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Dominion Resources 10-K 2010
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, 2009

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
001-02255   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  ¨    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 Resources, Inc. was approximately $19.3 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 February 1, 2010, Dominion had 600,108,463 shares of common stock outstanding and Virginia Power had 241,710 shares of common stock outstanding.

DOCUMENT INCORPORATED BY REFERENCE.

(a) Portions of Dominion’s 2010 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

   3

1A.

  

Risk Factors

   21

1B.

  

Unresolved Staff Comments

   24

2.

  

Properties

   24

3.

  

Legal Proceedings

   28

4.

  

Submission of Matters to a Vote of Security Holders

   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

   31

6.

  

Selected Financial Data

   32

7.

  

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

   33

7A.

  

Quantitative and Qualitative Disclosures About Market Risk

   53

8.

  

Financial Statements and Supplementary Data

   55

9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   126

9A.

  

Controls and Procedures (Dominion)

   126

9A(T).

  

Controls and Procedures (Virginia Power)

   128

9B.

  

Other Information

   129

Part III

     

10.

  

Directors, Executive Officers and Corporate Governance

   129

11.

  

Executive Compensation

   130

12.

  

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

   154

13.

  

Certain Relationships and Related Transactions, and Director Independence

   154

14.

  

Principal Accountant Fees and Services

   155

Part IV

     

15.

  

Exhibits and Financial Statement Schedules

   156


Table of Contents

Glossary of Terms

 

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

 

Abbreviation or Acronym    Definition

AOCI

  

Accumulated other comprehensive income (loss)

AFUDC

  

Allowance for funds used during construction

AIP

  

Annual Incentive Plan

Antero

  

Antero Resources

AROs

  

Asset retirement obligations

BBIFNA

  

Babcock & Brown Infrastructure Fund North America

bcf

  

Billion cubic feet

bcfe

  

Billion cubic feet equivalent

Bear Garden

  

A 580 MW combined cycle, natural gas-fired power station under construction in Buckingham County, Virginia

BP

  

BP Alternative Energy, Inc.

Brayton Point

  

Brayton Point power station

BRP

  

Benefit Restoration Plan

BVP

  

Book Value Performance

CAA

  

Clean Air Act

CAIR

  

Clean Air Interstate Rule

CAMR

  

Clean Air Mercury Rule

CAO

  

Chief Administrative Officer

Carson-to-Suffolk line

  

Virginia Power project to construct an approximately 60-mile 500-kV transmission line in southeastern Virginia

CEO

  

Chief Executive Officer

CD&A

  

Compensation Discussion and Analysis

CDO

  

Collateralized debt obligation

CFO

  

Chief Financial Officer

CGN Committee

  

Compensation, Governance and Nominating Committee

CNG

  

Consolidated Natural Gas Company

CNO

  

Chief Nuclear Officer

CO2

  

Carbon dioxide

COL

  

Combined Construction Permit and Operating License

COO

  

Chief Operating Officer

Dallastown

  

Dallastown Realty

DCI

  

Dominion Capital, Inc.

DCP

  

Dominion Cove Point LNG, LP

DD&A

  

Depreciation, depletion and amortization expense

DEI

  

Dominion Energy, Inc.

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

Dominion East Ohio

  

The East Ohio Gas Company

DPP

  

Dominion Pension Plan

DRC

  

Deferral Recovery Charge

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

EPA

  

Environmental Protection Agency

EPACT

  

Energy Policy Act of 2005

EPS

  

Earnings per share

Equitable

  

Equitable Resources, Inc.

ERISA

  

The Employment Retirement Income Security Act of 1974

ESRP

  

Executive Supplemental Retirement Plan

Fairless

  

Fairless power station

FASB

  

Financial Accounting Standards Board

FERC

  

Federal Energy Regulatory Commission

Fitch

  

Fitch Ratings Ltd.

Fowler Ridge

  

A wind-turbine facility joint venture with BP in Benton County, Indiana

FTRs

  

Financial transmission rights

GAAP

  

U.S. generally accepted accounting principles

GHG

  

Greenhouse gas

Hope

  

Hope Gas, Inc.

HSR Act

  

Hart-Scott-Rodino Act

IRS

  

Internal Revenue Service

ISO

  

Independent system operator

ISO-NE

  

ISO New England

Kewaunee

  

Kewaunee nuclear power station

kV

  

Kilovolt

kWh

  

Kilowatt-hour

 

        1

 


Table of Contents

Glossary of Terms, continued

 

 

Abbreviation or Acronym    Definition

LIBOR

  

London Interbank Offered Rate

LIFO

  

Last-in-first-out inventory method

LNG

  

Liquefied natural gas

LTIP

  

Long-term incentive program

Manchester Street

  

Manchester Street power station

mcf

  

Thousand cubic feet

mcfe

  

Thousand cubic feet equivalent

MD&A

  

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

Meadow Brook-to-Loudoun line

  

Project to construct an approximately 270-mile 500-kV transmission line that begins in southwestern Pennsylvania, crosses West Virginia, and terminates in northern Virginia, of which Virginia Power will construct approximately 65 miles in Virginia and Trans-Allegheny Interstate Line Company will construct the remainder

MISO

  

Midwest Independent Transmission System Operators, Inc.

Millstone

  

Millstone nuclear power station

Moody’s

  

Moody’s Investors Service

MW

  

Megawatt

MWh

  

Megawatt hour

NedPower

  

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

NEOs

  

Named executive officers

NERC

  

North American Electric Reliability Corporation

NGLs

  

Natural gas liquids

North Anna

  

North Anna nuclear power station

North Carolina Commission

  

North Carolina Utilities Commission

NOX

  

Nitrogen oxide

NRC

  

Nuclear Regulatory Commission

NYMEX

  

New York Mercantile Exchange

ODEC

  

Old Dominion Electric Cooperative

Ohio Commission

  

Public Utilities Commission of Ohio

Peaker facilities

  

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

Pennsylvania Commission

  

Pennsylvania Public Utility Commission

Peoples

  

The Peoples Natural Gas Company

PJM

  

PJM Interconnection, LLC

PM&P

  

Pearl Meyer & Partners

PNG Companies LLC

  

An indirect subsidiary of Babcock & Brown Infrastructure Fund North America

Prairie Fork

  

A 300MW wind-turbine facility in central Illinois

PUHCA

  

Public Utilities Holding Company Act

Regulation Act

  

The Virginia Electric Utility Regulation Act

RGGI

  

Regional Greenhouse Gas Initiative

Rider R

  

A rate adjustment clause for recovery of construction-related financing costs related to the construction of the Bear Garden facility to be recovered through rates in 2010

Rider S

  

A rate adjustment clause associated with the recovery of construction-related financing costs for the Virginia City Hybrid Energy Center

Rider T

  

A rate adjustment clause to recover certain transmission-related expenditures over the 12-month period beginning September 1, 2009, subject to an annual review and re-set in 2010, if necessary

ROE

  

Return on equity

ROIC

  

Return on invested capital

RTEP

  

Regional transmission expansion plan

RTO

  

Regional transmission organization

Salem Harbor

  

Salem Harbor power station

SEC

  

Securities and Exchange Commission

SELC

  

Southern Environmental Law Center

Shell

  

Shell WindEnergy, Inc.

