
10.38*    Retirement Agreement, dated as of June 20, 2013, between Dominion Resources, Inc. and Gary L. Sypolt (Exhibit 10.1, Form 8-K filed June 24, 2013, File No. 1-8489).      X         
10.39*    2014 Performance Grant Plan under 2014 Long-Term Incentive Program approved January 16, 2014 (Exhibit 10.40, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489).      X         X         X   
10.40*    Form of Restricted Stock Award Agreement under the 2014 Long-term Incentive Program approved January 16, 2014 (Exhibit 10.41, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489).      X         X         X   
10.41*    Form of Special Performance Grant for Thomas F. Farrell II and Mark F. McGettrick approved January 16, 2014 (Exhibit 10.42, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489).      X         X         X   

 

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Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
10.42*    2015 Performance Grant Plan under 2015 Long-Term Incentive Program approved January 22, 2015 (filed herewith).      X         X         X   
10.43*    Form of Restricted Stock Award Agreement under the 2015 Long-term Incentive Program approved January 22, 2015 (filed herewith).      X         X         X   
10.44*    Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).      X         
10.45*    Non-employee directors’ annual compensation for Dominion Resources, Inc. (filed herewith).      X         
10.46*    Dominion Resources, Inc. 2014 Incentive Compensation Plan, effective May 7, 2014 (Exhibit 10.1, Form 8-K filed May 7, 2014, File No. 1-8489).      X         X         X   
10.47    Registration Rights Agreement, dated as of October 22, 2013, by and among Dominion Gas Holdings, LLC and RBC Capital Markets, LLC, RBS Securities Inc. and Scotia Capital (USA) Inc., as the initial purchasers of the Notes (Exhibit 10.1, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
10.48    Inter-Company Credit Agreement, dated October 17, 2013, between Dominion Resources, Inc. and Dominion Gas Holdings, LLC (Exhibit 10.2, Form S-4 filed April 4, 2014, File No. 333-195066).      X            X   
10.49    DRS Services Agreement, dated September 12, 2013, between Dominion Gas Holdings, LLC and Dominion Resources Services, Inc. (Exhibit 10.3, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
10.50    DRS Services Agreement, dated January 1, 2003, between Dominion Transmission Inc. and Dominion Resources Services, Inc. (Exhibit 10.4, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
10.51    DRS Services Agreement, dated January 1, 2003, between The East Ohio Company and Dominion Resources Services, Inc. (Exhibit 10.5, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
10.52    DRS Services Agreement, dated January 1, 2003, between Dominion Iroquois, Inc. and Dominion Resources Services, Inc. (Exhibit 10.6, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
12.a    Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).      X         
12.b    Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).         X      
12.c    Ratio of earnings to fixed charges for Dominion Gas Holdings, LLC (filed herewith).            X   
21    Subsidiaries of Dominion Resources, Inc. (filed herewith).      X         
23    Consent of Deloitte & Touche LLP (filed herewith).      X         X         X   
31.a    Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).      X         
31.b    Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).      X         
31.c    Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).         X      
31.d    Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).         X      
31.e    Certification by Chief Executive Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).            X   
31.f    Certification by Chief Financial Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).            X   
32.a    Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).      X         

 

166        

 


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Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
32.b    Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).         X      
32.c    Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).            X   
101    The following financial statements from Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC Annual Report on Form 10-K for the year ended December 31, 2014, filed on February 27, 2015, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.      X         X         X   

 

* Indicates management contract or compensatory plan or arrangement

 

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Table of Contents

Signatures

 

 

 

DOMINION

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

DOMINION RESOURCES, INC.
By:  

/s/    Thomas F. Farrell II        

  (Thomas F. Farrell II, Chairman, President and Chief Executive Officer)

Date: February 27, 2015

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 27th day of February, 2015.

 

Signature    Title

/s/    Thomas F. Farrell II        

Thomas F. Farrell II

  

Chairman of the Board of Directors, President and Chief

Executive Officer

/s/    William P. Barr        

William P. Barr

   Director

/s/    Peter W. Brown        

Peter W. Brown

   Director

/s/    Helen E. Dragas        

Helen E. Dragas

   Director

/s/    James O. Ellis, Jr.        

James O. Ellis, Jr.

   Director

/s/    John W. Harris        

John W. Harris

   Director

/s/    Mark J. Kington        

Mark J. Kington

   Director

/s/    Pamela J. Royal        

Pamela J. Royal

   Director

/s/    Robert H. Spilman, Jr.        

