10-K 1 d283555d10k.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, 2011

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
333-178772   VIRGINIA ELECTRIC AND POWER COMPANY   54-0418825
 

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

2009 Series A 8.375%

Enhanced Junior Subordinated Notes

  New York Stock Exchange
VIRGINIA ELECTRIC AND POWER COMPANY  

Preferred Stock (cumulative),

$100 par value, $5.00 dividend

  New York Stock Exchange

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

None

 

 

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  ¨

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

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  ¨

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  ¨

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.    x            Virginia Electric and Power Company    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  ¨
   

(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

The aggregate market value of Dominion Resources, Inc. common stock held by non-affiliates of Dominion was approximately $22.3 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 the registrant’s most recently completed second fiscal quarter. Dominion is the sole holder of Virginia Electric and Power Company common stock. As of January 31, 2012, Dominion had 570,127,118 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding.

DOCUMENT INCORPORATED BY REFERENCE.

Portions of Dominion’s 2012 Proxy Statement are incorporated by reference in Part III.

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

 

 

 


Table of Contents

Dominion Resources, Inc. and

Virginia Electric and Power Company

 

 

 

 

Item

Number

         
 
Page
Number
  
  
  

Glossary of Terms

     1   

Part I

  

1.

  

Business

     5   

1A.

  

Risk Factors

     20   

1B.

  

Unresolved Staff Comments

     25   

2.

  

Properties

     25   

3.

  

Legal Proceedings

     28   

4.

  

Mine Safety Disclosures

     28   
  

Executive Officers of Dominion

     29   

Part II

  

5.

  

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

     30   

6.

  

Selected Financial Data

     31   

7.

  

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

     32   

7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     51   

8.

  

Financial Statements and Supplementary Data

     53   

9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     123   

9A.

  

Controls and Procedures (Dominion)

     123   

9B.

  

Other Information

     126   

Part III

  

10.

  

Directors, Executive Officers and Corporate Governance

     126   

11.

  

Executive Compensation

     127   

12.

  

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

     150   

13.

  

Certain Relationships and Related Transactions, and Director Independence

     150   

14.

  

Principal Accountant Fees and Services

     151   

Part IV

  

15.

  

Exhibits and Financial Statement Schedules

     152   


Table of Contents

Glossary of Terms

 

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

 

Abbreviation or Acronym    Definition

2009 Base Rate Review

  

Order entered by the Virginia Commission in January 2009, pursuant to the Regulation Act, initiating reviews of the base rates and terms and conditions of all investor-owned utilities in Virginia

2012 Proxy Statement

  

Dominion 2012 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

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

ASA

  

Average Speed of Answer, a primary metric used to measure customer service

ASLB

  

Atomic Safety and Licensing Board

bcf

  

Billion cubic feet

Bear Garden

  

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

Biennial Review Order

  

Order issued by the Virginia Commission in November 2011 concluding the 2009 - 2010 biennial review of Virginia Power’s base rates, terms and conditions

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

BVP

  

Book Value Performance

CAA

  

Clean Air Act

CAIR

  

Clean Air Interstate Rule

CAO

  

Chief Accounting Officer

Carson-to-Suffolk line

  

Virginia Power 60-mile 500-kV transmission line in southeastern Virginia

CD&A

  

Compensation Discussion and Analysis

CDO

  

Collateralized debt obligation

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

Chesapeake

  

Chesapeake power station

CNG

  

Consolidated Natural Gas Company

CNO

  

Chief Nuclear Officer

CO2

  

Carbon dioxide

COL

  

Combined Construction Permit and Operating License

Companies

  

Dominion and Virginia Power, 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

Cove Point

  

Dominion Cove Point LNG, LP

CSAPR

  

Cross State Air Pollution Rule

CWA

  

Clean Water Act

DCI

  

Dominion Capital, Inc.

DD&A

  

Depreciation, depletion and amortization expense

DEI

  

Dominion Energy, Inc.

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 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

Dooms-to-Bremo line

  

Virginia Power project to rebuild approximately 53 miles of existing 115-kV to 230-kV lines, between the Dooms and Bremo substations

 

        1

 


Table of Contents

Glossary of Terms, continued

 

 

 

Abbreviation or Acronym    Definition

DPP

  

Dominion’s Defined Benefit Pension Plan

Dresden

  

Partially-completed merchant generation facility sold in 2007

DRS

  

Dominion Resources Services, Inc.

DSM

  

Demand-side management

DTI

  

Dominion Transmission, Inc.

DVP

  

Dominion Virginia Power operating segment

E&P

  

Exploration & production

East Ohio

  

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

EGWP

  

Employer Group Waiver Plan

EPA

  

Environmental Protection Agency

EPACT

  

Energy Policy Act of 2005

EPS

  

Earnings per share

ERISA

  

The Employment Retirement Income Security Act of 1974

ERO

  

Electric Reliability Organization

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

  

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

GHG

  

Greenhouse gas

GWSA

  

Global Warming Solutions Act

Hayes-to-Yorktown line

  

Virginia Power project to construct an approximately eight-mile 230-kV transmission line in southeastern Virginia

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

IOGA

  

Independent Oil and Gas Association of West Virginia, Inc.

INPO

  

Institute of Nuclear Power Operations

IRC

  

Internal Revenue Code

IRS

  

Internal Revenue Service

ISO

  

Independent system operator

ISO-NE

  

ISO New England

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

LIBOR

  

London Interbank Offered Rate

LIFO

  

Last-in-first-out inventory method

LNG

  

Liquefied natural gas

LTIP

  

Long-term incentive program

MATS

  

Utility Mercury and Air Toxics Standard Rule

Manchester Street

  

Manchester Street power station

mcf

  

million cubic feet

MD&A

  

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

Meadow Brook-to-Loudoun line

  

An approximately 65-mile 500-kV transmission line that begins in Warren County, Virginia and terminates in Loudoun County, Virginia

Medicare Act

  

The Medicare Prescription Drug, Improvement and Modernization Act of 2003

Medicare Part D

  

Prescription drug benefit introduced in the Medicare Act

MF Global

  

MF Global Inc.

 

2        

 


Table of Contents

 

 

Abbreviation or Acronym    Definition

MGD

  

Million gallons a day

Millstone

  

Millstone nuclear power station

MISO

  

Midwest Independent Transmission System Operators, Inc.

MNES

  

Mitsubishi Nuclear Energy Systems, Inc., a wholly-owned subsidiary of Mitsubishi Heavy Industries, Inc.

Moody’s

  

Moody’s Investors Service

Mt. Storm-to-Doubs line

  

Virginia Power project to rebuild approximately 96 miles of an existing 500-kV transmission line in Virginia and West Virginia

MW

  

Megawatt

MWh

  

Megawatt hour

NAAQS

  

National Ambient Air Quality Standards

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 Branch

  

North Branch power station

North Carolina Commission

  

North Carolina Utilities Commission

North Carolina Settlement Approval Order

  

Order issued by the North Carolina Commission in December 2010 approving the Stipulation and Settlement Agreement filed by Virginia Power in connection with the ending of its North Carolina base rate moratorium

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

ODEC

  

Old Dominion Electric Cooperative

Ohio Commission

  

Public Utilities Commission of Ohio

OSHA

  

Occupational Safety and Health Administration

PBGC

  

Pension Benefit Guaranty Corporation

Peaker facilities

  

Collectively, the three natural gas-fired merchant generation peaking facilities sold in 2007

Pennsylvania Commission

  

Pennsylvania Public Utility Commission

Peoples

  

The Peoples Natural Gas Company

Pipeline Safety Act

  

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

PIPP

  

Percentage of Income Payment Plan

PIR

  

Pipeline Infrastructure Replacement program deployed by East Ohio

PJM

  

PJM Interconnection, LLC

PM&P

  

Pearl Meyer & Partners

PNG Companies LLC

  

An indirect subsidiary of Steel River Infrastructure Fund North America

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

REIT

  

Real estate investment trust

RGGI

  

Regional Greenhouse Gas Initiative

Rider B

  

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

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 T

  

A rate adjustment clause associated with the recovery of certain electric transmission-related expenditures

Rider W

  

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

Riders C1 and C2

  

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

ROE

  

Return on equity

ROIC

  

Return on invested capital

 

        3

 


Table of Contents

 

 

Abbreviation or Acronym    Definition

RPM Buyers

  

The Maryland Public Service Commission, Delaware Public Service Commission, Pennsylvania Commission, New Jersey Board of Public Utilities and several other organizations representing consumers in the PJM region

RPS

  

Renewable Portfolio Standard

RTEP

  

Regional transmission expansion plan

RTO

  

Regional transmission organization

SAIDI

  

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

Salem Harbor

  

Salem Harbor power station

SEC

  

Securities and Exchange Commission

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

TGP

  

Tennessee Gas Pipeline Company

TSR

  

Total shareholder return

U.S.

  

United States of America

U.S. DOT

  

United States Department of Transportation

UAO

  

Unilateral Administrative Order

UEX Rider

  

Uncollectible Expense Rider

US-APWR

  

Mitsubishi Heavy Industry’s Advanced Pressurized Water Reactor

VEBA

  

Voluntary Employees’ Beneficiary Association

VIE

  

Variable interest entity

Virginia City Hybrid Energy Center

  

A 585 MW baseload carbon-capture compatible, clean coal powered electric generation facility under construction 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

Virginia Settlement Approval Order

  

Order issued by the Virginia Commission in March 2010 concluding Virginia Power’s 2009 Base Rate Review

VPDES

  

Virginia Pollutant Discharge Elimination System

VSWCB

  

Virginia State Water Control Board

Warren County

  

A 1,300 MW, combined-cycle, natural gas-fired power station under construction in Warren County, Virginia

Waxpool-Brambleton-BECO line

  

A Virginia Power project to construct an approximately 1.5 mile double circuit 230-kV line to a new Waxpool substation, and a new 230-kV line between the Brambleton and BECO substations

West Virginia Commission

  

Public Service Commission of West Virginia

Yorktown

  

Yorktown power station

 

4        

 


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. Dominion’s portfolio of assets includes approximately 28,142 MW of generating capacity, 6,300 miles of electric transmission lines, 56,800 miles of electric distribution lines, 11,000 miles of natural gas transmission, gathering and storage pipeline and 21,800 miles of gas distribution pipeline, exclusive of service lines of two inches in diameter or less. Dominion also operates the nation’s largest underground natural gas storage system, with approximately 947 bcf of storage capacity, and serves nearly 6 million utility and retail energy customers in 15 states.

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. As a result, regulated capital projects will continue to receive priority treatment in its spending plans. Dominion expects this will increase its earnings contribution from regulated operations, while reducing the sensitivity of its earnings to commodity prices.

Dominion continues to expand and improve its regulated electric and natural gas businesses, in accordance with its five-year investment program. A major impetus for this program is to meet the anticipated increase in electricity demand in its electric utility service territory as forecasted by PJM. Other drivers for the capital investment program include the need to construct infrastructure to handle the increase in natural gas production from the Marcellus and Utica Shale formations; and to upgrade its gas distribution and electric transmission and distribution network. Dominion has announced that it may make further substantial investments in other gas projects over the next five years.

Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations. Dominion’s operations are conducted through various subsidiaries, including Virginia Power.

Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is 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.” 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 common stock is owned by Dominion.

Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.

 

 

EMPLOYEES

As of December 31, 2011, Dominion had approximately 15,800 full-time employees, of which approximately 5,900 employees are subject to collective bargaining agreements. As of December 31, 2011, Virginia Power had approximately 6,800 full-time employees, of which approximately 3,100 employees are subject to collective bargaining agreements.

 

 

PRINCIPAL EXECUTIVE OFFICES

Dominion and Virginia Power’s principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and their telephone number is (804) 819-2000.

 

 

WHERE YOU CAN FIND MORE INFORMATION ABOUT DOMINION AND VIRGINIA POWER

Dominion and Virginia Power 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.

Dominion and Virginia Power 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, www.dom.com, as soon as practicable after filing or furnishing the material to the SEC. You may also request a copy of these filings, at no cost, by writing or telephoning Dominion at: Corporate Secretary, Dominion, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Information contained on Dominion’s website is not incorporated by reference in this report.

 

 

ACQUISITIONS AND DISPOSITIONS

Following are significant divestitures by Dominion and Virginia Power during the last five years. There were no significant acquisitions by either registrant during this period.

SALE OF E&P PROPERTIES

In 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations, including its rights to associated Marcellus acreage, to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. See Note 4 to the Consolidated Financial Statements for additional information.

In 2007, Dominion completed the sale of its non-Appalachian natural gas and oil E&P operations and assets for approximately $13.9 billion.

The historical results of the non-Appalachian E&P operations are included in the Corporate and Other segment. The historical results of the Appalachian E&P operations are included in the Dominion Energy segment.

 

 

        5

 


Table of Contents

 

 

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. The historical results of these operations are included in the Corporate and Other segment and presented in discontinued operations. See Note 4 to the Consolidated Financial Statements for additional information.

ASSIGNMENT OF MARCELLUS ACREAGE

In 2008, Dominion completed a transaction with Antero Resources to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. Dominion received proceeds of approximately $347 million. Under the agreement, Dominion received a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. The overriding royalty interest was transferred to CONSOL as part of the sale of substantially all of Dominion’s Appalachian E&P operations in 2010.

SALE OF MERCHANT FACILITIES

In March 2007, Dominion sold three Peaker facilities for net cash proceeds of $254 million. The Peaker facilities included the 625 MW Armstrong facility in Shelocta, Pennsylvania; the 600 MW Troy facility in Luckey, Ohio; and the 313 MW Pleasants facility in St. Mary’s, West Virginia. The results of these operations were presented in discontinued operations.

SALE OF DRESDEN

In September 2007, Dominion completed the sale of Dresden to AEP Generating Company for $85 million.

SALE OF CERTAIN DCI OPERATIONS

In March 2008, Dominion reached an agreement to sell its remaining interest in the subordinated notes of a third-party CDO entity held as an investment by DCI and in April 2008 received proceeds of $54 million, including accrued interest. Dominion deconsolidated the CDO entity as of March 31, 2008.

In August 2007, Dominion completed the sale of Gichner, LLC, all of the issued and outstanding shares of the capital stock of Gichner, Inc. (an affiliate of Gichner, LLC) and Dallastown Realty for approximately $30 million.

 

 

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 the operations and sale of Peoples, which is discussed in Note 4 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.

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.