SO2

  

Sulfur dioxide

SRA

  

Special Retirement Account

Standard & Poor’s

  

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

State Line

  

State Line power station

SteelRiver Buyer

  

Originally Peoples Hope Gas Companies LLC, which was subsequently renamed PNG Companies LLC in 2010

SteelRiver Fund

  

SteelRiver Infrastructure Fund North America LP

tcfe

  

Trillion cubic feet equivalent

TSR

  

Total shareholder return

U.S.

  

United States of America

VEBA

  

Voluntary Employees’ Beneficiary Association

VIE

  

Variable interest entity

Virginia Commission

  

Virginia State Corporation Commission

Virginia Hybrid Energy Center

  

A 585 MW (nominal) carbon-capture compatible, clean coal powered electric generation facility under construction in Wise County, Virginia

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

VPEM

  

Virginia Power Energy Marketing, Inc.

VPP

  

Volumetric production payment

West Virginia Commission

  

Public Service Commission of West Virginia

 

2        

 


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 27,500 MW of generation, 6,000 miles of electric transmission lines, 56,000 miles of electric distribution lines in Virginia and North Carolina, 12,000 miles of natural gas transmission, gathering and storage pipeline, 21,700 miles of gas distribution pipeline, exclusive of service lines of two inches in diameter or less, and 1.3 Tcfe of proved natural gas and oil reserves. Dominion also owns the nation’s largest underground natural gas storage system, operates approximately 942 bcf of storage capacity and serves retail energy customers in twelve states.

Dominion is focused on expanding its investment in regulated electric generation, and regulated electric and natural gas transmission 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’s nonregulated operations include merchant generation, energy marketing and price risk management activities, retail energy marketing operations and natural gas and oil exploration and production in the Appalachian basin of the U.S. 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 northeastern 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.

The term “Dominion” is used throughout this report and, depending on the context of its use, may represent any of the following: 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.

The term “Virginia Power” is used throughout this report and, depending on the context of its use, may represent any of the following: 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.

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

 

 

EMPLOYEES

As of December 31, 2009, Dominion had approximately 17,900 full-time employees, of which approximately 6,600 employees are subject to collective bargaining agreements. As of December 31, 2009, Virginia Power had approximately 7,400 full-time employees, of which approximately 3,300 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 acquisitions and divestitures by Dominion and Virginia Power during the last five years.

ACQUISITION OF KEWAUNEE NUCLEAR POWER STATION

In July 2005, Dominion completed the acquisition of Kewaunee, a 556 MW facility in northeastern Wisconsin for approximately $192 million in cash. The operations of Kewaunee are included in the Dominion Generation operating segment.

ACQUISITION OF USGEN NEW ENGLAND, INC. POWER STATIONS

In January 2005, Dominion completed the acquisition of three fossil-fuel fired generation facilities for $642 million in cash. The facilities include Brayton Point, a 1,551 MW facility in Somerset, Massachusetts; Salem Harbor, a 754 MW facility in Salem, Massachusetts; and Manchester Street, a 432 MW facility in Providence, Rhode Island. The operations of these facilities are included in the Dominion Generation operating segment.


 

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Table of Contents

 

 

ASSIGNMENT OF MARCELLUS ACREAGE

In 2008, Dominion completed a transaction with Antero 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 receives a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. Dominion retained the drilling rights in traditional formations both above and below the Marcellus Shale interval and continues its conventional drilling program on the acreage.

SALE OF E&P PROPERTIES

In 2007, Dominion completed the sale of its non-Appalachian natural gas and oil E&P operations and assets for approximately $13.9 billion. See Note 4 to the Consolidated Financial Statement for additional information.

In 2006, Dominion received approximately $393 million of proceeds from sales of certain gas and oil properties, primarily resulting from the sale of certain properties located in Texas and New Mexico.

The historical results of these operations are included in the Corporate and Other segment.

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. Following the decision to sell these assets in December 2006, the results of these operations were reclassified to discontinued operations and are presented in the Corporate and Other segment.

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 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 for approximately $30 million.

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. As discussed in Note 25 to the Consolidated Financial Statements, Dominion deconsolidated the CDO entity as of March 31, 2008.

 

TRANSFER OF VIRGINIA POWER ENERGY MARKETING, INC. TO DOMINION

On December 31, 2005, Virginia Power completed a transfer of its indirect wholly-owned subsidiary, VPEM, to Dominion through a series of dividend distributions, in exchange for a capital contribution of $633 million. VPEM provides fuel, gas supply management and price risk management services to other Dominion affiliates and engages in energy trading and marketing activities. As a result of the transfer, VPEM’s results of operations were reclassified to discontinued operations in Virginia Power’s Consolidated Statements of Income and presented in its Corporate and Other segment.

SALE OF PEOPLES

In March 2006, Dominion entered into an agreement with Equitable to sell two of its wholly-owned regulated gas distribution subsidiaries, Peoples and Hope. Peoples serves approximately 358,000 customer accounts in Pennsylvania and Hope serves approximately 114,000 customer accounts in West Virginia. This sale was subject to regulatory approvals in the states in which the companies operate, as well as antitrust clearance under the HSR Act. In January 2008, Dominion and Equitable announced the termination of that agreement, primarily due to the continued delays in achieving final regulatory approvals. Dominion continued to seek other offers for the purchase of these utilities.

In July 2008, Dominion entered into an agreement with an indirect subsidiary of BBIFNA to sell Peoples and Hope. In May 2009, following a change in ownership of the general partner of BBIFNA and other related transactions, BBIFNA was renamed “SteelRiver Infrastructure Fund North America LP”. The sale of Peoples and Hope to the SteelRiver Buyer, an indirect subsidiary of the SteelRiver Fund, was expected to close in 2009, subject to state regulatory approvals in Pennsylvania and West Virginia. In November 2009, the Pennsylvania Commission approved the settlement entered into among Dominion, Peoples, the SteelRiver Buyer and two of the active intervenors in the Peoples sale proceeding, thereby approving the sale of Peoples to the SteelRiver Buyer. In December 2009, the West Virginia Commission denied the application for the sale of Hope. Dominion decided to retain Hope, but continue with the sale of Peoples. The sales price for Peoples was approximately $780 million, subject to changes in working capital, capital expenditures and affiliated borrowings. In February 2010, Dominion completed the sale of Peoples and netted after-tax proceeds of approximately $542 million. A more detailed description of the sale can be found in Note 4 to the Consolidated Financial Statements.