Robert H. Spilman, Jr.

   Director

/s/    Michael E. Szymanczyk        

Michael E. Szymanczyk

   Director

/s/    David A. Wollard        

David A. Wollard

   Director

/s/    Mark F. McGettrick        

Mark F. McGettrick

   Executive Vice President and Chief Financial Officer

/s/    Michele L. Cardiff        

Michele L. Cardiff

   Vice President, Controller and Chief Accounting Officer

 

168        

 


Table of Contents

 

 

Virginia Power

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

VIRGINIA ELECTRIC AND POWER COMPANY
By:  

/S/    THOMAS F. FARRELL II        

 

(Thomas F. Farrell II, Chairman of the Board

of Directors and Chief Executive Officer)

Date: February 27, 2015

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 27th day of February, 2015.

 

Signature    Title

/s/    Thomas F. Farrell II        

Thomas F. Farrell II

   Chairman of the Board of Directors and Chief Executive Officer

/s/    Mark F. McGettrick        

Mark F. McGettrick

   Director, Executive Vice President and Chief Financial Officer

/s/    Mark O. Webb        

Mark O. Webb

   Director

/s/    Michele L. Cardiff        

Michele L. Cardiff

   Vice President, Controller and Chief Accounting Officer

 

        169

 


Table of Contents

 

 

Dominion Gas

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

DOMINION GAS HOLDINGS, LLC
By:   /S/    THOMAS F. FARRELL II        
 

(Thomas F. Farrell II, Chairman of the Board

of Directors and Chief Executive Officer)

Date: February 27, 2015

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 27th day of February, 2015.

 

Signature    Title

/s/    Thomas F. Farrell II        

Thomas F. Farrell II

   Chairman of the Board of Directors and Chief Executive Officer

/s/    Mark F. McGettrick        

Mark F. McGettrick

   Director, Executive Vice President and Chief Financial Officer

/s/    Mark O. Webb        

Mark O. Webb

   Director

/s/    Michele L. Cardiff        

Michele L. Cardiff

   Vice President, Controller and Chief Accounting Officer

 

170        

 


Table of Contents

Exhibit Index

 

 

 

Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
2    Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1, Form 8-K filed March 15, 2010, File No. 1-8489).      X         
3.1.a    Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).      X         
3.1.b    Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255).         X      
3.1.c    Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
3.2.a    Dominion Resources, Inc. Amended and Restated Bylaws, effective May 3, 2013 (Exhibit 3.1, Form 8-K filed May 3, 2013, File No. 1-8489).      X         
3.2.b    Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).         X      
3.2.c    Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
4    Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.      X         X         X   
4.1.a    See Exhibit 3.1.a above.      X         
4.1.b    See Exhibit 3.1.b above.         X      
4.2    Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indenture (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); Ninety-Second Supplemental Indenture, dated as of July 1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255).      X         X      
4.3    Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of Tenth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Twelfth Supplemental Indenture, dated January 1, 2006 (Exhibit 4.2, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Thirteenth Supplemental Indenture, dated as of January 1, 2006 (Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Form of Seventeenth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255); Twenty-      X         X      

 

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Exhibit

Number

  

Description

   Dominion      Virginia
Power
   Dominion
Gas
   Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No. 1-2255).         
4.4    Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a Form of Second Supplemental Indenture, dated January 1, 2001 (Exhibit 4.6, Form 8-K filed January 12, 2001, File No. 1-8489).      X         
4.5    Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2026); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027).      X         
4.6    Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of Sixteenth Supplemental Indenture, dated December 1, 2002 (Exhibit 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Form of Twenty-First Supplemental Indenture, dated March 1, 2003 (Exhibits 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Fifth Supplemental Indenture, dated January 1, 2004 (Exhibit 4.2, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Form of Twenty-Ninth Supplemental Indenture, dated June 1, 2005 (Exhibit 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-Second Supplemental Indenture, dated November 1, 2006 (Exhibit 4.2, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 30, 2007, File No. 1-8489); Forms of Thirty-Fifth and Thirty-Sixth Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2 and 4.3, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011 (Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 15, 2011, File No. 1-8489); Forty-Fifth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Eighth Supplemental Indenture, dated March 1, 2014 (Exhibit 4.3, Form 8-K, filed March 24, 2014, File No. 1-8489); Forty-Ninth Supplemental Indenture, dated November 1, 2014 (Exhibit 4.3, Form 8-K, filed November 25, 2014, File No. 1-8489); Fiftieth      X         

 

172        

 


Table of Contents

 

 