While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by Dominion and Virginia Power 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
 

DVP

  Regulated electric distribution     X        X   
  Regulated electric transmission     X        X   
   

Nonregulated retail energy marketing (electric and gas)

    X           

Dominion Generation

  Regulated electric fleet     X        X   
    Merchant electric fleet     X           

Dominion Energy

  Gas transmission and storage     X     
  Gas distribution and storage     X     
  LNG import and storage     X     
    Producer services     X           

For additional financial information on operating segments, including revenues from external customers, see Note 26 to the Consolidated Financial Statements. For additional information on operating revenue related to Dominion’s and Virginia Power’s principal products and services, see Notes 2 and 5 to the Consolidated Financial Statements, which information is incorporated herein by reference.

DVP

The DVP Operating Segment of Virginia Power includes Virginia Power’s regulated electric transmission and distribution (including customer service) operations, which serve approximately 2.4 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.

Virginia Power has announced its five-year investment plan, which includes spending approximately $4 billion from 2012 through 2016 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 population growth and increases in electricity consumption by the typical consumer. In addition, data centers continue to contribute to anticipated demand growth, with an expected load of approximately 715 MW by the end of 2013.

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. The three-year average SAIDI has improved from 127 minutes at the end of 2006 to 111 minutes at the end of 2011. Likewise, ASA has also shown significant improvement. The three-year average ASA has improved from 60

 

 

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seconds at the end of 2006 to 40 seconds at the end of 2011. Customer service options continue to be enhanced and expanded through the use of technology. Customers now have the ability to use the Internet for routine billing and payment transactions, connecting and disconnecting service, reporting outages and obtaining outage updates. Additionally, customers can follow progress to restore electric service following major outages by accessing Facebook or Twitter. As electric distribution moves forward, safety, electric service reliability and customer service will remain key focal areas.

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.

The DVP Operating Segment of Dominion includes all of Virginia Power’s regulated electric transmission and distribution operations as discussed above, as well as Dominion’s nonregulated retail energy marketing operations.

Dominion’s retail energy marketing operations compete in nonregulated energy markets. The retail business requires limited capital investment and currently employs approximately 190 people. The retail customer base includes 2.2 million customers and is diversified across three product lines-natural gas, electricity and home warranty services. Dominion has a heavy concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice. Dominion pursues customers in electricity markets where utilities have divested of generation assets and where customers are permitted and have opted to purchase from the market. Major growth drivers are net customer additions, new market penetration, product development and expanded sales channels and supply optimization.

COMPETITION

DVP Operating Segment—Dominion and Virginia Power

Within Virginia Power’s service territory in Virginia and North Carolina, there is no competition for electric distribution service. Additionally, since its electric transmission facilities are integrated into PJM, electric transmission services are administered by PJM and are not subject to competition in relation to transmission service provided to customers within the PJM region. Virginia Power is seeing continued growth in new customers in its transmission and distribution operations.

DVP Operating Segment—Dominion

Dominion’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated

energy markets for natural gas and electricity. 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

Virginia Power’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia Commission and the North Carolina Commission. Virginia Power’s 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 14 to the Consolidated Financial Statements for additional information, including a discussion of the 2011 Biennial Review Order.

PROPERTIES

Virginia Power has approximately 6,300 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.

Each year, as part of PJM’s RTEP process, reliability projects are authorized. In 2011, Virginia Power completed construction of two of the major construction projects authorized in 2006, Meadow Brook-to-Loudoun and Carson-to-Suffolk, which are each designed to improve the reliability of service to customers and the region.

As part of subsequent annual PJM RTEP processes, PJM authorized additional electric transmission upgrade projects including Hayes-to-Yorktown in December 2008 and Mt. Storm-to-Doubs and Dooms-to-Bremo in December 2010. See Note 14 to the Consolidated Financial Statements for additional information on these and other electric transmission projects.

In addition, Virginia Power’s electric distribution network includes approximately 56,800 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 owner 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.

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.

 

 

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DVP Operating Segment—Dominion

The supply of electricity to serve Dominion’s retail energy marketing customers is procured through market wholesalers and RTO or ISO transactions. DVP’s supply of gas to serve its customers is procured through market wholesalers or by Dominion Energy. See Dominion Energy 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 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.

DVP Operating Segment—Dominion

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

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.

Earnings for the 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. Rates for the Virginia jurisdiction are set using a modified cost-of-service rate model. 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. Variability in earnings for Virginia Power’s generation operations results from changes in rates, the demand for services, which is primarily weather dependent, and labor and benefit costs, as well as the timing, duration and costs of scheduled and unscheduled outages. See Electric Regulation in Virginia under Regulation and Note 14 to the Consolidated Financial Statements for additional information, including a discussion of the 2011 Biennial Review Order.

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

associated capacity and ancillary services from Dominion’s merchant generation assets.

Variability in earnings provided by Dominion’s 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 electric and capacity price volatility of its merchant fleet by hedging a substantial portion of its expected near-term sales with derivative instruments and also entering into long-term power sales agreements. However, earnings have been adversely impacted due to a sustained decline in commodity prices. 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.

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 merchant generation fleet is dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that allows for a rate of return on its capital investments. Competition for the 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 merchant generation fleet owns and operates several facilities in the Midwest that operate within functioning RTOs. A significant portion of the output from these facilities is sold under long-term contracts, with expiration dates ranging from December 31, 2012 to August 31, 2017, and is therefore largely unaffected by price competition during the term of these contracts. Following expiration of these contracts, earnings could be adversely impacted if prevailing prices for energy, capacity and ancillary services are lower than the levels currently received under these contracts.

Dominion Generation’s other merchant assets also 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

 

 

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functioning properly. Dominion Generation’s merchant units have a variety of short- and medium-term contracts, and also 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 merchant fleet is competitive compared to similar assets within the region.

REGULATION

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 Commission and the North Carolina Commission. See State Regulations and Federal Regulations in Regulation 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 18,985 MW. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro and renewables. Virginia Power’s generation facilities are located in Virginia, West Virginia and North Carolina and serve load in Virginia and northeastern North Carolina.

Based on available generation capacity and current estimates of growth in customer demand in its utility service area, Virginia Power will need additional generation capacity over the next decade. Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the anticipated growing demand in its core market in Virginia. Significant projects under construction or development include:

Ÿ  

The Virginia City Hybrid Energy Center located in Wise County, Virginia, is expected to generate about 585 MW when completed. The baseload facility is estimated to cost $1.8 billion, excluding financing costs. Construction was approximately 95% complete at the end of 2011, and commercial operations are expected to commence in the summer of 2012.

Ÿ  

Warren County is expected to generate more than 1,300 MW of electricity when operational. In February 2012, the Virginia Commission authorized the construction of this power station, which is estimated to cost approximately $1.1 billion, excluding financing costs. Commercial operations are scheduled to commence by late 2014. In connection with the air permit process for Warren County, Virginia Power reached an agreement to permanently retire North Branch, a 74 MW coal-fired plant located in West Virginia, once Warren County begins commercial operations.

Ÿ  

Virginia Power plans to convert three coal-fired Virginia generating stations to biomass, a renewable energy source. The conversions of the power stations in Altavista, Hopewell and Southampton County would increase Dominion’s renewable generation by more than 150 MW and are expected to cost approximately $165 million, excluding financing costs. After approvals by the Virginia Department of Environmental Quality and the Virginia Commission, construction will begin; these conversions are expected to be complete by the end of 2013.

Ÿ  

Subject to the receipt of certain regulatory approvals, Virginia Power plans to construct a combined-cycle natural gas-fired power station in Brunswick County, Virginia, that is expected to generate more than 1,300 MW. If the project is approved, commercial operations are expected to commence in 2016. Brunswick County has approved a conditional use permit to allow for construction of the plant. This facility would more than offset the expected reduction in capacity caused by the anticipated retirement of coal-fired units at Chesapeake and Yorktown during 2015 and 2016 primarily due to the cost of compliance with MATS. The facility would be similar to the power station being built in Warren County, Virginia, which is estimated to cost approximately $1.1 billion, excluding financing costs.

In May 2011, Virginia Power completed construction of Bear Garden, at a total cost of approximately $620 million, excluding financing costs, and the 590 MW combined-cycle, natural gas-fired power station commenced commercial operations.

In addition to the projects above, Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. See Note 14 to the Consolidated Financial Statements for more information on this project.

Dominion Generation Operating Segment—Dominion

The generation capacity of Dominion’s merchant fleet totals 9,157 MW. The generation mix is diversified and includes nuclear, coal, gas, oil and renewables. Merchant generation facilities are located in Connecticut, Illinois, Indiana, Massachusetts, Pennsylvania, Rhode Island, West Virginia and Wisconsin with a majority of that capacity concentrated in New England. Dominion is the largest generator in ISO-NE and, mirroring the region’s load demand, has principally baseload units with the remainder split between intermediate and peaking.

In the first quarter of 2011, Dominion decided to pursue the sale of Kewaunee. Any sale of Kewaunee would be subject to the approval of Dominion’s Board of Directors, as well as applicable state and federal approvals.

During the second quarter of 2011, Dominion announced its intention to retire State Line by mid-2014 and to retire two of the four units at Salem Harbor by the end of 2011 and the remaining two Salem Harbor units on June 1, 2014. These decisions were prompted by the economic outlook for both facilities, in combination with the expectation that State Line would be impacted by potential environmental regulations that would likely require significant capital expenditures. During the third quarter of 2011, Dominion announced an accelerated schedule for State Line, with the facility to be retired in the first quarter of 2012, given a continued decline in power prices and the expected cost to comply with environmental regulations.

 

 

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Salem Harbor units 1 and 2 were retired as planned on December 31, 2011.

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, oil 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 both domestic and international 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, 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 allows flexibility in delivering natural gas to its gas turbine fleet, while minimizing costs.

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, ISO-NE and MISO 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    2011     2010     2009  

Purchased power, net

     33     29     25

Nuclear(1)

     28        28        32   

Coal(2)

     26        31        33   

Natural gas

     12        10        9   

Other(3)

     1        2        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 2011 Virginia in-system generation was $33.55 per MWh.
(3) Includes oil, hydro and biomass.

SEASONALITY

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. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree-days 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.

NUCLEAR DECOMMISSIONING

In June 2011, the NRC amended its regulations to improve decommissioning planning. As applied to the operators of nuclear power plants, these amendments require licensees to conduct operations in a manner minimizing introduction of residual radioactivity into the site, perform additional surveys, and maintain records of their results. In addition, the amendments make minor changes to financial assurance methods and require additional information on decommissioning and spent fuel management costs after a plant permanently ceases operations. The revised regulations will become effective in December 2012 and are not expected to significantly affect the decommissioning cost estimates or funding for Dominion’s or Virginia Power’s units.

Dominion Generation Operating Segment—Dominion and Virginia Power

Virginia Power has a total of four licensed, operating nuclear reactors at its Surry and North Anna power stations 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 and placed into trusts have been 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 requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC.

The total estimated cost to decommission Virginia Power’s four nuclear units is $2.2 billion in 2011 dollars and is primarily based upon site-specific studies completed in 2009. 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 2067.

 

 

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Dominion Generation Operating Segment—Dominion

In addition to the four nuclear units discussed above, Dominion has three licensed, operating nuclear reactors, two at Millstone in Connecticut and one at Kewaunee in Wisconsin. A third Millstone unit ceased operations before Dominion acquired the power station. 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 requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC. The total estimated cost to decommission Dominion’s eight units is $4.7 billion in 2011 dollars and is primarily based upon site-specific studies completed in 2009. For the Millstone and Kewaunee operating units, the current cost estimate assumes decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Millstone Unit 1 is not in service and selected minor decommissioning activities are being performed. This unit will continue to be monitored until full decommissioning activities begin for the remaining Millstone operating units. Dominion expects to start minor decommissioning activities at Millstone Unit 2 in 2035, with full decommissioning of Millstone Units 1, 2 and 3 at the permanent cessation of operations of Millstone Unit 3 during the period 2045 to 2069. In February 2011, the NRC approved the renewal of the Kewaunee operating license. The renewal permits Kewaunee to operate through December 21, 2033 with full decommissioning of Kewaunee during the period 2033 to 2065.

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

(2011
dollars)(1)

     Funds in
trusts at
December 31,
2011
    

2011

Contributions

To Trusts

 
(dollars in millions)                            

Surry

           

Unit 1

     2032       $ 562       $ 387       $ 0.6   

Unit 2

     2033         584         382         0.6   

North Anna

           

Unit 1(2)

     2038         509         310         0.4   

Unit 2(2)

     2040         522         291         0.3   

Total (Virginia Power)

        2,177         1,370         1.9   

Millstone

           

Unit 1(3)

     n/a         450         321           

Unit 2

     2035         676         398           

Unit 3(4)

     2045         706         393           

Kewaunee

                

Unit 1

     2033         681         517           

Total (Dominion)

            $ 4,690       $ 2,999       $ 1.9   

 

(1) The cost estimates shown above are total decommissioning cost estimates and differ from the cost estimates used to calculate Dominion’s and Virginia Power’s nuclear decommissioning AROs. Among other items, the cost estimates above do not reflect any reduction for the expected future
  recovery from the DOE of certain spent fuel costs based on the Companies’ contracts with the DOE for disposal of spent nuclear fuel.
(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 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 Wholesale Electric Company and Central Vermont Public Service Corporation. Decommissioning cost is shown at 100% and the trust funds are shown at Dominion’s ownership percentage. At December 31, 2011, the minority owners held approximately $27 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.

Also see Note 15 and Note 23 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively.

Dominion Energy

Dominion Energy includes Dominion’s regulated natural gas distribution companies, regulated gas transmission pipeline and storage operations, natural gas gathering and by-products extraction activities and regulated LNG operations. Dominion Energy also includes producer services, 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 gas transmission pipeline and storage business serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in Dominion’s gas transmission pipeline and storage business is its gas gathering and extraction activity, which sells extracted products at market rates. 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. In connection with the recent increase in Eastern U.S. natural gas production, including from the Marcellus and Utica shale formations, Dominion has requested regulatory authority to operate Cove Point as a bi-directional facility, able to import LNG, and vaporize it as natural gas, and liquefy natural gas and export it as LNG. See Future Issues and Other Matters in MD&A for more information.