 

4        

 


Table of Contents

 

 

 

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 that includes its corporate, service company and other functions and the net impact of certain operations disposed of or to be disposed of, which are discussed in Note 4 to the Consolidated Financial Statements. Corporate and Other also 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. Prior to the fourth quarter of 2009, Hope was included in Dominion’s Corporate and Other segment and its assets and liabilities were classified as held for sale. During the fourth quarter of 2009, following Dominion’s decision to retain this subsidiary, Hope was transferred to the Dominion Energy operating segment and its assets and liabilities were reclassified from held for sale.

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   X  
  LNG import and storage   X  
  Appalachian gas exploration and     production   X  
    Producer services   X    

For additional financial information on business segments, including revenues from external customers, see Notes 1 and 27 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.

DVP

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

Revenue provided by electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Changes in revenue are driven primarily by weather, customer growth and other factors impacting consumption such as the economy and energy conservation. Variability in earnings results from changes in rates, weather, the economy, customer growth and 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 has improved. The metric used to measure electric service reliability (System Average Interruption Duration Index, excluding major storm events) has improved from 139 minutes at the end of 2004 to 110 minutes at the end of 2009. Customer service options are also being 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. At the end of 2009, over 800,000 of Virginia Power’s customers were signed up to manage their account on-line through dom.com, and over 2.9 million transactions were performed on-line in 2009. This reflects a transaction increase of 45% over 2008. As electric distribution continues to evolve, safety, operational performance and customer service will remain as key focal areas.

The Virginia General Assembly enacted legislation in April 2007 that instituted a modified cost-of-service rate model for the Virginia jurisdiction of Virginia Power’s utility operations, subject to base rate caps in effect through December 31, 2008. In 2009, the Virginia Commission initiated a review of Virginia Power’s base rates. A discussion of Virginia Power’s proposal in the case, including a settlement agreement to which it is a party, is contained in Electric Regulation in Virginia under Regulation.

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 results from changes in rates and the timing of property additions, retirements and depreciation.

In April 2008, FERC granted an application by 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% on the common equity base of these operations, effective as of January 1, 2008. The FERC ruling did not materially impact the Company’s results of operations; however, the FERC-approved formula method allows Virginia Power to earn a more current return on its growing investment in electric transmission infrastructure. In addition, in August 2008, FERC granted an application by Virginia Power’s electric transmission operations requesting a revision to its cost of service to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects and approved an incentive of 1.5% for four of the projects and an incentive of 1.25% for the other seven. See Federal Regulations in Regulation for additional information.

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


 

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committed to meeting NERC standards, modernizing their infrastructure and maintaining superior system reliability. Virginia Power’s electric transmission operations will continue to focus on safety, operational performance 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 and have experienced strong customer growth during the past few years. The retail business requires limited capital investment and currently employs fewer than 150 people. The retail customer base is diversified across three product lines—natural gas, electricity and home warranty services. In natural gas, Dominion has a heavy concentration of customers in markets where utilities have a long-standing commitment to customer choice. In electricity, Dominion pursues 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 customer additions, new markets/products and 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 for additional information.

PROPERTIES

Virginia Power has approximately 6,000 miles of electric transmission lines of 69 kV or more located in the states of North Carolina, Virginia and West Virginia. Portions of Virginia Pow -

er’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 June 2006, PJM authorized construction of numerous electric transmission upgrades through 2011. Virginia Power is involved in two of the major construction projects, which are designed to improve the reliability of service to customers and the region, and are subject to applicable state and federal permits and approvals.

In October 2008, the Virginia Commission authorized construction of the Meadow Brook-to-Loudoun line and affirmed the 65-mile route proposed for the line which is adjacent to, or within, existing transmission line right-of-ways. The Virginia Commission’s approval of the Meadow Brook-to-Loudoun line was conditioned on the respective state commission approvals of both the West Virginia and Pennsylvania portions of the transmission line. The West Virginia Commission’s approval of Trans-Allegheny Interstate Line Company’s application became effective in February 2009 and the Pennsylvania Commission granted approval in December 2008. In March 2009, the Sierra Club filed an appeal and request for stay of the West Virginia Commission’s approval, which was subsequently denied by the Supreme Court of West Virginia in April 2009. An appeal of the Pennsylvania Commission’s approval by the Energy Conservation Council of Pennsylvania is pending. In February 2009, Petitions for Appeal of the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line were filed with the Supreme Court of Virginia by the Piedmont Environmental Council and others. In November 2009, the Virginia Supreme Court affirmed the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line. The Meadow Brook-to-Loudoun line is expected to cost approximately $255 million and, subject to the receipt of all regulatory approvals, is expected to be completed in June 2011.

In October 2008, the Virginia Commission authorized the construction of the Carson-to-Suffolk line. This project is estimated to cost $224 million and is expected to be completed in June 2011. The siting and construction of these transmission lines are subject to applicable state and federal permits and approvals.

In addition, Virginia Power’s electric distribution network includes approximately 56,000 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain right-of-ways that have been obtained from the apparent owner of real estate, but underlying titles have not been examined. Where right-of-ways 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 and its 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. The generation mix is diversified and includes coal, nuclear, gas, oil and renewables. The generation facilities of Virginia Power’s electric utility fleet are located in Virginia, West Virginia and North Carolina. As discussed in Properties, Virginia Power has plans to add additional generation capacity to satisfy future growth in its utility service area.

Earnings for the Generation operating segment of Virginia Power primarily result from the sale of electricity generated by its utility fleet. Due to 1999 Virginia deregulation legislation, as amended in 2004 and 2007, revenues for serving Virginia jurisdictional retail load were based on capped rates through 2008. Additionally, fuel costs for the utility fleet, including purchased power, were subject to fixed-rate recovery provisions until July 1, 2007. Pursuant to the 2007 amendments to the fuel cost recovery statute, annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs, were re-instituted beginning July 1, 2007 for Virginia jurisdictional customers. The Virginia General Assembly enacted legislation in April 2007 that returned the Virginia jurisdiction of Virginia Power’s generation operations to a modified cost-of-service rate model, subject to base rate caps in effect through December 31, 2008. As a result, Virginia Power reapplied accounting guidance for cost-based regulation to those operations in April 2007, when the legislation was enacted. In 2009, the Virginia Commission initiated a review of Virginia Power’s base rates. A discussion of

Virginia Power’s proposal in the case, including a settlement agreement to which it is a party, is contained in Electric Regulation in Virginia under Regulation. 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.