Exhibit

Number

  

Description

   Dominion      Virginia
Power
   Dominion
Gas
 
   Supplemental Indenture, dated November 1, 2014 (Exhibit 4.4, Form 8-K, filed November 25, 2014, File No. 1-8489); Fifty-First Supplemental Indenture, dated November 1, 2014 (Exhibit 4.5, Form 8-K, filed November 25, 2014, File No. 1-8489).         
4.7    Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196).      X         
4.8    Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489); Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2014, File No. 1-8489).      X         
4.9    Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).      X         
4.10    Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).      X         
4.11    Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated July 18, 2014 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2014 filed July 30, 2014, File No. 1-8489).      X         
4.12    Series A Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.7, Form 8-K filed June 7, 2013, File No. 1-8489).      X         
4.13    Series B Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.8, Form 8-K filed June 7, 2013, File No. 1-8489).      X         
4.14    2014 Series A Purchase Contract and Pledge Agreement, dated as of July 1, 2014, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.5, Form 8-K filed July 1, 2014, File No. 1-8489).      X         
4.15    Indenture, dated as of October 1, 2013, between Dominion Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form S-4 filed April 4, 2014, File No. 333-195066); First Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.2,      X            X   

 

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Table of Contents

 

 

Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
   Form S-4 filed April 4, 2014, File No. 333-195066); Second Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.3, Form S-4 filed April 4, 2014, File No. 333-195066); Third Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.4, Form S-4 filed April 4, 2014, File No. 333-195066); Fourth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.2, Form 8-K filed December 8, 2014, File No. 333-195066); Fifth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.3, Form 8-K filed December 8, 2014, File No. 333-195066); Sixth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.4, Form 8-K filed December 8, 2014, File No. 333-195066).         
10.1    DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489).      X         
10.2    DRS Services Agreement, dated as of January 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255).         X      
10.3    Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489).      X         X      
10.4    $4,000,000,000 Five-Year Amended and Restated Revolving Credit Agreement, dated May 19, 2014, among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, The Royal Bank of Scotland plc, Bank of America, N.A., Barclays Bank PLC and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein (Exhibit 10.1, Form 8-K filed May 19, 2014, File No. 1-8489 and File No. 1-2255).      X         X         X   
10.5    $500,000,000 Five-Year Amended and Restated Revolving Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, Keybank National Association, as Administrative Agent, U.S. Bank National Association, as Syndication Agent, and other lenders named therein (Exhibit 10.1, Form 8-K filed June 2, 2014, File No. 1-8489 and File No. 1-2255).      X         X         X   
10.6    Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003, File No. 1-8489 and File No. 1-2255).      X         X      
10.7*    Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489), as amended September 26, 2014 (Exhibit 10.1, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).      X         X         X   
10.8*    Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489).      X         X         X   
10.9*    Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company dated January 24, 2013 (effective for certain officers elected subsequent to February 1, 2013) (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2013 filed February 27, 2014, File No. 1-8489 and File No. 1-2255).      X         X         X   
10.10*    Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489), as amended September 26, 2014 (Exhibit 10.2, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).      X         X         X   
10.11*    Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489).      X         X         X   

 

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Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
10.12*    Dominion Resources, Inc. New Executive Supplemental Retirement Plan, as amended and restated effective July 1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013 filed August 6, 2013 File No. 1-8489), as amended September 26, 2014 (Exhibit 10.3, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).      X         X         X   
10.13*    Dominion Resources, Inc. New Retirement Benefit Restoration Plan, as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255), as amended September 26, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014).      X         X         X   
10.14*    Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489).      X         
10.15*    Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).      X         
10.16*    Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489).      X         
10.17*    Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489).      X         
10.18*    Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated May 7, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended June 30, 2014 filed July 30, 2014, File No. 1-8489 and File No. 1-2250).      X         X         X   
10.19*    Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489).      X         X         X   
10.20*    Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).      X         X         X   
10.21*    Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489).      X         X         X   
10.22*    Supplemental Retirement Agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255).      X         X         X   
10.23*    Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255).      X         X         X   
10.24*    Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008      X         X         X   

 