Revenue provided by Dominion’s regulated gas transmission and storage and LNG operations is based primarily on rates established by FERC. Additionally, Dominion receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain gas transportation, gas storage, LNG storage and regasification services. Dominion’s gas distribution operations serve residential, commercial and industrial gas sales and transportation customers. Revenue provided by its gas distribution operations is based primarily on rates established by the Ohio and West Virginia Commissions. The profitability of these businesses is dependent on Dominion’s 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 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.

In October 2008, East Ohio implemented a rate case settlement which provided for a straight-fixed-variable rate design.

 

 

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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.

Earnings from Dominion Energy’s producer services business are unregulated, and are subject to variability associated with changes in commodity prices. Producer services uses physical and financial arrangements to hedge this price risk.

COMPETITION

Dominion Energy’s gas transmission operations compete with domestic and Canadian pipeline companies. Dominion 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.

Retail competition for gas supply exists to varying degrees in the two states in which Dominion’s gas distribution subsidiaries operate. In Ohio, there has been no legislation enacted to require supplier choice for residential and commercial natural gas consumers. However, Dominion offers an Energy Choice program to customers, in cooperation with the Ohio Commission. At December 31, 2011, approximately 1 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice Program. West Virginia does not require customers to choose their provider in its retail natural gas markets at this time. 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. See Regulation-State Regulations-Gas for additional information.

REGULATION

Dominion Energy’s natural gas transmission pipeline, storage and LNG operations are regulated primarily by FERC. Dominion Energy’s gas distribution service, including the rates that it may charge customers, is regulated by the Ohio and West Virginia Commissions. See State Regulations and Federal Regulations in Regulation for more information.

PROPERTIES

Dominion Energy’s gas distribution network is located in the states of Ohio and West Virginia. This network involves approximately 21,800 miles of pipe, exclusive of service lines of two inches in diameter or less. The rights-of-way grants for many natural gas pipelines have been obtained from the actual owner 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 Energy has approximately 11,000 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy operates gas processing and fractionation facilities in West Virginia with a total processing capacity of 267,000 mcf per day and fractionation capacity of 582,000 gallons per day. Dominion Energy also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with almost 2,000 storage wells and approximately 349,000 acres of operated leaseholds.

The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 947 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy. The capacity of those fields owned by Dominion’s partners totals about 242 bcf. Dominion Energy also has about 15 bcf of above-ground storage capacity at Cove Point. Dominion Energy has about 128 compressor stations with more than 777,000 installed compressor horsepower.

In August 2009, Dominion announced the proposed development of the Keystone Connector Project, a joint venture with The Williams Companies that would transport new natural gas supplies from the Appalachian Basin to Transcontinental Gas Pipe Line Corporation’s Station 195, providing access to markets throughout the eastern U.S. The joint venture was terminated in June 2011. DTI is currently independently marketing its Keystone Connector Project. Project timing is subject to producer drilling plans in the Appalachian Basin, as well as customer demand throughout the mid-Atlantic and Northeast regions.

In January 2011, Dominion completed the $50 million Cove Point Pier Reinforcement Project to upgrade, expand and modify the existing pier at the Cove Point terminal to accommodate the next generation of LNG vessels (up to 267,000 cubic meters) that are much larger than those that could previously be accommodated (no larger than 148,000 cubic meters).

DTI has announced the Gathering Enhancement Project, a $253 million expansion of its natural gas gathering, processing and liquids facilities in West Virginia. The project is designed to increase the efficiency and reduce high pressures in its gathering system, thus increasing the amount of natural gas local producers can move through DTI’s West Virginia system. Construction started in 2009 and is expected to be completed by the fourth quarter of 2012. The cost of the project will be paid for by rates charged to producers.

In June 2011, FERC approved DTI’s $634 million Appalachian Gateway Project. The project is expected to provide approximately 484,000 dekatherms per day of firm transportation services for new Appalachian gas supplies in West Virginia and southwestern Pennsylvania to an interconnection with Texas Eastern Transmission, LP at Oakford, Pennsylvania. Construction has commenced and transportation services are scheduled to begin by September 2012.

In August 2011, DTI received FERC authorization for the Northeast Expansion Project. The project is expected to provide approximately 200,000 dekatherms per day of firm transportation services for CONSOL’s Marcellus Shale natural gas production from various receipt points in central and southwestern Pennsylvania to a nexus of market pipelines and storage facilities in Leidy, Pennsylvania. The project is expected to cost approximately $100 million. Construction of new compression facilities

 

 

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at three existing compressor stations in central Pennsylvania is expected to begin in March 2012, with a projected in-service date of November 2012.

In September 2011, FERC approved DTI’s proposed Ellisburg-to-Craigs project. The project is expected to have capacity of approximately 150,000 dekatherms per day, which will be leased by TGP to move Marcellus shale natural gas supplies from TGP’s 300 Line pipeline system in northern Pennsylvania to its 200 Line pipeline system in upstate New York. The project is expected to cost approximately $46 million. Construction of additional compression facilities and a new measurement and regulating station is expected to begin in March 2012, with a projected in-service date of November 2012.

In November 2011, DTI filed a FERC application for approval to construct the $17 million Sabinsville to Morrisville project, a pipeline to move additional Marcellus supplies from a TGP pipeline in northeast Pennsylvania to its line in upstate New York. DTI executed a binding precedent agreement with TGP in October 2010 to provide this firm transportation service up to 92,000 dekatherms per day for a 14-year term. Construction is expected to commence April 2013 with an expected in service date of November 2013.

DTI is developing the Allegheny Storage Project, which is expected to provide approximately 7.5 bcf of incremental storage service and 125,000 dekatherms per day of associated year-round firm transportation service to three local distribution companies under 15-year contracts. Storage capacity for the project will be provided from storage pool enhancements at DTI and capacity leased from East Ohio. DTI intends to construct additional compression facilities and upgrade measurement and regulation in order to provide 115,000 dekatherms per day of transportation service. The remaining 10,000 dekatherms per day of transportation service will not require construction of additional facilities. The $112 million project is expected to be in service in 2014, subject to FERC approval, which DTI requested in February 2012.

In February 2011, DTI concluded a binding open season for its $67 million Tioga Area Expansion Project, which is designed to provide approximately 270,000 dekatherms per day of firm transportation service from supply interconnects in Tioga and Potter Counties in Pennsylvania to DTI’s Crayne interconnect with Texas Eastern Transmission, LP in Greene County, Pennsylvania and the Leidy interconnect with Transcontinental Gas Pipe Line Company in Clinton County, Pennsylvania. Two customers have contracted for the service under 15-year terms. DTI filed a certificate application with FERC in November 2011. Subject to the receipt of regulatory approvals, the project is anticipated to be in service in November 2013.

In January 2011, Dominion announced the development of a natural gas processing and fractionation facility in Natrium, West Virginia, and in July 2011 it executed a contract for the construction of the first phase of the facility. This phase of the project is fully contracted and is expected to be in service by December 2012. The Phase 1 costs for processing, fractionation, plant inlet and outlet natural gas transportation, gathering, and various modes of NGL transportation is approximately $500 million. Dominion is also in negotiations for the possible construction of Phase 2 at Natrium, which could be in service by the fourth quar-

ter of 2013. The complete project is designed to process up to 400,000 mcf of natural gas per day and fractionate up to 59,000 barrels of NGLs per day.

In March 2011, East Ohio filed a request with the Ohio Commission to accelerate the PIR program by nearly doubling its PIR spending to more than $200 million annually. East Ohio identified 1,450 miles of pipeline that need to be replaced, in addition to the pipeline originally identified in the PIR project scope. See Note 14 to the Consolidated Financial Statements for additional information.

SOURCES OF ENERGY SUPPLY

Dominion Energy’s 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 large underground natural gas storage network and the location of its pipeline system are a significant link between the country’s major interstate gas pipelines, including the Rockies Express East pipeline, and large markets in the Northeast and mid-Atlantic regions. Dominion’s 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 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.

SEASONALITY

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. Commodity prices can be impacted by seasonal weather changes, the effects of unusual weather events on operations and the economy. Dominion’s producer services business is affected by seasonal changes in the prices of commodities that it transports, stores and actively markets and trades.

Corporate and Other

Corporate and Other Segment—Virginia Power

Virginia Power’s Corporate and Other segment primarily includes certain 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.

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 the operations and sale of Peoples, which is

 

 

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discussed in Note 4 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

Dominion and Virginia Power 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 five major elements:

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Compliance with applicable environmental laws, regulations and rules;

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Conservation and load management;

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Renewable generation development;

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Other generation development to maintain fuel diversity, including clean coal, advanced nuclear energy, and natural gas; and

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Improvements in other energy infrastructure.

This strategy incorporates Dominion’s and Virginia Power’s efforts to voluntarily reduce GHG emissions, which are described below. See Dominion Generation—Properties for more information on certain of the projects described below, as well as other projects under current development.

Environmental Compliance

Dominion and Virginia Power remain committed to compliance with all applicable environmental laws, regulations and rules related to their operations. Additional information related to Dominion’s and Virginia Power’s environmental compliance matters can be found in Future Issues and Other Matters in MD&A and in Note 23 to the Consolidated Financial Statements.

Conservation and Load Management

Conservation plays a significant role in meeting the growing demand for electricity. The Regulation Act provides incentives for energy conservation and sets a voluntary goal to reduce electricity consumption by retail customers in 2022 by ten percent of the amount consumed in 2006 through the implementation of conservation programs. Legislation in 2009 added definitions of peak-shaving and energy efficiency programs and allowed for a margin on operating expenses and revenue reductions related to energy efficiency programs.

Virginia Power’s DSM programs provide important incremental steps toward achieving the voluntary ten percent energy conservation goal. The conservation and load management plan includes the following DSM programs, which were approved by the Virginia Commission in March 2010 and were rolled out in May 2010:

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Residential Lighting Program—an instant, in-store discount on the purchase of qualifying compact fluorescent lights;

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Home Energy Improvement—energy audits and improvements for homes of low-income customers;

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Smart Cooling Rewards—incentives for residential customers who voluntarily enroll to allow Virginia Power to cycle their air conditioners and heat pumps during periods of peak demand;

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Commercial Heating, Ventilating and Air Conditioning Upgrade Program—incentives for commercial customers to improve the energy efficiency of their heating and/or cooling units; and

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Commercial Lighting Program—incentives for commercial customers to install energy-efficient lighting.

In September 2011, Virginia Power filed an application for approval of six additional DSM programs and to expand the approved Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs, in addition to requesting annual recovery of DSM program costs. The proposed DSM programs include:

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Commercial Energy Audit Program—an on-site energy audit providing commercial customers with information to evaluate potential energy cost savings options;

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Commercial Duct Testing & Sealing—an incentive for commercial customers to seal duct and air distribution systems to improve system efficiency;

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Commercial Refrigeration Program—an incentive for commercial customers to install more efficient refrigeration technologies;

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Commercial Distributed Generation—a redesigned distributed generation program allowing customers to commit their on-site back-up generators to Virginia Power during periods of peak demand;

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Residential Lighting Phase II—an extension of the initial in-store discount on the purchase of qualifying compact fluorescent lighting as well as light-emitting diode bulbs to phase out and replace conventional incandescent bulbs; and

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Residential Bundle Program—a bundle of four residential programs to be available to residential customers, including a Residential Home Energy Check-up Program, Residential Duct Testing & Sealing Program, Residential Heat Pump Tune-Up Program and Residential Heat Pump Upgrade Program.

In September 2010, Virginia Power filed with the North Carolina Commission an application for approval and its initial request for cost recovery of the five DSM programs initially approved in Virginia, as well as the distributed generation program. In February 2011, the North Carolina Commission approved the five DSM programs approved in Virginia, and Virginia Power subsequently launched the residential lighting program in May 2011 and the remainder of the approved programs in June 2011. In a separate order issued in September of 2011, the North Carolina Commission denied approval of Virginia Power’s proposed distributed generation program.

Virginia Power continues to assess smart grid technologies through a demonstration designed to indicate how these technologies may enhance Virginia Power’s electric distribution system by allowing energy to be delivered more efficiently. The demonstration involves a limited deployment, within Virginia Power’s Virginia service territory, of smart meters that use digital technology to enable two-way communication between the meter and Virginia Power’s electric distribution system. Dependent upon the outcome of the demonstration and certain regulatory proceedings, Virginia Power may make a significant investment in replacing existing meters with Advanced Metering Infrastructure. The technology is intended to help customers monitor and control their

 

 

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energy use. It is also expected to lead to more efficient use of the power grid, which is expected to result in energy savings and lower environmental emissions. Moreover, deployment of smart grid technology is expected to provide more accurate outage information, fewer service calls, and faster service restoration.

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% renewable power by 2022 and 15% by 2025, and North Carolina’s RPS of 12.5% by 2021. In May 2010, the Virginia Commission approved Virginia Power’s participation in the state’s RPS program. As a participant, Virginia Power is permitted to seek recovery, through rate adjustment clauses, of the costs of programs designed to meet RPS goals. Virginia Power plans to meet the respective RPS targets in Virginia and North Carolina by utilizing existing renewable facilities, as well as through additional renewable generation where it makes sense for customers. In addition, Virginia Power intends to purchase renewable energy certificates, as permitted by each RPS program, to meet any remaining annual requirement needs. Virginia Power continues to explore opportunities to develop new renewable facilities within its service territory, the energy attributes of which would qualify for inclusion in the RPS programs.

Dominion has invested in wind energy through two joint ventures. Dominion is a 50% owner of NedPower. Dominion’s share of this project produces 132 MW of renewable energy. Dominion is also a 50% owner with BP of the first phase of Fowler Ridge, which has a generating capacity of 300 MW. Dominion has a long-term agreement with Fowler Ridge to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In the first quarter of 2011, Dominion completed the sale of its remaining share of the development assets of the second phase of Fowler Ridge to BP.

In October 2011, Virginia Power filed with the Virginia Commission an application to conduct a solar distributed generation demonstration program, consisting of up to a combined 30 MW of company-owned solar distributed generation facilities to be located at selected commercial, industrial and community locations throughout its Virginia service territory, as well as up to a combined 3 MW of customer-owned solar distributed generation facilities that will be subject to a tariff filed with the Virginia Commission in 2012. If approved, this program is expected to generate enough electricity to power about 6,000 homes during peak daylight hours.

Other Generation Development

Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the anticipated growth in demand in its core market of Virginia. Virginia Power expects that these investments collectively will provide the following benefits: expanded electricity production capability, increased technological and fuel diversity and a reduction in the CO2 emission intensity of its generation fleet.