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 facilities of Dominion’s merchant fleet are located in Connecticut, Illinois, Indiana, Massachusetts, Pennsylvania, Rhode Island, West Virginia and Wisconsin. In the merchant generation business, Dominion is adding generation capacity through several new renewable energy projects and uprates, as discussed in Properties. 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 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 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 by hedging a substantial portion of its expected near-term sales with derivative instruments and also entering into long-term power sales agreements, which should help mitigate the adverse impact on earnings from declines in commodity prices, such as those experienced during 2008 and 2009. 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

Retail choice was made available to Virginia Power’s Virginia jurisdictional electric utility customers beginning January 1, 2003; however, no significant competition developed. In April 2007, the Virginia General Assembly passed legislation ending retail choice for most of these customers effective January 1, 2009. See Regulation—State Regulations—Electric for more information. Currently, North Carolina does not offer retail choice to electric customers.

Dominion Generation Operating Segment—Dominion

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 competition.


 

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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 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 generation facilities, see Item 2. Properties.

Dominion Generation Operating Segment—Dominion and Virginia Power

Based on available generation capacity and current estimates of growth in customer demand in Virginia Power’s utility service area, it will need additional generation capacity over the next ten years. 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 growing demand in its core market in Virginia. As part of this program, the following projects have recently been completed or are in various stages of development:

In June 2008, Virginia Power commenced the operation of two additional natural gas-fired electric generating units (Units 3 and 4) totaling 321 MW at its Ladysmith power station to supply electricity during periods of peak demand. In addition, in April 2009, a fifth combustion turbine (Unit 5) with 160 MW of capacity commenced operations.

The Virginia Commission issued a final order in March 2008 (Final Order), approving a certificate to construct and operate the Virginia City Hybrid Energy Center located in Wise County, Virginia, which once operational, will generate about 585 MW. In July 2008, the SELC, on behalf of four environmental groups, filed a Petition for Appeal of the Final Order with the Supreme Court of Virginia. In April 2009, the Virginia Supreme Court affirmed the Virginia Commission’s Final Order. In its Final Order, the Virginia Commission approved an initial return on common equity for the facility of 12.12%, consisting of a base return of 11.12% plus a 100 basis point enhancement that Virginia law provides for new conventional coal generation facili -

ties. The Virginia Commission also authorized Virginia Power to apply for an additional 100 basis point enhancement upon a demonstration that the plant is carbon-capture compatible. The enhanced return will apply to the Virginia City Hybrid Energy Center during construction and through the first twelve years of the facility’s service life.

In June 2008, the Virginia State Air Pollution Control Board approved and issued an air permit to construct and operate the Virginia City Hybrid Energy Center and also approved and issued another air permit for hazardous emissions. Construction of the Virginia City Hybrid Energy Center commenced and the facility is expected to be in operation by 2012. In August 2008, the SELC, on behalf of four environmental groups, filed Petitions for Appeal in Richmond Circuit Court challenging the approval of both of the air permits. The Richmond Circuit Court issued an Order in September 2009 upholding the initial air permit and upholding the second air permit for hazardous emissions except for one condition related to the permit limit for mercury emissions. The hazardous emissions air permit was amended by the Virginia Department of Environmental Quality in September 2009 to comply with the Richmond Circuit Court Order. The permit amendment does not impact the project. In October 2009, the SELC filed a Notice of Appeal of the court’s Order regarding the initial air permit with the Richmond Circuit Court, initiating the appeals process to the Virginia Court of Appeals. The SELC’s opening brief to the Virginia Court of Appeals was filed in January 2010. Briefing should conclude in February 2010. Oral argument will be scheduled upon the completion of briefing. A decision by the Court of Appeals is expected by the second or third quarter of 2010. The result of the appeal does not impact the project’s construction.

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna, which Virginia Power owns along with ODEC. Virginia Power and ODEC have obtained an Early Site Permit for the North Anna site from the NRC. In November 2007, Virginia Power, along with ODEC, filed an application with the NRC for a COL that references a specific reactor design and which would allow Virginia Power to build and operate a new nuclear unit at North Anna. In January 2008, the NRC accepted Virginia Power’s application for the COL and deemed it complete. In December 2008, Virginia Power terminated a long-lead agreement with its vendor with respect to the reactor design identified in its COL application and certain related equipment. A competitive process was initiated in 2009 to determine if vendors can provide an advanced technology reactor that could be licensed and built under terms acceptable to Virginia Power. If, as a result of this process, Virginia Power chooses a different reactor design, it will amend its COL application, as necessary. Virginia Power has not yet committed to building a new nuclear unit.

The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the Atomic Safety and Licensing Board of the NRC granted a request for a hearing on one of eight contentions filed by the Blue Ridge Environmental Defense League. In August 2009, the Atomic Safety and Licensing Board dismissed this contention as moot, but in November 2009 admitted a new contention filed by Blue Ridge Environmental Defense League. Virginia Power filed a motion for reconsideration of this ruling that is pending before the Atomic Safety and Licensing


 

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Board. Absent additional contentions, the mandatory NRC hearing will be uncontested with respect to other issues. Virginia Power has a cooperative agreement with the DOE to share equally the cost of developing a COL that references a specific reactor technology; however, this agreement may not remain in effect going forward if Virginia Power chooses a different reactor technology.

In June 2008, the DOE issued a solicitation announcement inviting the submission of applications for loan guarantees from the DOE under its Loan Guarantee Program in support of debt financing for nuclear power facility projects in the U.S. In May 2009, the DOE announced the names of four energy companies that were selected to begin negotiations for federal loan guarantees for proposed new nuclear units in the U.S. Although Virginia Power, in a two-part process, submitted an application for a federal loan guarantee for the proposed North Anna unit, the Company was not among those selected. While Virginia Power can provide no assurance, because of the dynamic nature of the market for new nuclear units, there may be other opportunities to secure a loan guarantee with the DOE.

In March 2008, Virginia Power purchased the Bear Garden power station development project which, once constructed, will generate about 580 MW. The air and water permits for the combined-cycle, natural gas-fired power station have been amended to allow for Virginia Power’s project designs and schedules. Authorization was granted by the Virginia Commission in March 2009 to build the proposed combined-cycle, natural gas-fired power station and transmission interconnection line for an estimated $619 million, excluding financing costs. A gas pipeline is scheduled to be constructed by Columbia Gas of Virginia to provide gas supply to the power station.

In March 2008, Virginia Power also purchased a power station development project in Warren County, Virginia for future development. If developed, the project will involve the construction of a combined-cycle, natural gas-fired power station expected to generate more than 600 MW of electricity and will be subject to necessary regulatory approvals.

In April 2008, Virginia Power announced a joint effort with BP to evaluate wind energy projects, which, if completed, would increase the renewable energy capacity of Virginia Power’s utility generation fleet.

Dominion Generation Operating Segment—Dominion

In addition to the Powering Virginia projects, Dominion has invested in several wind farm projects. In December 2006, Dominion acquired a 50% interest in NedPower. NedPower consists of two phases totaling 264 MW. The first (164 MW) and second (100 MW) phases began commercial operations in July and December 2008, respectively.