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Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
   (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255).         
10.25*    Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489).      X         X         X   
10.26*    Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective December 20, 2011 (Exhibit 10.32, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255).      X         X         X   
10.27*    2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489).      X         X         X   
10.28*    Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489).      X         X         X   
10.29*    Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489).      X         X         X   
10.30*    2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489).      X         X         X   
10.31*    Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489).      X         X         X   
10.32*    Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012, File No. 1-8489).      X         X         X   
10.33*    2012 Performance Grant Plan under the 2012 Long-Term Incentive Program approved January 19, 2012 (Exhibit 10.1, Form 8-K filed January 20, 2012, File No. 1-8489).      X         X         X   
10.34*    Form of Restricted Stock Award Agreement under the 2012 Long-term Incentive Program approved January 19, 2012 (Exhibit 10.2, Form 8-K filed January 20, 2012, File No. 1-8489).      X         X         X   
10.35*    2013 Performance Grant Plan under 2013 Long-Term Incentive Program approved January 24, 2013 (Exhibit 10.1, Form 8-K filed January 25, 2013, File No. 1-8489).      X         X         X   
10.36*    Form of Restricted Stock Award Agreement under the 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.2, Form 8-K filed January 25, 2013, File No. 1-8489).      X         X         X   
10.37*    Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010 (Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489).      X         X         X   
10.38*    Retirement Agreement, dated as of June 20, 2013, between Dominion Resources, Inc. and Gary L. Sypolt (Exhibit 10.1, Form 8-K filed June 24, 2013, File No. 1-8489).      X         
10.39*    2014 Performance Grant Plan under 2014 Long-Term Incentive Program approved January 16, 2014 (Exhibit 10.40, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489).      X         X         X   
10.40*    Form of Restricted Stock Award Agreement under the 2014 Long-term Incentive Program approved January 16, 2014 (Exhibit 10.41, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489).      X         X         X   
10.41*    Form of Special Performance Grant for Thomas F. Farrell II and Mark F. McGettrick approved January 16, 2014 (Exhibit 10.42, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489).      X         X         X   
10.42*    2015 Performance Grant Plan under 2015 Long-Term Incentive Program approved January 22, 2015 (filed herewith).      X         X         X   
10.43*    Form of Restricted Stock Award Agreement under the 2015 Long-term Incentive Program approved January 22, 2015 (filed herewith).      X         X         X   

 

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Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
10.44*    Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).      X         
10.45*    Non-employee directors’ annual compensation for Dominion Resources, Inc. (filed herewith).      X         
10.46*    Dominion Resources, Inc. 2014 Incentive Compensation Plan, effective May 7, 2014 (Exhibit 10.1, Form 8-K filed May 7, 2014, File No. 1-8489).      X         X         X   
10.47    Registration Rights Agreement, dated as of October 22, 2013, by and among Dominion Gas Holdings, LLC and RBC Capital Markets, LLC, RBS Securities Inc. and Scotia Capital (USA) Inc., as the initial purchasers of the Notes (Exhibit 10.1, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
10.48    Inter-Company Credit Agreement, dated October 17, 2013, between Dominion Resources, Inc. and Dominion Gas Holdings, LLC (Exhibit 10.2, Form S-4 filed April 4, 2014, File No. 333-195066).      X            X   
10.49    DRS Services Agreement, dated September 12, 2013, between Dominion Gas Holdings, LLC and Dominion Resources Services, Inc. (Exhibit 10.3, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
10.50    DRS Services Agreement, dated January 1, 2003, between Dominion Transmission Inc. and Dominion Resources Services, Inc. (Exhibit 10.4, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
10.51    DRS Services Agreement, dated January 1, 2003, between The East Ohio Company and Dominion Resources Services, Inc. (Exhibit 10.5, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
10.52    DRS Services Agreement, dated January 1, 2003, between Dominion Iroquois, Inc. and Dominion Resources Services, Inc. (Exhibit 10.6, Form S-4 filed April 4, 2014, File No. 333-195066).            X   
12.a    Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).      X         
12.b    Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).         X      
12.c    Ratio of earnings to fixed charges for Dominion Gas Holdings, LLC (filed herewith).            X   
21    Subsidiaries of Dominion Resources, Inc. (filed herewith).      X         
23    Consent of Deloitte & Touche LLP (filed herewith).      X         X         X   
31.a    Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).      X         
31.b    Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).      X         
31.c    Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).         X      
31.d    Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).         X      
31.e    Certification by Chief Executive Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).            X   
31.f    Certification by Chief Financial Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).            X   
32.a    Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).      X         
32.b    Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).         X      

 

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Exhibit

Number

  

Description

   Dominion      Virginia
Power
     Dominion
Gas
 
32.c    Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).            X   
101    The following financial statements from Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC Annual Report on Form 10-K for the year ended December 31, 2014, filed on February 27, 2015, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.      X         X         X   

 

* Indicates management contract or compensatory plan or arrangement

 

178