Improvements in Other Energy Infrastructure

Virginia Power’s five-year investment plan includes significant capital expenditures 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. 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.

Virginia Power is taking measures to ensure that its electrical infrastructure can support the expected demand from electric vehicles, which have significantly lower carbon intensity than conventional vehicles. Virginia Power has partnered with Ford Motor Company to help prepare Virginia for the operation of electric vehicles, in a collaboration that involves consumer outreach, educational programs and the exchange of information on vehicle charging requirements.

Dominion, in connection with its five-year growth plan, is also pursuing the construction or upgrade of regulated infrastructure in its natural gas business.

Dominion and Virginia Power’s Strategy for Voluntarily Reducing GHG Emissions

While Dominion and Virginia Power have not established a standalone GHG emissions reduction target or timetable, they are actively engaged in voluntary reduction efforts, as well as working toward achieving required RPS standards established by existing state regulations, as set forth above. The Companies have an integrated voluntary strategy for reducing overall GHG emission intensity that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, oil, hydro and renewable energy, investing in renewable energy projects and promoting energy conservation and efficiency efforts. Below are some of the Companies’ efforts that have or are expected to reduce the Companies’ overall carbon emissions or intensity:

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In 2003, Virginia Power retired two oil-fired units at its Possum Point power station, replacing them with a new 559 MW combined-cycle natural gas unit. Virginia Power also converted two coal-fired units at Possum Point to cleaner burning natural gas.

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Since 2000, Dominion has added over 2,600 MW of non-emitting nuclear generation and over 3,500 MW of new lower-emitting natural gas-fired generation including nearly 1,600 MW at Virginia Power (excluding Possum Point), to its generation mix.

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Virginia Power added 83 MW of renewable biomass and has plans to convert three coal-fired power stations to biomass, which is anticipated to be considered carbon neutral by regulatory agencies.

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Dominion has over 800 MW of wind energy in operation or development.

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Virginia Power completed construction of the natural gas-fired Bear Garden generating facility in May 2011.

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Virginia Power is constructing the natural gas-fired Warren County power station. In connection with the air permit process for Warren County, Virginia Power reached an

 

 

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agreement with the National Park Service to permanently retire the North Branch power station, a 74 MW coal fired plant located in West Virginia, once Warren County begins commercial operations.

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Virginia Power plans to construct an additional combined-cycle natural gas-fired power station similar in size to Warren County to replace coal-fired units at Chesapeake and Yorktown that are anticipated to be retired in 2015 and 2016.

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Virginia Power has received an Early Site Permit from the NRC for the possible addition of approximately 1,500 MW of nuclear generation in Virginia. Virginia Power has not yet committed to building a new nuclear unit.

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Virginia Power has developed the DSM programs described above.

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Virginia Power has initiated a demonstration of smart grid technologies as described above.

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In October 2011, Virginia Power announced plans to develop the community solar power program described above.

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Dominion retired two coal-fired units at Salem Harbor in 2011 and announced that the remaining units at Salem Harbor will be retired during the second quarter of 2014.

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Dominion has announced its plans to retire State Line during the first quarter of 2012.

While Virginia Power’s new Virginia City Hybrid Energy Center, which is currently under construction in southwest Virginia, will be a new source of GHG emissions upon entering service, Virginia Power has taken steps to minimize the impact on the environment. The new plant is expected to use at least 10% biomass for fuel and is designed to be carbon-capture compatible, meaning that technology to capture CO2 can be added to the station if or when it becomes commercially available. Also, Virginia Power has announced plans to convert its coal units at Bremo to natural gas, contingent upon the Virginia City Hybrid Energy Center entering service and receipt of necessary approvals. It is currently estimated that the Virginia City Hybrid Energy Center will have the potential to emit about 4.8 million metric tonnes of direct CO2 emissions in a year assuming a 100% capacity factor and 100% coal-fired operation. Actual emissions will depend on the capacity factor of the facility and the extent to which biomass is burned.

Dominion also developed a comprehensive GHG inventory for calendar year 2010. For Dominion Generation, Dominion’s and Virginia Power’s direct CO2 equivalent emissions, based on equity share (ownership), were approximately 52.4 million metric tonnes and 32.4 million metric tonnes, respectively. For the DVP operating segment’s electric transmission and distribution operations, direct CO2 equivalent emissions were approximately 0.2 million metric tonnes. DTI’s (including Cove Point) direct CO2 equivalent emissions were approximately 3.0 million metric tonnes and East Ohio’s direct CO2 equivalent emissions were approximately 1.4 million metric tonnes. While the Companies do not have final 2011 emissions data, they do not expect a significant variance in emissions from 2010 amounts. With respect to electric generation, primary facility stack emissions of CO2 from carbon based fuel combustion are directly measured via continuous emissions monitor system methods set forth under 40 CFR Part 75 of the U.S. Electric Code of Federal Regulation. For those emission sources not covered under 40 CFR Part 75, and

for methane and nitrous oxide emissions, quantification is based on fuel combustion, higher heating values, emission factors, and global warming potentials as specified in the EPA’s Mandatory Reporting of Greenhouse Gases Rule. For the DVP operating segment’s electric transmission and distribution emissions, the protocol used was The Climate Registry. For Dominion’s natural gas businesses, combustion related emissions were calculated using the EPA Mandatory Reporting of Greenhouse Gases Rule as described above. For DTI, the protocol used to calculate the non-combustion related emissions reported above was Greenhouse Gas Emission Estimation Guidelines for Natural Gas Transmission and Storage, Volume 1-GHG Estimation Methodologies and Procedures-Revision 2, September 28, 2005 developed by the Interstate Natural Gas Association of America. For East Ohio, the protocol used to calculate the non-combustion related emissions was the American Gas Association’s April 2008 Greenhouse Emissions Estimation Methodologies and Procedures for Natural Gas Distribution Operations.

Since 2000, the Companies have tracked the emissions of their electric generation fleet. Their electric generation fleet employs a mix of fuel and renewable energy sources. Comparing annual year 2000 to annual year 2010, Dominion and Virginia Power’s electric generating fleet (based on ownership percentage) reduced their average CO2 emissions rate per MWh of energy produced from electric generation by about 21% and 10%, respectively. During such time period the capacity of Dominion and Virginia Power’s electric generation fleet has grown.

Alternative Energy Initiatives

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 base 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. For example, in March 2011, AES initiated a Dominion scoping study for a high-voltage underwater transmission line from Virginia Beach into the ocean to support multiple offshore wind farms; the first of many steps with the goal being the development of a transmission line making offshore wind resources available to its customers. A 2010 Dominion study of its existing transmission system in eastern Virginia showed that it is possible to interconnect large scale wind facilities up to an installed capability of 4,500 MW.

 

 

REGULATION

Dominion and Virginia Power are subject to regulation by the Virginia Commission, North Carolina Commission, SEC, FERC, EPA, DOE, NRC, Army Corps of Engineers and other federal, state and local authorities.

State Regulations

ELECTRIC

Virginia Power’s electric utility retail service is subject to regulation by the Virginia Commission and the North Carolina Commission.

 

 

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Virginia Power holds certificates of public convenience and necessity 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.

Electric Regulation in Virginia

The enactment of the Regulation Act in 2007 significantly changed electric service regulation in Virginia by instituting a modified cost-of-service rate model. With respect to most classes of customers, the Regulation Act ended Virginia’s planned transition to retail competition for its electric supply service. Base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. The Virginia Commission reviews 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. If, as a result of the earnings test review, the Virginia Commission determines that Virginia Power’s historic earnings for the two-year test period are more than 50 basis points above the authorized level, between 60% and 100% of earnings above this level must be shared with customers through a refund process. 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 a determination by the Virginia Commission that Virginia Power has exceeded its authorized level of earnings by more than 50 basis points 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. Virginia Power’s ROE may be increased or decreased by up to 100 basis points based on operating performance criteria, or alternatively, will be increased by 50 basis points for compliance with Virginia’s RPS.

In addition, the Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation facilities or major unit modifications of existing facilities, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It provides for enhanced returns on capital expenditures relating to the construction or major modification of facilities that are nuclear-powered, clean coal/carbon capture compatible-powered, or renewable-powered, as well as conventional coal and combined-cycle combustion turbine facilities. Costs of fuel used for the generation of electricity, along with costs of purchased power, are recovered from customers through an annually approved fuel rider, as provided under a separate section of the Virginia Code. Decisions of the Virginia Commission may be appealed to the Supreme Court of Virginia.

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

2009 BASE RATE REVIEW

Pursuant to the Regulation Act, the Virginia Commission initiated a review of Virginia Power’s base rates, terms and conditions in 2009, including a review of Virginia Power’s earnings for test year 2008. In March 2010, the Virginia Commission issued the Virginia Settlement Approval Order, thus concluding the 2009 case and resolving open issues relating to Virginia Power’s base rates, fuel factor and Riders R, S, T, C1 and C2.

2011 BIENNIAL REVIEW

Pursuant to the Regulation Act and the Virginia Settlement Approval Order, in March 2011, Virginia Power submitted its base rate filing and accompanying schedules in support of the first biennial review of its base rates, terms and conditions, as well as of its earnings for the 2009 and 2010 test period. In November 2011, the Virginia Commission issued the Biennial Review Order.

In the 2011 Biennial Review Order, the Virginia Commission determined that Virginia Power earned an ROE of approximately 13.3% during the 2009 and 2010 combined test years, which exceeded the authorized ROE earnings band of 11.4% to 12.4% established in the Virginia Settlement Approval Order, resulting in an order that Virginia Power refund 60% of earnings above the upper end of the authorized ROE earnings band, or approximately $78 million, to its customers. The actual refund amount is expected to total approximately $81 million, taking into account refunds to be paid to certain non-jurisdictional customers pursuant to their customer contracts. The Virginia Commission also determined that Virginia Power’s new authorized ROE is 10.9%, inclusive of a performance incentive of 50 basis points for meeting RPS targets. Subject to the outcome of Virginia Power’s petition for rehearing or reconsideration described below, this ROE will serve as the ROE against which Virginia Power’s earned return will be compared for all or part of the test periods in the 2013 biennial review proceeding.

With respect to Virginia Power’s rate adjustment clauses, the Virginia Commission determined that, effective December 1, 2011, the ROE applicable to Riders C1 and C2 is 10.4% and the ROE applicable to Riders R and S is 11.4%, inclusive of a statutory enhancement of 100 basis points. The Virginia Commission also found that, as a result of its determination that credits will be applied to customers’ bills, the Regulation Act requires the combination of its existing Riders T, C1, and C2 with Virginia Power’s base costs, revenues and investments, and these Riders will thereafter be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings. Accordingly, the Virginia Commission directed that Virginia Power’s tariff filings pursuant to the Biennial Review Order reflect such combination. The Virginia Commission has initiated a proceeding to address further implementation of this directive. As a result of the Virginia Settlement Approval Order and the Regulation Act, Virginia Power’s base rates will otherwise remain unchanged through at least December 1, 2013.

In December 2011, Virginia Power filed a petition with the Virginia Commission seeking rehearing or reconsideration of the Biennial Review Order, to clarify whether the effective date of the

 

 

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newly authorized base ROE is prospective from the date the Virginia Commission issued the Biennial Review Order or retrospective to January 1, 2011. Also, in December 2011, Virginia Power filed with the Virginia Commission a Notice of Appeal of the Biennial Review Order to the Supreme Court of Virginia.

See Note 14 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 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 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 intends to file an application with the North Carolina Commission by March 30, 2012, to increase its base rates. See Note 14 to the Consolidated Financial Statements for additional information.

GAS

Dominion’s gas distribution services are regulated by the Ohio Commission and the West Virginia Commission.

Status of Competitive Retail Gas Services

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

Ohio—Ohio has not enacted legislation requiring supplier choice for residential or commercial natural gas consumers. However, in cooperation with the Ohio Commission, Dominion offers retail choice to residential and commercial customers. At December 31, 2011, approximately 1.0 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice program. In October 2006, East Ohio implemented a program approved by the Ohio Commission as a transitional step towards the improvement and expansion of the Energy Choice program, under which East Ohio entered into gas purchase contracts with selected suppliers at a fixed price above the NYMEX month-end settlement. This Standard Service Offer pricing mechanism replaced the traditional gas cost recovery rate with a monthly market price that eliminated the true-up adjustment, making it easier for customers to compare and switch to competitive suppliers if they so choose.

In June 2008, the Ohio Commission approved a settlement filed in response to East Ohio’s application seeking approval of Phase 2 of its plan to restructure its commodity service. Under that settlement, the existing Standard Service Offer program was continued through March 2009 with an update to the fixed rate adder to the NYMEX price. Starting in April 2009, East Ohio buys natural gas under the Standard Service Offer program 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. Subject to the Ohio Commission’s approval, East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. East Ohio continues to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.

West Virginia—At this time, West Virginia has not enacted legislation to require 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.

Rates

Dominion’s gas distribution subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate - Ohio and West Virginia. When necessary, Dominion’s gas distribution subsidiaries seek 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. Base rates for Hope are designed primarily based on a rate design methodology in which the majority of operating costs are recovered through volumetric charges. In addition to general rate increases, Dominion’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions 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 prospective one-, three- or twelve-month periods. 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. 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 14 to the Consolidated Financial Statements for additional information.

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

 

 

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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.

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 is evaluating its transmission facilities for any discrepancies between design and actual field conditions. In addition, NERC has requested the industry to increase the number of assets subject to NERC reliability standards that are designated as critical assets, 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 Dominion’s interstate natural gas company subsidiaries, including DTI, Cove Point and the Dominion South Pipeline Company, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

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

Dominion 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 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.

See Future Issues and Other Matters in MD&A and Note 14 to the Consolidated Financial Statements for additional information.

Environmental Regulations

Each of Dominion’s and Virginia Power’s 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 jurisdictions) or market prices (in deregulated jurisdictions), those costs could adversely affect future results of operations and cash flows. Dominion and Virginia Power 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 MD&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 23 to the Consolidated Financial Statements.

GLOBAL CLIMATE CHANGE

The national and international attention in recent years on GHG emissions and their relationship to climate change has resulted in federal, regional and state legislative or regulatory action in this

 

 

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area. Dominion and Virginia Power 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 MD&A and Note 23 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 Powers’ nuclear power stations, which are part of the Dominion Generation segment, 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 Nuclear Matters in Future Issues and Other Matters in MD&A 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 the Companies are required by the NRC to be financially prepared. For information on decommissioning trusts, see Dominion Generation-Nuclear Decommissioning and Note 10 to the Consolidated Financial Statements. See Note 23 to the Consolidated Financial Statements for information on spent nuclear fuel.