In January 2008, Dominion acquired a 50% interest in Fowler Ridge. The first phase consisting of 300 MW achieved full commercial operations in March 2009. Dominion has a long-term agreement with Fowler Ridge to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In June 2009, Dominion reached an agreement with BP to split the development assets of the final 350 MW phase. Under

the agreement, Dominion will own 150 MW of the development assets and BP will retain the remaining development assets. Closing of this transaction was effective in December 2009.

In April 2008, Dominion announced plans to develop Prairie Fork. Construction of this wind turbine facility is subject to receipt of all necessary permits and approvals.

In 2008 and 2009, Dominion completed two uprates totaling 120 MW at Fairless. Additionally, in January 2009, Dominion successfully implemented an NRC-approved 7% uprate at Unit 3 of Millstone. This increased the unit’s output by approximately 77 MW from 1,150 MW to 1,227 MW, or enough to power an additional 60,000 homes.

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.


 

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Dominion Generation Operating Segment—Virginia Power

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

 

      2009
Source
    2008
Source
    2007
Source
 

Coal(1)

   33   33   35

Nuclear(2)

   32      31      29   

Purchased power, net

   25      29      28   

Natural gas

   9      6      6   

Oil

   1      1      2   

Total

   100   100   100

 

(1) Excludes ODEC’s 50% ownership interest in the Clover Power Station. The average cost of coal for 2009 Virginia in-system generation was $33.58 per MWh.
(2) Excludes ODEC’s 11.6% ownership interest in North Anna.

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 for Virginia Power’s utility 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.

NUCLEAR DECOMMISSIONING

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 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 2009 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.

 

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. 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 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 $4.5 billion in 2009 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 during the period 2045 to 2069. In August 2008, Dominion filed an application with the NRC to renew the Kewaunee operating license. A renewal would permit Kewaunee to operate through December 21, 2033 with full decommissioning of Kewaunee during the period 2033 to 2065. The NRC docketed the application in October 2008. No requests for a hearing were received on the application, although there will be opportunities for public input as the NRC conducts its review of the application. The NRC’s schedule contemplates completion of the uncontested proceeding in February 2011.

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

(2009
dollars)

   Funds in
trusts at
December 31,
2009
  

2009
contributions

to trusts

(dollars in millions)                    

Surry

           

Unit 1

   2032    $ 526    $ 340    $ 1.3

Unit 2

   2033      546      334      1.4

North Anna

           

Unit 1(1)

   2038      534      273      0.9

Unit 2(1)

   2040      547      257      0.9

Total (Virginia Power)

        2,153      1,204      4.5

Millstone

           

Unit 1(2)

   n/a      394      286     

Unit 2

   2035      632      345     

Unit 3(3)

   2045      660      340     

Kewaunee

             

Unit 1(4)

   2013      639      450     

Total (Dominion)

        $ 4,478    $ 2,625    $ 4.5

 

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(1) 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 100% of the decommissioning cost for both of North Anna’s units.
(2) Unit 1 ceased operations in 1998, before Dominion’s acquisition of Millstone.
(3) Millstone Unit 3 is jointly owned by Dominion Nuclear Connecticut and a 6.53% undivided interest in Unit 3 is owned by Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation. Amounts reflect 100% of the decommissioning cost for Millstone Unit 3.
(4) Kewaunee Unit 1 original license expiration year is 2013. The cost estimate is based on the license renewal expiration year of 2033.

Dominion Energy

Dominion Energy includes Dominion’s Ohio and West Virginia regulated natural gas distribution companies, regulated gas transmission pipeline and storage operations, natural gas gathering and by-products extraction activities, regulated LNG operations and Appalachian E&P 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. Revenue provided by Dominion’s regulated gas transmission and storage, and LNG operations is based primarily on rates established by FERC. Dominion’s gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio and West Virginia. 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 can be dependent on weather, changes in commodity prices and the economy.

Revenue from gas transportation, gas storage, and LNG storage and regasification services are largely based on firm, fee-based contractual arrangements.

In October 2008, Dominion East Ohio implemented a rate case settlement which began a transition to a Straight Fixed Variable rate design. Under this rate design, Dominion 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, Dominion East Ohio’s revenue is less impacted by weather-related fluctuations in natural gas consumption than under the traditional rate design.

Dominion’s Appalachian E&P business generates income from the sale of natural gas and oil it produces from its reserves, including fixed-term overriding royalty interests formerly associated with its VPP agreements (VPP royalty interests) discussed in Note 11 to the Consolidated Financial Statements. Variability in earnings relates to changes in commodity prices, which are largely market-based, production volumes, which are impacted by numerous factors including drilling success and timing of development projects, and drilling costs which may be impacted

by drilling rig availability and other external factors. Production from VPP royalty interests declined significantly due to the expiration of these interests in February 2009. Dominion manages commodity price volatility by hedging a substantial portion of its near-term expected production, which should help mitigate the adverse impact on earnings from declines in gas and oil prices, such as those experienced in 2008 and 2009. These hedging activities may require cash deposits to satisfy collateral requirements. Dominion’s Appalachian E&P business added 138 bcfe to its gas and oil reserves as a result of its drilling program during 2009, as compared to production of 50 bcfe in 2009, excluding production from VPP royalty interests.

Earnings from Dominion Energy’s other nonregulated business, producer services, 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 has offered an Energy Choice program to customers, in cooperation with the Ohio Commission. West Virginia does not require customer choice in its retail natural gas markets at this time. 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 21,700 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.


 

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Dominion Energy has approximately 12,000 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 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 942 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 its Cove Point LNG facility. Dominion Energy has about 134 compressor stations with more than 747,000 installed compressor horsepower.

Dominion Energy also owns about 1.3 Tcfe of proved natural gas and oil reserves and produces approximately 137 million cubic feet equivalent of natural gas and oil per day from its leasehold acreage and facility investments in Appalachia.

In 2006, FERC approved the proposed expansion of Dominion’s Cove Point terminal and DTI pipeline and the commencement of construction of the project. The expansion project included the installation of two new LNG storage tanks at Dominion’s Cove Point terminal, each capable of storing 160,000 cubic meters of LNG, pumps, gas-turbine generators, and vaporization capacity to increase the terminal send-out by 800,000 dekatherms per day. Dominion installed 48 miles of 36-inch pipeline to increase the terminal take-away capacity to approximately 1,800,000 dekatherms per day. In addition, Dominion’s DTI gas pipeline and storage system was expanded by building approximately 120 miles of pipeline, two new compressor stations in Pennsylvania and other upgrades to other compressor stations in West Virginia and New York. The DTI facilities associated with the Cove Point expansion project were placed into service in December 2008, the Cove Point LNG terminal expansion was placed into service in January 2009 and the remainder of the expanded Cove Point facilities were placed into commercial service in March 2009.

In September 2008, Dominion completed a transaction with Antero 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 receives a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. Dominion retained the drilling rights in traditional formations both above and below the Marcellus Shale interval and continues its conventional drilling program on the acreage. Following this transaction, Dominion controls drilling rights on approximately 450,000 acres in the Marcellus Shale formation. Dominion plans to monetize its remaining acreage within the next two years in order to reduce or eliminate its equity financing needs.