 

 

Item 1A. Risk Factors

Dominion’s and Virginia Power’s 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.

Dominion’s and Virginia Power’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas, and affect the price of energy commodities. In addition, severe weather, including hurricanes and winter storms, can be destructive, causing outages and property damage that require incurring additional expenses. Droughts can result in reduced water levels 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.

Dominion and Virginia Power are subject to complex governmental regulation that could adversely affect their results of operations. Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. 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. However, new laws or regulations, the revision or reinterpretation of existing laws or regulations, or penalties imposed for non-compliance with existing laws or regulations may result in substantial expense.

Dominion and Virginia Power could be subject to penalties as a result of mandatory reliability standards. As a result of EPACT, owners and operators of generation facilities and bulk electric transmission systems, including Dominion and Virginia Power, are subject to mandatory reliability standards enacted by NERC and enforced by FERC. Compliance with the mandatory reliability standards may subject the Companies to higher operating costs and may result in increased capital expenditures. If either Dominion or Virginia Power is found not to be in compliance with the mandatory reliability standards it could be subject to remediation costs, as well as sanctions, including substantial monetary penalties.

Dominion’s and Virginia Power’s costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws, including laws and regulations designed to address global climate change, air quality, coal combustion by-products, cooling water and other matters could make certain of the Companies’ generation facilities uneconomical to maintain or operate. Dominion’s and Virginia Power’s 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 pollution 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 Dominion and Virginia Power expect that they will remain significant in the future.

Existing environmental laws and regulations may be revised and/or new laws may be adopted or become applicable to Dominion or Virginia Power. The EPA is expected to issue additional regulations with respect to air quality under the CAA, including revised NAAQS and regulations governing the emissions of GHGs from electric generating units. Risks relating to potential regulation of GHG emissions are discussed below. Dominion and

 

 

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Virginia Power also expect additional federal water and waste regulations, including regulations concerning cooling water intake structures and coal combustion by-product handling and disposal practices that are expected to be applicable to at least some of its generating facilities.

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’ 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.

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 Dominion’s or Virginia Power’s 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 requiring efficiency improvements from fossil fuel-fired electric generating units.

There are also potential impacts on Dominion’s 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. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products. Several regions of the U.S. have moved forward with GHG emission regulations including regions where Dominion has operations. For example, Massachusetts and Rhode Island have implemented regulations requiring reductions in CO2 emissions through RGGI, a cap and trade program covering CO2 emissions from power plants in the Northeast, which affects several of Dominion’s facilities.

Compliance with GHG emission reduction requirements may require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon capture and storage technology, 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 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 capture and storage technology, and the selected compliance alternatives. The Companies 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 the Companies’ 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.

The rates of Virginia Power are subject to regulatory review. In the Biennial Review Order, the Virginia Commission determined that Virginia Power’s actual ROE during the 2009 and 2010 combined test years exceeded the upper end of the authorized ROE earnings band for that period, resulting in an order that Virginia Power refund approximately $78 million to its customers. The Virginia Commission also determined that Virginia Power’s new authorized ROE is 10.9%, inclusive of a performance incentive of 50 basis points for meeting certain renewable energy targets. Subject to the outcome of the petition for rehearing or reconsideration described below, this ROE will serve as the ROE against which Virginia Power’s earned return will be compared for all or part of the test periods in the 2013 biennial review proceeding. In December 2011, Virginia Power filed a petition with the Virginia Commission seeking a rehearing or reconsideration of the Biennial Review Order to clarify whether the effective date of the newly authorized ROE is the date the Virginia Commission issued the 2011 Biennial Review Order or January 1, 2011. If the Virginia Commission orders that the effective date of the newly authorized ROE is January 1, 2011, such effective date may adversely affect the outcome of the earnings test in the 2013 biennial review. In addition, Virginia Power’s base rates are subject to reduction if the Virginia Commission concludes, in the 2013 biennial review, that Virginia Power’s actual ROE during the test period exceeded the upper end of the authorized ROE earnings band for that period, under circumstances described in the Regulation Act. The Virginia Commission could also order Virginia Power to refund to customers 60% of any such excess earnings for the 2011-2012 earnings test period. The Virginia Commission may alternatively order Virginia Power to refund up to 100% of earnings that exceed the earnings band in a biennial review if it finds that Virginia Power’s total aggregate regulated rates have exceeded annual increases in the U.S. Consumer Price Index, as described in the Regulation Act.

In the 2011 Biennial Review Order, as a result of the Virginia Commission’s determination that credits will be applied to customers’ bills, the Virginia Commission, as required by the Regulation Act, directed Virginia Power to combine its existing Riders T, C1, and C2 with Virginia Power’s base costs, revenues and investments, and to file revised tariffs reflecting such combination. These existing Riders will thereafter be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings. The Virginia Commission has initiated a proceeding to address how this combination will be implemented. Depending on how the Virginia Commission orders the combination of existing Riders T, C1 and C2 to be effected, Virginia Power may be required to discontinue deferral accounting and could potentially not receive full recovery of costs associated with these existing riders. At this time, Virginia Power is not able to estimate the impact, if any, of the outcome of these proceedings.

The rates of Virginia Power’s electric transmission operations and Dominion’s gas transmission and distribution operations are subject to regulatory review. Revenue provided by Virginia Power’s electric

 

 

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transmission operations and Dominion’s gas transmission and distribution operations is based primarily on rates approved by federal and state 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 charges 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 as appropriate to reflect actual costs allocated to Virginia Power by PJM. 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 gas transmission businesses are subject to review by FERC. In addition, Dominion’s gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate.

Risks arising from the reliability of electric generation, transmission and distribution equipment, supply chain disruptions or personnel issues could result in lost revenues and increased expenses, including higher maintenance costs. Operation of the Companies’ generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages 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. In addition, weather-related incidents, earthquakes and other natural disasters can disrupt generation, transmission and distribution facilities. Because Virginia Power’s transmission facilities are interconnected with those of third parties, the operation of its facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

Operation of the Companies’ generation facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of generating units 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 energy or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement energy and capacity from third parties in the open market to satisfy forward energy and capacity obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.

Dominion’s merchant power business is operating 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

purchase and 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 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. 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.

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 in PJM, MISO and ISO-NE depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize PJM, MISO and ISO-NE 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, 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.

War, acts and threats of terrorism, natural disaster and other significant events could adversely affect Dominion’s and Virginia Power’s operations. Dominion and Virginia Power 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, infrastructure facilities, such as electric generation, electric and gas transmission and distribution facilities could be direct targets of, or indirect casualties of, an act of terror. Furthermore, the physical or cybersecurity compromise of the Companies’ facilities could adversely affect the Companies’ ability to manage these facilities effectively. Instability in financial mar-

 

 

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kets 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.

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 and Virginia Power 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.

The use of derivative instruments could result in financial losses and liquidity constraints. Dominion and Virginia Power use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity and financial market risks. In addition, Dominion purchases and sells commodity-based contracts primarily in the natural gas market for trading purposes. The Companies could recognize financial losses on these contracts, including as a result of volatility in the market values of the underlying commodities, if a counterparty fails to perform under a contract or upon the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these transactions. In the absence of actively-quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the under-

lying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

The use of derivatives to hedge future sales may limit the benefit Dominion would otherwise receive from increases in commodity prices. These hedge arrangements generally include collateral requirements that require Dominion to deposit funds or post letters of credit with counterparties, financial intermediaries or clearinghouses to cover the fair value of covered contracts in excess of agreed upon credit limits. For instance, when commodity prices rise to levels substantially higher than the levels where it has hedged future sales, Dominion may be required to use a material portion of its available liquidity or obtain additional liquidity to cover these collateral requirements. In some circumstances, this could have a compounding effect on Dominion’s financial liquidity and results of operations. In addition, the availability or security of the collateral delivered by Dominion may be adversely affected by the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these types of transactions.

Derivatives designated under hedge accounting, to the extent not fully offset by the hedged transaction, can result in ineffectiveness losses. These losses primarily result from differences between the location and/or specifications of the derivative hedging instrument and the hedged item and could adversely affect Dominion’s results of operations.

Dominion’s and Virginia Power’s operations in regards to these transactions are subject to multiple market risks including market liquidity, price volatility, credit strength of the Companies’ counterparties and the financial condition of the financial intermediaries, exchanges and clearinghouses used for the types of transactions. These market risks are beyond the Companies’ control and could adversely affect their results of operations, liquidity and future growth.

The Dodd-Frank Act, which was enacted into law in July 2010, 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. Final rules for the over-the-counter derivatives-related provisions of the Dodd-Frank Act, including the clearing, exchange trading and capital and margin requirements, will be established through the on-going rulemaking process of each applicable regulator, including the CFTC and SEC. In June 2011, both the CFTC and SEC confirmed that they would not complete the required rulemakings by the July 2011 deadline under the Dodd-Frank Act. Each agency has granted temporary relief from most derivative-related provisions of the Dodd-Frank Act until the effective date of the applicable rules. Currently, the CFTC’s temporary relief would expire no later than July 16, 2012, if not extended. If, as a result of the rulemaking process, Dominion’s or Virginia Power’s derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs for their derivative activities, including from higher margin requirements. In addition, implementation of, and compliance with, the over-the-counter derivatives provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in increased costs related to the Companies’ derivative activities.

Dominion depends on third parties to produce the natural gas it gathers and processes, and the NGLs it fractionates at its facilities. A reduction in these quantities could reduce Dominion’s revenues.

 

 

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Dominion obtains its supply of natural gas and NGLs from numerous third-party producers. Such producers are under no obligation to deliver a specific quantity of natural gas or NGLs to Dominion’s facilities, although the producers that have contracted to supply natural gas to Dominion’s natural gas processing and fractionation facility under development in Natrium, West Virginia will generally be subject to contractual minimum fee payments. If producers were to decrease the supply of natural gas or NGLs to Dominion’s systems and facilities for any reason, Dominion could experience lower revenues to the extent it is unable to replace the lost volumes on similar terms.

Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. Dominion and Virginia Power 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. Such defaults by customers, suppliers or other third parties may adversely affect the Companies’ financial results.

Dominion and Virginia Power may not complete plant construction or expansion 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 plant construction and expansion projects have been announced and additional projects may be considered in the future. 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 their counterparties or vendors, or other factors beyond their control. Even if plant construction and expansion projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of Dominion and Virginia Power following the projects may not meet expectations. Additionally, Dominion and Virginia Power 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 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 plant construction and expansion projects.

Energy conservation could negatively impact Dominion’s and Virginia Power’s financial results. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices, including lighting and electric heat pumps, could lead to declines in per capita energy consumption. To the extent conservation results in reduced energy demand or significantly slowed growth in demand, the value of the Companies’ business activities could be adversely impacted.

An inability to access financial markets could adversely affect the execution of Dominion’s and Virginia Power’s business plans. Dominion and Virginia Power rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for capital expenditures, 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 Dominion’s and Virginia Power’s 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.

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

Changing rating agency requirements could negatively affect Dominion’s and Virginia Power’s 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, Dominion and Virginia Power 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 Dominion’s credit ratings or the credit ratings of Virginia Power could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require Dominion to post additional collateral in connection with some of its price risk management activities.

Potential changes in accounting practices may adversely affect Dominion’s and Virginia Power’s financial results. Dominion and Virginia Power cannot predict the impact that future changes in accounting standards or practices may have on public companies

 

 

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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 reported earnings or could increase reported liabilities.

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on Dominion’s and Virginia Power’s operations. Dominion’s and Virginia Power’s business strategy is dependent on their ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect their business and future operating results.

Hostile cyber intrusions could severely impair Dominion’s and Virginia Power’s operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on Dominion’s and Virginia Power’s 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. Parties that wish to disrupt the U.S. bulk power system or the Companies’ operations could view the Companies’ computer systems, software or networks as attractive targets for cyber attack. In addition, the Companies’ business requires that they collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

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 cybersecurity 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.

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, Dominion and Virginia Power are subject to mandatory cybersecurity regulatory requirements. However, cyber threats continue to evolve and adapt, and, as a result, there is a risk that the Companies could experience a successful cyber attack despite their current security posture and regulatory compliance efforts.

 

 

Item 1B. Unresolved Staff Comments

None.

 

 

Item 2. Properties

As of December 31, 2011, 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 shares its 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, 2011; however, by leaving the indenture open, Virginia Power retains the flexibility to issue mortgage bonds in the future. Certain of Dominion’s merchant generation facilities are also subject to liens.

 

 

POWER GENERATION

Dominion and Virginia Power generate electricity for sale on a wholesale and a retail level. The Companies supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2011, Dominion Generation’s total utility and merchant generating capacity was 28,142 MW.

 

 

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The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2011:

VIRGINIA POWER UTILITY GENERATION

 

Plant    Location    Net Summer
Capability (MW)
    Percentage
Net Summer
Capability
 

Coal

       

Mt. Storm

   Mt. Storm, WV      1,591     

Chesterfield

   Chester, VA      1,240     

Chesapeake(1)

   Chesapeake, VA      595     

Clover

   Clover, VA      433 (5)   

Yorktown(1)

   Yorktown, VA      323     

Bremo(2)

   Bremo Bluff, VA      227     

Mecklenburg

   Clarksville, VA      138     

North Branch(3)

   Bayard, WV      74     

Altavista(3),(4)

   Altavista, VA      63     

Hopewell(4)

   Hopewell, VA      63     

Southampton(4)

   Southampton, VA      63           

Total Coal

        4,810        25

Gas

       

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     

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

        4,589        24   

Nuclear

       

Surry

   Surry, VA      1,678     

North Anna

   Mineral, VA      1,647 (6)         

Total Nuclear

        3,325        18   

Oil

       

Yorktown

   Yorktown, VA      818     

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

        2,188        12   

Hydro

       

Bath County

   Warm Springs, VA      1,802 (7)   

Gaston

   Roanoke Rapids, NC      220     

Roanoke Rapids

   Roanoke Rapids, NC      95     

Other

   Various      3           

Total Hydro

        2,120        11   

Biomass

       

Pittsylvania

   Hurt, VA      83          

Various

       

Other

   Various      11          
            17,126           

Power Purchase Agreements

          1,859        10   

Total Utility Generation

          18,985        100

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

(1) Certain coal-fired units are expected to be retired at Chesapeake and Yorktown during 2015 and 2016 as a result of the issuance of the MATS rule.
(2) Planned to convert to gas subject to Virginia City Hybrid Energy Center entering service and necessary approvals.
(3) Facility has been placed into cold reserve status, but can be restarted within a reasonably short period if necessary. North Branch will be permanently retired upon commencement of commercial operations at Warren County.