DTI has announced the proposed development of a gas pipeline project, known as the Appalachian Gateway Project, which is designed to transport gas on a firm basis out of the Appalachian Basin in West Virginia and southwestern Pennsylvania to DTI’s interconnect with Texas Eastern Transmission Corporation at Oakford, Pennsylvania. An open season for the project concluded in September 2008. The project is fully subscribed under long

term binding agreements. The Appalachian Gateway Project is expected to be fully placed into service by the fall of 2012.

Dominion 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 Dominion’s West Virginia system. Construction started in 2009 and will be completed by the fourth quarter of 2012. The cost of the project will be paid for by rates charged to producers.

Dominion has also 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. Dominion is currently in discussions regarding the continued development of the 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.

SOURCES OF ENERGY SUPPLY

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. Dominion Energy’s natural gas supply is obtained from various sources including Dominion’s own production, less royalties, purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area and gas marketers.

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 Dominion East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipelines and storage business can also be weather sensitive. Dominion Energy’s Appalachian E&P business can be impacted by seasonal changes in the demand for natural gas and oil. Commodity prices, including prices for Dominion’s unhedged natural gas and oil production, can be impacted by seasonal weather changes, the effects of weather on operations and the economy. Dominion’s producer services business is affected by seasonal changes in the prices of


 

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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 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 certain operations disposed of or to be disposed of, which are discussed in Note 4 to the Consolidated Financial Statements. Operations disposed of during 2007 included all of Dominion’s non-Appalachian E&P operations, three natural gas-fired merchant generation peaker facilities and certain DCI operations. Operations disposed of during 2008 included certain DCI operations. Operations to be disposed of at December 31, 2009 include Peoples, which Dominion sold in February 2010. 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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Conservation and load management;

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Renewable generation development;

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

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Improvements in other energy infrastructure; and

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Compliance with applicable environmental laws, regulations and rules.

Conservation plays a role in meeting the growing demand for electricity. Virginia re-regulation legislation enacted in 2007 provides incentives for energy conservation and sets a 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. A description of Virginia Power’s conservation and load management programs is detailed below.

Dominion and Virginia Power are working to improve their own energy efficiency, both in using less fuel to produce the same amount of energy and to use less energy in their operations. Recent uprates of their facilities have resulted in significant increases in generation capacity and lower emissions to meet the needs of their customers.

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 renewable portfolio standard of 12.5% by 2021. In July 2009, Virginia Power applied to the Virginia Commission for approval to participate in Virginia’s renewable energy portfolio standard program. The application identifies a Renewable Portfolio Standard Plan for meeting Virginia’s goals and includes a combination of existing renewable energy sources, development of new renewable energy facilities and purchase of renewable energy certificates. Virginia Power also anticipates using at least 10% biomass (woodwaste) at the Virginia City Hybrid Energy Center.

In addition, Dominion is a 50% owner of the NedPower wind energy facility in Grant County, West Virginia. Dominion’s share of this project produces 132 MW of renewable energy. Dominion has also acquired a 50% interest in a joint venture with BP to develop the Fowler Ridge wind-turbine facility in Benton County, Indiana. The first phase with a generating capacity of 300 MW reached full commercial operations in March 2009. Dominion has a long-term agreement with the joint venture to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In June 2009, Dominion reached an agreement with BP to split the development assets of the final 350 MW phase. Under the agreement with BP, Dominion will own 150 MW of the development assets and BP will retain the remaining development assets. Closing of this transaction was effective in December 2009.

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 growing demand in the 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. A critical aspect of the Powering Virginia program is the extent to which Virginia Power seeks to reduce the carbon intensity of its generation fleet by developing generation facilities with zero CO2 and low CO2 emissions, as well as economically viable facilities that can be equipped for CO2 capture and storage. There is no current economically viable technological solution to retro-fit existing fossil-fueled technology to capture and store GHG emissions. There are six generally recognized GHGs including CO2, methane, nitrous oxide, sulfur hexafluoride, hydrofluorocarbons, and perfluorocarbons. Given that new generation units have useful lives of up to 55 years, Virginia Power will give full consideration to CO2 and other GHG emissions when making long-term decisions. See Dominion Generation—Properties for more information.

Virginia Power plans to make a significant investment in improving the capabilities and reliability of its electric transmission and distribution system. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed or to be developed in the future. See Global Climate Change under Regulations for more information.

In further support of the Companies’ environmental strategy, Dominion and Virginia Power remain committed to compliance with all applicable environmental laws, regulations and rules


 

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related to our operations. Additional information related to our environmental compliance obligations can be found in Note 23 to the Consolidated Financial Statements.

Energy Efficiency and Peak Shaving Programs

In July 2009, Virginia Power filed with the Virginia Commission an application for approval and cost recovery of eleven DSM programs. Virginia Power plans to use DSM, along with its traditional and renewable supply-side resources, to meet its projected load growth over the next 15 years. The DSM programs provide the first steps toward achieving Virginia’s goal of reducing, by 2022, the electric energy consumption of Virginia Power’s retail customers by ten percent of what was consumed in 2006. Virginia Power expects to launch the DSM programs in early 2010, subject to approval by the Virginia Commission and the North Carolina Commission, as applicable.

A key component of the plan is the demonstration of “smart grid” technologies that are designed to enhance Virginia Power’s electric distribution system by allowing energy to be delivered more efficiently. Dependent upon the outcome of demonstration and certain regulatory proceedings, Virginia Power may make a significant investment in replacing existing meters with Advanced Metering Infrastructure. The technology is expected to lead to improvements in service reliability and the ability of customers to monitor and control their energy use. Additionally, programs in the DSM plan include:

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Incentives for construction of energy-efficient homes that meet the federal government’s Energy Star® standards;

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Incentives for residential and commercial customers to install energy-efficient lighting;

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Energy audits and improvements for homes of low-income customers;

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Incentives for residential customers who voluntarily enroll to allow Virginia Power to cycle their air conditioners and heat pumps during periods of peak demand; and

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Incentives for residential and commercial customers to improve the energy efficiency of their heating and/or cooling units.

 

 

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.

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 or incur financial commitments for construction of any substantial 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 securities.

Electric Regulation in Virginia

In March 2009, Virginia Power filed with the Virginia Commission, pursuant to the Regulation Act, a petition to recover from Virginia jurisdictional customers an annual net increase of approximately $78 million in costs related to FERC-approved transmission charges and PJM demand response programs. This amount also included a portion of costs discussed further in Federal Regulations. In a final order in June 2009, the Virginia Commission approved recovery of approximately $218 million through Rider T, which includes approximately $150 million of transmission-related costs that were traditionally incorporated in base rates, plus an incremental increase of approximately $68 million. The Virginia Commission also ruled that approximately $10 million that the Company had proposed to collect in Rider T would be more appropriately recovered through base rates, and those costs have been incorporated into the Company’s revised base rate filing that was submitted in July 2009. Rider T became effective on September 1, 2009, and increased a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.11 per month.