 

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(4) Seeking regulatory approval to convert to biomass.
(5) Excludes 50% undivided interest owned by ODEC.
(6) Excludes 11.6% undivided interest owned by ODEC.
(7) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.

DOMINION MERCHANT GENERATION

 

Plant    Location    Net Summer
Capability (MW)
    Percentage
Net Summer
Capability
 

Coal

       

Kincaid(1)

   Kincaid, IL      1,158     

Brayton Point

   Somerset, MA      1,103     

State Line(2)

   Hammond, IN      515     

Salem Harbor(3)

   Salem, MA      314           

Total Coal

        3,090        34

Nuclear

       

Millstone

   Waterford, CT      2,016 (6)   

Kewaunee(4)

   Kewaunee, WI      556           

Total Nuclear

        2,572        28   

Gas

       

Fairless (CC)(1)(5)

   Fairless Hills, PA      1,196      

Elwood (CT)(1)

   Elwood, IL      712 (7)   

Manchester (CC)

   Providence, RI      432           

Total Gas

        2,340        26   

Oil

       

Salem Harbor(3)

   Salem, MA      440     

Brayton Point

   Somerset, MA      425           

Total Oil

        865        9   

Wind

       

Fowler Ridge(1)

   Benton County, IN      150 (8)   

NedPower Mt. Storm(1)

   Grant County, WV      132 (9)         

Total Wind

        282        3   

Various

       

Other

   Various      8          
       

Total Merchant Generation

          9,157        100

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

(1) Subject to a lien securing the facility’s debt. Also see Note 18 to the Consolidated Financial Statements for additional information on liens related to Kincaid and Fairless.
(2) State Line will be retired in the first quarter of 2012.
(3) Two coal-fired units at Salem Harbor with capacity of 163 MW were retired at the end of 2011 and the Company plans to retire the remaining units on June 1, 2014.
(4) In the first quarter of 2011, Dominion decided to pursue the sale of Kewaunee.
(5) Includes generating units that Dominion operates under leasing arrangements.
(6) Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation.
(7) Excludes 50% membership interest owned by J. POWER Elwood, LLC.
(8) Excludes 50% membership interest owned by BP.
(9) Excludes 50% membership interest owned by Shell.

 

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Item 3. Legal Proceedings

From time to time, Dominion and Virginia Power 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 February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, New Source Performance Standards, and Title V permit program and the stations’ respective State Implementation Plans. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the CAA.

Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The CAA authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. In addition to any such penalties that may be awarded, an adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time. Such expenditures could affect future results of operations, cash flows, and financial condition. Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.

See Notes 14 and 23 to the Consolidated Financial Statements and Future Issues and Other Matters in 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 (57)

   Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date; Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; Chairman of the Board of Directors, President and CEO of CNG from January 2006 to June 2007; Director of Dominion from March 2005 to April 2007.

Mark F. McGettrick (54)

   Executive Vice President and CFO of Dominion and Virginia Power from June 2009 to date; Executive Vice President of Dominion from April 2006 to May 2009; President and COO-Generation of Virginia Power from February 2006 to May 2009.

Paul D. Koonce (52)

   Executive Vice President of Dominion from April 2006 to date; President and COO of Virginia Power from June 2009 to date; President and COO-Energy of Virginia Power from February 2006 to September 2007.

David A. Christian (57)

   Executive Vice President of Dominion from May 2011 to date; President and COO of Virginia Power from June 2009 to date; President and CNO of Virginia Power from October 2007 to May 2009; Senior Vice President-Nuclear Operations and CNO of Virginia Power from April 2000 to September 2007.

David A. Heacock (54)

   President and CNO of Virginia Power from June 2009 to date; Senior Vice President of Dominion and President and COO-DVP of Virginia Power from June 2008 to May 2009; Senior Vice President-DVP of Virginia Power from October 2007 to May 2008; Senior Vice President-Fossil & Hydro of Virginia Power from April 2005 to September 2007.

Gary L. Sypolt (58)

   Executive Vice President of Dominion from May 2011 to date; President of DTI from June 2009 to date; President-Transmission of DTI from January 2003 to May 2009; President and COO-Transmission of Virginia Power from February 2006 to September 2007.

Robert M. Blue (44)

   Senior Vice President-Law, Public Policy and Environment of Dominion, Virginia Power and DRS from January 2011 to date; Senior Vice President-Public Policy and Environment of Dominion and DRS from February 2010 to December 2010; Senior Vice President-Public Policy and Corporate Communications of Dominion and DRS from May 2008 to January 2010; Vice President-State and Federal Affairs of DRS from September 2006 to May 2008.

Steven A. Rogers (50)

   Senior Vice President and Chief Administrative Officer of Dominion and President and Chief Administrative Officer of DRS from October 2007 to date; Senior Vice President and CAO of Dominion and Virginia Power from January 2007 to September 2007 and CNG from January 2007 to June 2007.

Ashwini Sawhney (62)

   Vice President-Accounting and Controller (CAO) of Dominion from May 2010 to date; Vice President and Controller (CAO) of Dominion from July 2009 to May 2010; Vice President-Accounting of Virginia Power from April 2006 to date; Vice President and Controller of Dominion from April 2007 to June 2009; Vice President-Accounting and Controller of Dominion from January 2007 to April 2007 and of CNG from January 2007 to June 2007.

 

(1) Any service listed for Virginia Power, CNG, DTI, DEI 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, 2012, there were approximately 142,000 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 18 and 21 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 2011 and 2010. Quarterly information concerning stock prices and dividends is disclosed in Note 27 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 2011.

 

 

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)

 

10/1/2011-10/31/11

     1,284       $ 50.77         N/A       19,629,059 shares/$ 1.18 billion   

11/1/2011-11/30/11

     361       $ 51.59         N/A       19,629,059 shares/$ 1.18 billion   

12/1/2011-12/31/11

     294       $ 51.62         N/A       19,629,059 shares/$ 1.18 billion   

Total

     1,939       $ 51.05         N/A       19,629,059 shares/$ 1.18 billion   

 

(1) In October, November and December 2011, 1,284 shares, 361 shares and 294 shares, respectively, were tendered by employees to satisfy tax withholding obligations on vested restricted stock.
(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 Dividend Restrictions in Item 7. MD&A and Note 21 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)                                   

2011

   $ 131       $ 118       $ 199       $ 109       $ 557   

2010

     108         81         171         140         500   

 

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Item 6. Selected Financial Data

DOMINION

 

Year Ended December 31,    2011      2010     2009      2008      2007  
(millions, except per share amounts)                                  

Operating revenue

   $ 14,379       $ 15,197      $ 14,798       $ 15,895       $ 14,456   

Income from continuing operations before extraordinary item(1)

     1,408         2,963        1,261         1,644         2,661   

Income (loss) from discontinued operations, net of tax(1)

             (155     26         190         36   

Extraordinary item, net of tax(1)

                                    (158

Net income attributable to Dominion

     1,408         2,808        1,287         1,834         2,539   

Income from continuing operations before extraordinary item per common share-basic

     2.46         5.03        2.13         2.84         4.09   

Net income attributable to Dominion per common share-basic

     2.46         4.77        2.17         3.17         3.90   

Income from continuing operations before extraordinary item per common share-diluted

     2.45         5.02        2.13         2.83         4.06   

Net income attributable to Dominion per common share-diluted

     2.45         4.76        2.17         3.16         3.88   

Dividends paid per common share

     1.97         1.83        1.75         1.58         1.46   

Total assets

     45,614         42,817        42,554         42,053         39,139   

Long-term debt

     17,394         15,758        15,481         14,956         13,235   

 

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

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 $206 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, as discussed in Notes 4 and 23 to the Consolidated Financial Statements, respectively. Also in 2010, Dominion recorded $127 million of after-tax impairment charges at certain merchant generation facilities, as discussed in Note 7 to the Consolidated Financial Statements. The loss from discontinued operations in 2010 includes a $140 million after-tax loss on the sale of Peoples.

2009 results include a $435 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings discussed in Note 14 to the Consolidated Financial Statements. Also in 2009, Dominion recorded a $281 million after-tax ceiling test impairment charge related to the carrying value of its Appalachian E&P properties.

2008 results include $109 million of after-tax charges reflecting other-than-temporary declines in the fair value of certain securities held as investments in nuclear decommissioning trusts. In addition, income from discontinued operations in 2008 includes a $120 million after-tax benefit due to the reversal of deferred tax liabilities associated with the sale of Peoples.

2007 results include a $1.5 billion after-tax benefit from the disposition of Dominion’s non-Appalachian E&P operations and a $252 million after-tax impairment charge associated with the sale of Dresden. Also in 2007, Dominion recorded a $137 million after-tax charge resulting from the termination of the long-term power sales agreement associated with State Line. In addition, the reapplication of accounting guidance for cost-based rate regulation to the Virginia jurisdiction of Virginia Power’s generation operations in 2007 resulted in a $158 million after-tax extraordinary charge.

VIRGINIA POWER

 

Year Ended December 31,    2011      2010      2009      2008      2007  
(millions)                                   

Operating revenue

   $ 7,246       $ 7,219       $ 6,584       $ 6,934       $ 6,181   

Income from operations before extraordinary item

     822         852         356         864         606   

Extraordinary item, net of tax

                                     (158

Net income

     822         852         356         864         448   

Balance available for common stock

     805         835         339         847         432   

Total assets

     23,544         22,262         20,118         18,802         17,063   

Long-term debt

     6,246         6,702         6,213         6,000         5,316   

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 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 $123 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, discussed in Note 23 to the Consolidated Financial Statements.

2009 results include a $427 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings discussed in Note 14 to the Consolidated Financial Statements.

2007 results reflect the reapplication of accounting guidance for cost-based rate regulation to the Virginia jurisdiction of Virginia Power’s generation operations, which resulted in a $158 million after-tax extraordinary charge.

 

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

 

 

 

MD&A discusses Dominion’s and Virginia Power’s results of operations and general financial condition. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data.

 

 

CONTENTS OF MD&A

MD&A consists of the following information:

Ÿ  

Forward-Looking Statements

Ÿ  

Accounting Matters

Ÿ  

Dominion

  Ÿ  

Results of Operations

  Ÿ  

Segment Results of Operations

Ÿ  

Virginia Power

  Ÿ  

Results of Operations

  Ÿ  

Segment Results of Operations

Ÿ  

Liquidity and Capital Resources

Ÿ  

Future Issues and Other Matters

 

 

FORWARD-LOOKING STATEMENTS

This report contains statements concerning Dominion’s and Virginia Power’s 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.

Dominion and Virginia Power 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, and earthquakes that can cause outages and property damage to facilities;

Ÿ  

Federal, state and local legislative and regulatory developments;

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  

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 of the Companies’ facilities;

Ÿ  

Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Dominion’s and Virginia Power’s 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  

Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion;

Ÿ  

Fluctuations in interest rates;

Ÿ  

Changes in federal and state tax laws and regulations;

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  

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

Ÿ  

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

Ÿ  

Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, pricing rules and rules involving revenue calculations 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  

Industrial, commercial and residential growth or decline in the Companies’ service areas and changes in customer growth or usage patterns, including as a result of energy conservation programs;

Ÿ  

Additional competition in electric markets in which Dominion’s merchant generation facilities operate;

Ÿ  

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

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  

Timing and receipt of regulatory approvals necessary for planned construction or expansion projects;

Ÿ  

The inability to complete planned construction projects within the terms and time frames initially anticipated; and

Ÿ  

Adverse outcomes in litigation matters.

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

 

 

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

Dominion and Virginia Power have 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 their financial condition or results of operations under different conditions or using different assumptions. Dominion and Virginia Power have discussed the

 

 

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development, selection and disclosure of each of these policies with the Audit Committees of their Boards of Directors. Virginia Power’s Board of Directors also serves as its Audit Committee.

ACCOUNTING FOR REGULATED OPERATIONS

The accounting for Virginia Power’s regulated electric and Dominion’s regulated gas 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 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.

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 or historical experience, as well as discussions with applicable regulatory authorities. 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 13 and 14 to the Consolidated Financial Statements for additional information.

ASSET RETIREMENT OBLIGATIONS

Dominion and Virginia Power recognize 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, the Companies estimate the fair value of their AROs using present value techniques, in which they make 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 the Companies revise any assumptions used to calculate the fair value of existing AROs, they adjust the carrying amount of both the ARO liability and the related long-lived asset. The Companies accrete the ARO liability to reflect the passage of time.

In 2011, 2010 and 2009, Dominion recognized $84 million, $85 million and $89 million, respectively, of accretion, and expects to recognize $75 million in 2012. In 2011, 2010 and 2009, Virginia Power recognized $36 million, $35 million and $35 million, respectively, of accretion, and expects to recognize $35 million in 2012. Virginia Power records accretion and depreciation associated with utility nuclear decommissioning AROs as an adjustment to its regulatory liability for nuclear decommissioning.

A significant portion of the Companies’ AROs relates to the future decommissioning of Dominion’s merchant and Virginia Power’s utility nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2011, Dominion’s nuclear decommissioning AROs totaled $1.2 billion, representing approximately 83% of its total AROs. At December 31, 2011, Virginia Power’s nuclear decommissioning AROs totaled $559 million, representing approximately 89% 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 the Companies’ nuclear decommissioning obligations.

The Companies obtain 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 their 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, the Companies’ cost estimates include cost escalation rates that are applied to the base year costs. The Companies determine 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 a critical assumption.

In December 2011, Dominion recorded a decrease of $290 million in the nuclear decommissioning AROs for its units. Virginia Power recorded a decrease of $95 million in the nuclear decommissioning AROs for its units. The ARO revision was driven by a reduction in anticipated future decommissioning costs due to the expected future recovery from the DOE of certain spent fuel costs based on the Companies’ contracts with the DOE for disposal of spent nuclear fuel, as well as updated escalation rates. In 2009, as a result of updated decommissioning cost studies and applicable escalation rates, Dominion recorded a decrease of $309 million in the nuclear decommissioning AROs of its units, including a $103 million ($62 million after-tax) reduction in other operations and maintenance expense due to a downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service. Virginia Power recorded a decrease of $119 million in the nuclear decommissioning AROs for its units.