Virginia Power also has filed with the Virginia Commission an application for approval and cost recovery of eleven DSM programs, including one peak-shaving program and ten energy efficiency programs. Virginia Power plans to use DSM, along with its traditional and renewable supply-side resources, to meet its projected load growth over the next 15 years. The DSM programs provide the first steps toward achieving Virginia’s goal of reducing, by 2022, the electric energy consumption of the Company’s retail customers by ten percent of what was consumed in 2006. In February 2010, the Virginia Commission concluded an evidentiary hearing to consider the DSM programs and the related recovery. The Company has requested approval of two rate adjustment clauses for the associated cost recovery to be effective April 1, 2010. Specifically, the two rate adjustment clauses for recovery from Virginia jurisdictional customers represent an annual net increase in costs of approximately $48 million for the period April 1, 2010 to March 31, 2011. If approved by the Virginia Commission, the rate adjustment clauses will be expected, on a combined basis, to increase a typical 1,000 kWh residential bill by approximately $0.91 per month. The Regulation Act gives the Virginia Commission until the end of March 2010 to act on Virginia Power’s application.

In March 2009, Virginia Power filed with the Virginia Commission its first annual update to the rate adjustment clause for the Virginia City Hybrid Energy Center requesting an increase of approximately $99 million for financing costs to be recovered through rates in 2010. As part of this filing Virginia Power requested that the 13.5% ROE proposed in its March 31, 2009 base rate filing be applied to Rider S, plus the 100 basis point enhancement for construction of a new coal-fired generation facility, for a requested total ROE of 14.5%. An evidentiary hearing was held before a hearing examiner in August 2009, at which Virginia Power presented a proposed Stipulation and Recommendation that, among other things, would reduce the increase in the revenue requirement by approximately $8 million to $91 million. In December 2009, the hearing examiner’s report


 

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was issued recommending approval of the Rider S increase as set forth in the proposed Stipulation, and thereafter the Virginia Commission approved the Rider S increase consistent with this recommendation. The Rider S revenue requirement approved for 2010 remains subject to revision to reflect the Virginia Commission’s ROE determination in the pending base rate proceeding.

In March 2009, Virginia Power also filed a petition with the Virginia Commission for recovery of approximately $77 million of construction-related financing costs associated with Bear Garden through the initiation of Rider R. As part of this filing Virginia Power requested that the 13.5% ROE proposed in its March 31, 2009 base rate filing be applied to the Bear Garden facility rate adjustment clause, with a 100 basis point enhancement for construction of a combined-cycle facility, as authorized by the Regulation Act, for a requested total ROE of 14.5%. An evidentiary hearing was held before a hearing examiner in August 2009. In Virginia Power’s post-hearing brief, it unilaterally agreed to reduce the revenue requirement by $4 million to $73 million. In December 2009, the Virginia Commission approved Rider R with the $73 million revenue requirement for 2010. The Rider R revenue requirement approved for 2010 remains subject to revision to reflect the Virginia Commission’s ROE determination in the pending base rate proceeding. In accordance with the Virginia Commission’s approval of Rider R, the enhanced return will apply to the Bear Garden facility during construction and through the first ten years of the facility’s service life.

In March 2009, Virginia Power filed its Virginia fuel factor application with the Virginia Commission. The application requested an annual decrease in fuel expense recovery of approximately $236 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.893 cents per kWh to 3.529 cents per kWh, or approximately $3.64 per month for the typical 1,000 kWh Virginia jurisdictional residential customer’s average bill. The proposed fuel factor went into effect on July 1, 2009 on an interim basis and an evidentiary hearing on the Company’s application was held on September 1, 2009. Consistent with a proposal made by the Company at the hearing in September 2009, the Virginia Commission issued an interim fuel order, effective October 1, 2009, further reducing the fuel factor by approximately $103 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.529 cents per kWh to 3.310 cents per kWh, or approximately $2.19 per month for a typical 1,000 kWh Virginia jurisdictional residential customer’s bill. The cumulative decrease in the fuel factor for the period July 1, 2009 through June 30, 2010 reflects lower projected fuel expenses and a prospective credit against fuel expenses of certain FTRs allocated to the Company. In December 2009, the Virginia Commission issued another interim order decreasing Virginia Power’s fuel factor by approximately $119 million from 3.310 cents per kWh to 2.927 cents per kWh, a reduction of approximately $3.83 per month for the typical 1,000 kWh Virginia jurisdictional residential customer’s average bill, for service rendered on and after January 1, 2010. The Virginia Commission has not yet issued a final order.

Pursuant to the Regulation Act, the Virginia Commission entered an order in January 2009 initiating reviews of the base rates and terms and conditions of all investor-owned electric utilities in Virginia. In response, Virginia Power submitted base rate filings and accompanying schedules during 2009 to the Virginia

Commission, which, as amended, propose to increase its Virginia jurisdictional base rates by approximately $250 million annually. Virginia Power’s initial March 2009 filing proposed a 12.5% ROE, plus an additional 100 basis point performance incentive pursuant to the Regulation Act based on Virginia Power’s generating plant performance, customer service, and operating efficiency, resulting in a total ROE request of 13.5%. In July 2009, in response to rulings by the Virginia Commission relating to the appropriate rate year and capital structure to be used in the Company’s base rate review, Virginia Power submitted a revised filing reflecting a number of adjustments, including an upward adjustment of 50 basis points in the proposed ROE. The base rate increase became effective on an interim basis on September 1, 2009, subject to refund and adjustment by the Virginia Commission and increases a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $5.22 per month.

In November 2009, Virginia Power and the Office of the Attorney General of Virginia, Division of Consumer Counsel, and certain other interested parties, filed a Stipulation and Recommendation for consideration and requested approval by the Virginia Commission that would resolve the pending proceeding to set base rates in Virginia, the Virginia fuel case proceeding and the authorized ROE for the rate adjustment clauses for the Virginia City Hybrid Energy Center, Bear Garden and the DSM programs. The November 2009 Stipulation entails, among other things, a partial refund of 2008 revenues and other amounts, an authorized ROE applicable to base rates of 11.9%, an authorized ROE applicable to the Virginia City Hybrid Energy Center and Bear Garden rate adjustment clauses of 12.3% and continuation of Virginia Power’s base rates in existence prior to September 1, 2009. An evidentiary hearing in the base rate review has been completed, at which evidence relating to both Virginia Power’s request for a base rate increase and the November 2009 Stipulation was presented. Not all of the parties to the base rate review or the related proceedings supported the November 2009 Stipulation. In February 2010, Virginia Power filed a revised Stipulation and Recommendation with the Virginia Commission. As compared to the November 2009 Stipulation, the February 2010 Stipulation has the support of all parties, including the Staff of the Virginia Commission and reflects an increase in the amounts to be refunded to customers. Virginia Power’s 2009 results include a charge representing its best estimate of the probable outcome of this matter, which is discussed further in Note 14 to the Consolidated Financial Statements. Outcomes of the base rate review could include adoption of the terms of the February 2010 Stipulation, or alternatively, a rate increase, a rate decrease, or a partial refund of 2008 earnings deemed more than 50 basis points above the authorized ROE.