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

 

 

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

 

 

 

examined by tax authorities with full knowledge of all relevant information. At December 31, 2011, Dominion had $347 million and Virginia Power had $114 million of unrecognized tax benefits.

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 and Virginia Power evaluate 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. 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. At December 31, 2011, Dominion had established $96 million of valuation allowances and Virginia Power had no valuation allowances.

ACCOUNTING FOR DERIVATIVE CONTRACTS AND OTHER INSTRUMENTS AT FAIR VALUE

Dominion and Virginia Power use derivative contracts such as futures, swaps, forwards, options and FTRs to manage commodity and financial market risks of their 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 and Virginia Power’s nuclear decommissioning and Dominion’s rabbi and benefit plan trust funds are also subject to fair value accounting. See Notes 7 and 22 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 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 information 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 use of statistical methods, including regression analysis, that reflect their market assumptions.

The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

As of December 31, 2011, Dominion reported $3.1 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 2011, 2010 and 2009 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. For Dominion’s Appalachian E&P operations and Peoples and Hope operations, negotiated sales prices were used as fair value for the tests conducted in 2010 and 2009. 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 12 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 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 and the selection of an appropriate discount rate. 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, and expected fluctuations of prices of commodities sold and consumed. See Note 7 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets.

 

 

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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 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 and healthcare cost trend 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  

Forward-looking return expectations derived from the yield on long-term bonds and the price earnings ratios 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 other independent investment advisors 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 8.50% for 2011, 2010 and 2009. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 7.75% for 2011, 2010 and 2009. 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 were 5.9% in 2011 and 6.60% in 2010 and 2009. Dominion selected a discount rate of 5.50% for determining its December 31, 2011 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, 2011 is 7% and is expected to gradually decrease to 4.60% by 2060 and continue at that rate for years thereafter.

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 )%    $ 13       $ 2   

Long-term rate of return on plan assets

     (0.25 )%      13         3   

Healthcare cost trend rate

     1     N/A         20   

In addition to the effects on cost, at December 31, 2011, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $163 million and its accumulated postretirement benefit obligation by $43 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $174 million. See Note 22 to the Consolidated Financial Statements for additional information.

REVENUE RECOGNITION—UNBILLED REVENUE

Virginia Power recognizes and records revenues when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, the amount of electric energy delivered to customers, but not yet billed, is estimated and recorded as unbilled revenue. This estimate is reversed in the following month and actual revenue is recorded based on meter readings. Virginia Power’s customer receivables included $360 million and $397 million of accrued unbilled revenue at December 31, 2011 and 2010, respectively.

The calculation of unbilled revenues is complex and includes numerous estimates and assumptions including historical usage, applicable customer rates, weather factors and total daily electric generation supplied, adjusted for line losses. Changes in generation patterns, customer usage patterns and other factors, which are the basis for the estimates of unbilled revenues, could have a significant effect on the calculation and therefore on Virginia Power’s results of operations and financial condition.

 

 

 

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

 

 

 

Other

ACCOUNTING STANDARDS AND POLICIES

During 2009, Dominion and Virginia Power were required to adopt several new accounting standards, which are discussed in Note 3 to the Consolidated Financial Statements.

DOMINION

 

 

RESULTS OF OPERATIONS

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

 

Year Ended
December 31,
   2011      $ Change     2010      $ Change      2009  
(millions, except EPS)                                  

Net Income attributable to Dominion

   $ 1,408       $ (1,400   $ 2,808       $ 1,521       $ 1,287   

Diluted EPS

     2.45         (2.31     4.76         2.59         2.17   

Overview

2011 VS. 2010

Net income attributable to Dominion decreased by 50%. Unfavorable drivers include the absence of a gain on the sale of Dominion’s Appalachian E&P operations, lower margins from merchant generation operations, and the impact of less favorable weather, including Hurricane Irene, on electric utility operations. Favorable drivers include the absence of charges related to a workforce reduction program and the absence of a loss on the sale of Peoples, and higher earnings from rate adjustment clauses.

2010 VS. 2009

Net income attributable to Dominion increased by 118%. Favorable drivers include a gain on the sale of Dominion’s Appalachian E&P operations, lower ceiling test impairment charges related to these properties, the absence of a charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings and the impact of favorable weather on electric utility operations. Unfavorable drivers include charges related to a workforce reduction program, a loss on the sale of Peoples, lower margins from merchant generation operations and impairment charges related to certain merchant generation facilities.

Analysis of Consolidated Operations

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

 

Year Ended December 31,   2011     $ Change     2010     $ Change     2009  
(millions)                              

Operating Revenue

  $ 14,379      $ (818   $ 15,197      $ 399      $ 14,798   

Electric fuel and other energy-related purchases

    4,194        44        4,150        (135     4,285   

Purchased electric capacity

    454        1        453        42        411   

Purchased gas

    1,764        (286     2,050        (150     2,200   

Net Revenue

    7,967        (577     8,544        642        7,902   

Other operations and maintenance

    3,483        (241     3,724        12        3,712   

Depreciation, depletion and amortization

    1,069        14        1,055        (83     1,138   

Other taxes

    554        22        532        49        483   

Gain on sale of Appalachian E&P operations

           (2,467     2,467        2,467          

Other income

    179        10        169        (25     194   

Interest and related charges

    869        37        832        (57     889   

Income tax expense

    745        (1,312     2,057        1,461        596   

Income (loss) from discontinued operations

           155        (155     (181     26   

An analysis of Dominion’s results of operations follows:

2011 VS. 2010

Net Revenue decreased 7%, primarily reflecting:

Ÿ  

A $519 million decrease from merchant generation operations, primarily due to a decrease in realized prices ($347 million) and lower generation ($163 million); and

Ÿ  

A $125 million decrease reflecting the sale of substantially all of Dominion’s Appalachian E&P operations in April 2010.

These decreases were partially offset by:

Ÿ  

A $32 million increase from Dominion’s gas transmission business primarily related to an increase in revenue from NGLs;

Ÿ  

A $28 million increase in producer services primarily related to higher physical margins and favorable price changes on economic hedging positions, all associated with natural gas aggregation, marketing and trading activities;

Ÿ  

A $13 million increase from electric utility operations, primarily reflecting:

  Ÿ  

The impact of rate adjustment clauses ($169 million); and

  Ÿ  

A decrease in net capacity expenses ($44 million); partially offset by

  Ÿ  

The impact ($120 million) of a decrease in sales to retail customers, primarily due to a decrease in heating and cooling degree days ($220 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($100 million); and

  Ÿ  

A decrease due to a charge based on the Biennial Review Order to refund revenues to customers ($81 million).

 

 

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Other operations and maintenance decreased 6%, primarily reflecting:

Ÿ  

A $441 million decrease in salaries, wages and benefits primarily related to a 2010 workforce reduction program; partially offset by

Ÿ  

A $96 million increase due to restoration costs associated with damage caused by Hurricane Irene; and

Ÿ  

An $89 million net increase in impairment charges related to certain utility and merchant coal-fired generating units.

Gain on sale of Appalachian E&P operations reflects a gain on the sale of these operations, as described in Note 4 to the Consolidated Financial Statements.

Interest and related charges increased 4%, primarily due to the absence of a benefit recorded in 2010 resulting from the discontinuance of hedge accounting for certain interest rate derivatives ($73 million) and an increase in debt issuances in 2011 ($18 million), partially offset by the recognition of hedging gains that had previously been deferred as regulatory liabilities as a result of the Biennial Review Order ($50 million).

Income tax expense decreased $1.3 billion, primarily reflecting lower federal and state taxes largely due to the absence of a gain from the sale of Dominion’s Appalachian E&P operations recorded in 2010.

Loss from discontinued operations reflects the sale of Peoples in 2010.

2010 VS. 2009

Net Revenue increased 8%, primarily reflecting:

Ÿ  

A $1.1 billion increase from electric utility operations, primarily reflecting:

  Ÿ  

The absence of a charge for the settlement of Virginia Power’s 2009 base rate case proceedings ($570 million);

  Ÿ  

The impact of rate adjustment clauses ($279 million);

  Ÿ  

An increase in sales to retail customers primarily due to an increase in cooling degree days ($248 million); and

  Ÿ  

An increase in ancillary revenues received from PJM ($78 million), primarily reflecting an increase in the scheduled dispatch of gas and oil-fired generation units to meet higher demand; partially offset by

  Ÿ  

A decrease primarily due to the impact of unfavorable economic conditions on customer usage and other factors ($75 million);

Ÿ  

A $98 million increase from regulated natural gas distribution operations primarily reflecting increased rider revenue associated with the recovery of bad debt expense ($60 million) and an increase in base rates ($40 million); and

Ÿ  

A $46 million increase related to natural gas transmission operations largely due to the completion of the Cove Point expansion project.

These increases were partially offset by:

Ÿ  

A $356 million decrease from merchant generation operations due to a decrease at certain nuclear generating facilities ($237 million) primarily due to lower realized prices, a decline in margins at certain fossil generation facilities ($70 million) primarily due to an increase in fuel prices and the expiration of certain requirements-based power sales contracts in December 2009 ($49 million);

Ÿ  

A $222 million decrease reflecting the sale of substantially all of Dominion’s Appalachian E&P operations in April 2010; and

Ÿ  

A $40 million decrease in producer services primarily related to unfavorable price changes on economic hedging positions and lower physical margins, all associated with natural gas aggregation, marketing and trading activities.

Other operations and maintenance increased $12 million primarily reflecting:

Ÿ  

A $240 million net increase in salaries, wages and benefits primarily related to a workforce reduction program;

Ÿ  

Impairment charges related to certain merchant generating facilities ($194 million);

Ÿ  

A $103 million increase due to the absence of a benefit in 2009 from a downward revision in the nuclear decommissioning ARO for a unit that is no longer in service;

Ÿ  

A $56 million increase in bad debt expense at regulated natural gas distribution operations, primarily related to low income assistance programs ($60 million). These expenses are recovered through rates and do not impact net income; and

Ÿ  

A $42 million increase in certain electric transmission-related expenditures.

These increases were partially offset by:

Ÿ  

A $434 million decrease in ceiling test impairment charges related to the carrying value of Dominion’s E&P properties;

Ÿ  

The absence of a $142 million write-off of previously deferred RTO costs in connection with the settlement of Virginia Power’s 2009 base rate case proceedings; and

Ÿ  

A $48 million decrease in outage costs due to a decrease in scheduled outage days primarily at certain merchant generation facilities.

DD&A decreased 7%, primarily due to the sale of Dominion’s Appalachian E&P operations ($45 million) and lower amortization due to decreased cost of emissions allowances consumed ($37 million).

Other taxes increased 10%, primarily due to additional property tax from increased investments and higher rates ($16 million), an increase in gross receipts tax due to new non-regulated retail energy customers ($14 million) and higher payroll taxes associated with a workforce reduction program ($12 million).

Gain on sale of Appalachian E&P operations reflects a gain on the sale of these operations, as described in Note 4 to the Consolidated Financial Statements.

Other income decreased 13%, primarily reflecting an increase in charitable contributions ($46 million) and a decrease in interest income ($15 million); partially offset by the absence of an impairment loss on an equity method investment ($30 million) and higher realized gains (including investment income) on nuclear decommissioning trust funds ($12 million).

Interest and related charges decreased 6%, primarily due to a benefit resulting from the net effect of the discontinuance of hedge accounting for certain interest rate hedges and subsequent changes in fair value of these interest rate derivatives ($73 million), partially offset by an increase in interest expense associated with the June 2009 hybrid issuance ($26 million).

 

 

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

 

 

 

Income tax expense increased $1.5 billion, primarily reflecting higher federal and state taxes largely due to the gain on the sale of Dominion’s Appalachian E&P business.

Loss from discontinued operations primarily reflects a loss on the sale of Peoples.

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’s 2011 results were negatively impacted by lower margins from merchant generation operations and less favorable weather on electric utility operations. In 2012, Dominion is expected to experience an increase in net income on a per share basis as compared to 2011. Dominion’s anticipated 2012 results reflect the following significant factors:

Ÿ  

The absence of charges incurred in 2011 related to expected plant retirements, impairment of emissions allowances and Hurricane Irene;

Ÿ  

Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue, as well as growth projects in gas transmission and distribution operations;

Ÿ  

Growth in weather-normalized electric utility sales of 2-2.5% resulting from the recovering economy and rising energy demand;

Ÿ  

Reductions in certain operations and maintenance expenses; and

Ÿ  

A reduction in interest expense; partially offset by

Ÿ  

Lower realized margins from merchant generation operations due to lower commodity prices and the retirement of certain coal units; and

Ÿ  

An increase in DD&A.

Dominion expects the bonus depreciation provisions of the tax legislation enacted by the U.S. Congress in 2010, discussed in Note 6 to the Consolidated Financial Statements, to reduce income taxes otherwise payable, resulting in cash savings in 2012 and 2013 of approximately $475 million and $700 million, respectively.

 

 

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,   2011     2010     2009  
    

Net

Income
attributable
to

Dominion

    Diluted
EPS
   

Net

Income
attributable

to

Dominion

    Diluted
EPS
   

Net

Income
attributable

to

Dominion

    Diluted
EPS
 
(millions, except EPS)                                    

DVP

  $ 501      $ 0.87      $ 448      $ 0.76      $ 384      $ 0.65   

Dominion Generation

    1,003        1.74        1,291        2.19        1,281        2.16   

Dominion Energy

    521        0.91        475        0.80        517        0.87   

Primary operating segments

    2,025        3.52        2,214        3.75        2,182        3.68   

Corporate and Other

    (617     (1.07     594        1.01        (895     (1.51

Consolidated

  $ 1,408      $ 2.45      $ 2,808      $ 4.76      $ 1,287      $ 2.17   

DVP

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

 

Year Ended December 31,    2011     % Change     2010     % Change     2009  

Electricity delivered (million MWh)

     82.3        (3 )%      84.5        4     81.4   

Degree days:

          

Cooling

     1,899        (9     2,090        42        1,477   

Heating

     3,354        (12     3,819        2        3,747   

Average electric distribution customer accounts (thousands)(1)

     2,438        1        2,422        1        2,404   

Average retail energy marketing customer accounts (thousands)(1)

     2,152        6        2,037        19        1,718   

 

(1) Thirteen-month average.

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

2011 VS. 2010

 

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

Regulated electric sales:

    

Weather

   $ (43   $ (0.07

Other

     10        0.02   

FERC transmission equity return

     44        0.07   

Retail energy marketing operations

     6        0.01   

Storm damage and service restoration

     9        0.02   

Other O&M expense(1)

     28        0.04   

Other

     (1       

Share accretion

            0.02   

Change in net income contribution

   $ 53      $ 0.11   

 

(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.

2010 VS. 2009

 

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

Regulated electric sales:

    

Weather

   $ 48      $ 0.08   

Other

     2          

FERC transmission equity return

     23        0.04   

Other O&M expenses(1)

     7        0.01   

Depreciation and amortization

     (8     (0.01

Storm damage and service restoration

     (11     (0.02

Other

     3          

Share accretion

            0.01   

Change in net income contribution

   $ 64      $ 0.11   

 

(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program.

 

 

 

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Dominion Generation

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

 

Year Ended December 31,    2011      % Change     2010      % Change     2009  

Electricity supplied (million MWh):

            

Utility

     82.3         (3 )%      84.5         4     81.4   

Merchant

     43.0         (9     47.3         (1 )     48   

Degree days (electric utility service area):

            

Cooling

     1,899         (9     2,090         42       1,477   

Heating

     3,354         (12     3,819         2       3,747   

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

2011 VS. 2010

 

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

Merchant generation margin

   $ (288   $ (0.50

Regulated electric sales:

    

Weather

     (91     (0.16

Other

     59        0.10   

Rate adjustment clause equity return

     30        0.05   

Outage costs

     (11     (0.02

Other O&M expenses(1)

     71        0.12   

Interest expense

     (15     (0.02

Kewaunee 2010 earnings(2)

     (19     (0.03

Other

     (24     (0.03

Share accretion

            0.04   

Change in net income contribution

   $ (288   $ (0.45

 

(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.
(2) Kewaunee’s 2011 results of operations have been reflected in the Corporate and Other segment due to Dominion’s decision, in the first quarter of 2011, to pursue a sale of the power station.

2010 VS. 2009

 

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

Regulated electric sales:

    

Weather

   $ 104      $ 0.18   

Other

     (23     (0.04

Rate adjustment clause equity return

     66        0.11   

Outage costs

     29        0.05   

Other O&M expenses(1)

     32        0.05   

PJM ancillary services

     27        0.05   

Merchant generation margin

     (209     (0.36

Other

     (16     (0.03

Share accretion

            0.02   

Change in net income contribution

   $ 10      $ 0.03   

 

(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program.

Dominion Energy

Presented below are selected operating statistics related to Dominion Energy’s operations. As discussed in Note 4, in April 2010 Dominion completed the sale of substantially all of its Appa-

lachian E&P operations. As a result, production-related operating statistics for the Dominion Energy segment are no longer significant.

 

Year Ended December 31,    2011      % Change     2010      % Change     2009  

Gas distribution throughput (bcf):

            

Sales

     30         (3 )%      31         (28 )%      43   

Transportation

     253         5        241         16       208   

Heating degree days

     5,584         (2     5,682         (3 )     5,847   

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

            

Sales

     256         (2     260         (19 )     321   

Transportation

     1,040                1,042         5       988   

 

(1) Thirteen-month average.

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

2011 VS. 2010

 

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

Producer services margin

   $ 18      $ 0.03   

Gas transmission margin(1)

     15        0.03   

Other O&M expenses(2)

     11        0.02   

Gas distribution margin:

    

AMR and PIR revenue

     9        0.02   

Base gas sales

     (4     (0.01

E&P disposed operations

     (17     (0.03

Other

     14        0.02   

Share accretion

            0.03   

Change in net income contribution

   $ 46      $ 0.11   

 

(1) Primarily reflects an increase in revenue from NGLs.
(2) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.

2010 VS. 2009

 

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

E&P disposed operations

   $ (61   $ (0.11

Producer services

     (27     (0.05

Gas distribution margin:

    

AMR and PIR revenue(1)

     11        0.02   

Base gas sale(2)

     10        0.02   

Weather

     (2       

Other

     15        0.03   

Cove Point expansion revenue

     20        0.03   

Other

     (8     (0.02

Share accretion

            0.01   

Change in net income contribution

   $ (42   $ (0.07

 

(1) Primarily reflects an allowed return on investment through the AMR and PIR programs.
(2) Reflects East Ohio’s sale of 3 bcf of base gas in December 2010 as the Company determined that it could operate its storage system and meet existing and anticipated contractual commitments with less base gas.
 

 

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

 

 

 

Corporate and Other

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

 

Year Ended December 31,    2011     2010     2009  
(millions, except EPS amounts)                   

Specific items attributable to operating segments

   $ (375   $ 1,014      $ (688

Specific items attributable to Corporate and Other segment:

      

Peoples discontinued operations

            (155     26   

Other

     29        (22     7   

Total specific items

     (346     837        (655

Other corporate operations

     (271     (243     (240

Total net benefit (expense)

   $ (617   $ 594      $ (895

EPS impact

   $ (1.07   $ 1.01      $ (1.51

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 the segments’ performance or allocating resources among the segments. See Note 26 to the Consolidated Financial Statements for discussion of these items.

VIRGINIA POWER

 

 

RESULTS OF OPERATIONS

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

 

Year Ended December 31,    2011      $ Change     2010      $ Change      2009  
(millions)                                  

Net Income

   $ 822       $ (30   $ 852       $ 496       $ 356   

Overview

2011 VS. 2010

Net income decreased by 4%, primarily reflecting less favorable weather, including Hurricane Irene, and an impairment charge related to certain coal-fired power stations, partially offset by higher earnings from rate adjustment clauses and the absence of charges related to a workforce reduction program.

2010 VS. 2009

Net income increased by 139%, primarily reflecting the absence of a charge in connection with the settlement of the 2009 base rate case proceedings, favorable weather and a benefit from rate adjustment clauses, partially offset by charges related to a workforce reduction program.

 

Analysis of Consolidated Operations

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

 

Year Ended December 31,    2011      $ Change     2010      $ Change     2009  
(millions)                                 

Operating Revenue

   $ 7,246       $ 27      $ 7,219       $ 635      $ 6,584   

Electric fuel and other energy-related purchases

     2,506         11        2,495         (477     2,972   

Purchased electric capacity

     452         3        449         40        409   

Net Revenue

     4,288         13        4,275         1,072        3,203   

Other operations and maintenance

     1,743         (2     1,745         122        1,623   

Depreciation and amortization

     718         47        671         30        641   

Other taxes

     222         4        218         27        191   

Other income

     88         (12     100         (4     104   

Interest and related charges

     331         (16     347         (2     349   

Income tax expense

     540         (2     542         395        147   

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

2011 VS. 2010

Net Revenue increased $13 million, primarily reflecting:

Ÿ  

The impact of rate adjustment clauses ($169 million); and

Ÿ  

A decrease in net capacity expenses ($44 million); partially offset by

Ÿ  

The impact ($120 million) of a decrease in sales to retail customers, primarily due to a decrease in heating and cooling degree days ($220 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($100 million); and

Ÿ  

A decrease due to a charge based on the Biennial Review Order to refund revenues to customers ($81 million).

Other operations and maintenance decreased $2 million, primarily reflecting:

Ÿ  

A $267 million decrease in salaries, wages and benefits as well as certain administrative and general costs primarily due to a 2010 workforce reduction program; and

Ÿ  

A $54 million decrease in planned outage costs primarily due to fewer scheduled outage days at certain generation facilities; partially offset by

Ÿ  

A $228 million impairment charge related to certain coal-fired generating units; and

Ÿ  

A $96 million increase due to restoration costs associated with damage caused by Hurricane Irene.

Depreciation and amortization expense increased 7%, primarily due to property additions.

Other income decreased 12%, primarily due to a decrease in the equity component of AFUDC ($17 million), partially offset by an increase in amounts collectible from customers for taxes in connection with contributions in aid of construction ($5 million).

 

 

 

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2010 VS. 2009

Net Revenue increased 33%, primarily reflecting:

Ÿ  

The absence of a charge for the settlement of the 2009 base rate case proceedings ($570 million);

Ÿ  

The impact of rate adjustment clauses ($279 million);

Ÿ  

An increase in sales to retail customers primarily due to an increase in cooling degree days ($248 million); and

Ÿ  

An increase in ancillary revenues received from PJM ($78 million), primarily reflecting an increase in the scheduled dispatch of gas and oil-fired generation units to meet higher demand.

These increases were partially offset by:

Ÿ  

A decrease primarily due to the impact of unfavorable economic conditions on customer usage and other factors ($75 million).

Other operations and maintenance increased 8%, primarily reflecting:

Ÿ  

A $177 million net increase in salaries, wages and benefits primarily due to a workforce reduction program;

Ÿ  

A $42 million increase in certain electric transmission-related expenditures; and

Ÿ  

A $19 million increase in storm damage and service restoration costs.

These increases were partially offset by:

Ÿ  

The absence of a $130 million write-off of previously deferred RTO costs in connection with the settlement of Virginia Power’s 2009 base rate case proceedings.

Depreciation and amortization expense increased 5%, primarily due to property additions.

Other taxes increased 14%, primarily reflecting additional property tax due to increased investments and higher rates ($12 million), incremental use tax that is recoverable through a customer surcharge ($8 million) and higher payroll taxes associated with a workforce reduction program ($7 million).

Income tax expense increased $395 million, primarily reflecting higher pretax income in 2010.

Outlook

Virginia Power expects to provide growth in net income in 2012. Virginia Power’s anticipated 2012 results reflect the following significant factors:

Ÿ  

The absence of charges incurred in 2011 related to expected plant retirements, impairment of emissions allowances and Hurricane Irene;

Ÿ  

Growth in weather-normalized electric sales of 2-2.5% resulting from the recovering economy and rising energy demand; and

Ÿ  

Construction and operation of growth projects and associated rate adjustment clause revenue; partially offset by

Ÿ  

An increase in planned outages at certain nuclear facilities.

Virginia Power expects the bonus depreciation provisions of the tax legislation enacted by the U.S. Congress in 2010, discussed in Note 6 to the Consolidated Financial Statements, to reduce income taxes otherwise payable, resulting in cash savings of approximately $500 million in 2012.

 

 

SEGMENT RESULTS OF OPERATIONS

Presented below is a summary of contributions by Virginia Power’s operating segments to net income:

 

Year Ended December 31,    2011     $ Change     2010     $ Change      2009  
(millions)                                

DVP

   $ 426      $ 49      $ 377      $ 64       $ 313   

Dominion Generation

     664        34        630        155         475   

Primary operating segments

     1,090        83        1,007        219         788   

Corporate and Other

     (268     (113     (155     277         (432

Consolidated

   $ 822      $ (30   $ 852      $ 496       $ 356   

DVP

Presented below are operating statistics related to Virginia Power’s DVP segment:

 

Year Ended December 31,    2011      % Change     2010      % Change     2009  

Electricity delivered (million MWh)

     82.3         (3 )%      84.5         4     81.4   

Degree days (electric service area):

            

Cooling

     1,899         (9     2,090         42       1,477   

Heating

     3,354         (12     3,819         2       3,747   

Average electric distribution customer accounts (thousands)(1)

     2,438         1        2,422         1       2,404   

 

(1) Thirteen-month average.

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

2011 VS. 2010

 

      Increase (Decrease)  
(millions, except EPS)       

Regulated electric sales:

  

Weather

   $ (43

Other

     10   

FERC transmission equity return

     44   

Storm damage and service restoration

     9   

Other O&M expense(1)

     28   

Other

     1   

Change in net income contribution

   $ 49   

 

(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.

2010 VS. 2009

 

      Increase (Decrease)  
(millions)       

Regulated electric sales:

  

Weather

   $ 48   

Other

     2   

FERC transmission equity return

     23   

Other O&M expense(1)

     7   

Depreciation and amortization

     (8

Storm damage and service restoration

     (11

Other

     3   

Change in net income contribution

   $ 64   

 

(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program.
 

 

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

 

 

 

Dominion Generation

Presented below are operating statistics related to Virginia Power’s Dominion Generation segment:

 

Year Ended December 31,    2011      % Change     2010      % Change     2009  

Electricity supplied (million MWh)

     82.3         (3 )%      84.5         4     81.4   

Degree days (electric service area):

            

Cooling

     1,899         (9     2,090         42       1,477   

Heating

     3,354         (12     3,819         2       3,747   
                                            

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

2011 VS. 2010

 

      Increase (Decrease)  
(millions)       

Regulated electric sales:

  

Weather

   $ (91

Other

     59   

Rate adjustment clause equity return

     30   

Outage costs

     33   

Other

     3   

Change in net income contribution

   $ 34   

2010 VS. 2009

 

      Increase (Decrease)  
(millions)       

Regulated electric sales:

  

Weather

   $ 104   

Other

     (23

Rate adjustment clause equity return

     66   

PJM ancillary services

     27   

Energy supply margin(1)

     (13

Other

     (6

Change in net income contribution

   $ 155   
(1) Primarily reflects a reduced benefit from FTRs, due to the crediting of certain FTRs allocated to Virginia Power against Virginia jurisdictional fuel factor expenses subject to deferral accounting beginning July 1, 2009.

Corporate and Other

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

 

Year Ended December 31,    2011     2010     2009  
(millions)                   

Specific items attributable to operating segments

   $ (268   $ (153   $ (430

Other corporate operations

            (2     (2

Total net expense

   $ (268   $ (155   $ (432

SPECIFIC ITEMS ATTRIBUTABLE TO OPERATING SEGMENTS

Corporate and Other primarily includes specific items attributable to Virginia Power’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 26 to the Consolidated Financial Statements for a discussion of these items.

 

LIQUIDITY AND CAPITAL RESOURCES

Dominion and Virginia Power depend on both internal and external sources of liquidity to provide working capital and to fund capital requirements. 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, 2011, Dominion had $1.7 billion of unused capacity under its credit facilities, including $341 million of unused capacity under joint credit facilities available to Virginia Power. See additional discussion under Credit Facilities and Short-Term Debt.

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

 

Year Ended December 31,    2011     2010     2009  
(millions)                   

Cash and cash equivalents at beginning of year(1)

   $ 62      $ 50      $ 71   

Cash flows provided by (used in):