If the Virginia Commission’s future rate actions, including actions relating to Virginia Power’s 2009 base rate review, DSM programs, recovery of Virginia fuel expenses, and additional rate adjustment clause filings differ materially from Virginia Power’s expectations it could adversely affect its results of operations, financial condition and cash flows.

North Carolina Regulation

In 2004, the North Carolina Commission commenced a review of Virginia Power’s North Carolina base rates and subsequently ordered Virginia Power to file a general rate case to show cause


 

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why its North Carolina jurisdictional base rates should not be reduced. The rate case was filed in September 2004, and in March 2005 the North Carolina Commission approved a settlement that included a prospective $12 million annual reduction in current base rates and a five-year base rate moratorium, effective as of April 2005. Fuel rates are still subject to annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs.

In February 2010, Virginia Power filed an application with the North Carolina Commission to increase its electric retail rates in North Carolina by approximately $46 million effective January 2011. The requested rate increase would consist of a base rate increase of approximately $29 million and approximately $17 million in purchased power costs to be recovered by means of the existing pass-through fuel adjustment charge. These purchased power costs have previously been considered part of the Company’s cost of service for recovery through base rates. The application entails a proposed ROE of 11.9%. The proposed base rate increase of $29 million would increase a typical 1,000 kWh North Carolina jurisdictional customer’s bill by approximately 9% or $8.96 per month when compared to residential bills under the currently approved rates. If the entire $17 million increase related to purchased power costs were to be approved for recovery in the 2011 fuel adjustment charge, and if none of those costs are offset by reductions in costs for other fuel types, the additional impact on residential customer bills would be approximately 5% or $4.94 per month. It is anticipated that a public hearing on the proposed base rate increase will be consolidated with the Company’s annual fuel adjustment proceeding in the fourth quarter of 2010 so as to facilitate a North Carolina Commission order in both matters before the end of 2010.

GAS

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

Status of Competitive Retail Gas Services

Each of the three states in which Dominion has gas distribution operations has enacted or 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 has offered retail choice to residential and commercial customers. At December 31, 2009, approximately 1 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice program. In October 2006, Dominion East Ohio implemented a pilot program approved by the Ohio Commission as a transitional step towards the improvement and expansion of the Energy Choice program. Under the pilot program, Dominion 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 Dominion 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, Dominion East Ohio buys natural gas under the Standard Service Offer program for customers not eligible to participate in the Energy Choice program, but places Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills. Subject to ultimate Ohio Commission approval, Dominion East Ohio may exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. Dominion East Ohio will continue 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.

Pennsylvania—In Pennsylvania, supplier choice is available for all residential and small commercial customers of Peoples. At December 31, 2009, approximately 94,000 of Peoples’ 358,000 residential and small commercial customers had opted for Energy Choice in the Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers.

West Virginia—At this time, West Virginia has not enacted legislation to require customer choice 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 customer 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, Pennsylvania and West Virginia. When necessary, Dominion’s gas distribution subsidiaries seek general base rate increases to recover increased operating costs. 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.

In the fourth quarter of 2008, the Ohio Commission approved an approximately $41 million annual revenue increase and an 8.49% allowed rate of return on rate base for Dominion East Ohio, which were reflected in revised rates commencing December 22, 2008.

In October 2008, Hope filed a request with the West Virginia Commission for an increase in the base rates it charges for natural gas service. The requested new base rates would have increased Hope’s revenues by approximately $34 million annually. In November 2009, the West Virginia Commission authorized an approximately $9 million increase in base rates.


 

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Regulatory Approval of Sale of Peoples

In September 2008, Dominion and BBIFNA each filed a Premerger Notification and Report Form with the U.S. Department of Justice and the Federal Trade Commission under the HSR Act. In October 2008, the mandatory waiting period under the HSR Act related to the proposed sale of Peoples and Hope to the SteelRiver Buyer expired. In September 2009, Dominion and the SteelRiver Fund each filed a renewed Premerger Notification and Report Form with the U.S. Department of Justice and Federal Trade Commission. In October 2009, Dominion and the SteelRiver Fund were granted early termination of the mandatory waiting period under the HSR Act.

In September 2008, Peoples, Dominion and the SteelRiver Buyer filed a joint petition with the Pennsylvania Commission seeking approval of the purchase by the SteelRiver Buyer of all of the stock of Peoples. In September 2009, Peoples, Dominion, the SteelRiver Buyer and two of the active intervenors in the Peoples sale proceeding reached a settlement on issues involved in the Peoples sale. In November 2009, the Pennsylvania Commission approved the settlement, thereby approving the sale of Peoples to the SteelRiver Buyer.

In October 2008, Hope, Dominion and the SteelRiver Buyer filed a joint petition seeking West Virginia Commission approval of the purchase by the SteelRiver Buyer of all of the stock of Hope. In December 2009, the West Virginia Commission denied the application for the sale of Hope.

Dominion decided to retain Hope, but continue with the sale of Peoples, which closed in February 2010.

Federal Regulations

EPACT AND THE REPEAL OF PUHCA

EPACT was signed into law in August 2005. Among other things, EPACT repealed PUHCA, which regulated many significant aspects of a registered holding company system, such as Dominion’s. As a result of PUHCA’s repeal, utility holding companies, including Dominion’s system, are no longer limited to a single integrated public utility system. Further, utility holding companies are no longer restricted from acquiring businesses that may not be related to the utility business. Jurisdiction over certain holding company related activities has been transferred to the FERC, including the issuance of securities by public utilities, the acquisition of securities of utilities, the acquisition or sale of certain utility assets, and the merger with another electric utility or holding company. In addition, both FERC and state regulators are permitted to review the books and records of any company within a holding company system.

EPACT contains key provisions affecting the electric power industry. These provisions include tax changes for the utility industry, incentives for emissions reductions and federal insurance and incentives to build new nuclear power plants. It gives the FERC “backstop” transmission siting authority, as well as increased utility merger oversight. The law also provides incentives and funding for clean coal technologies and initiatives to voluntarily reduce GHG emissions. FERC has issued regulations implementing EPACT. Dominion and Virginia Power do not expect compliance with these regulations to have a material adverse impact on their financial condition or results of operations.

 

FEDERAL ENERGY REGULATORY COMMISSION

Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominion’s merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion’s market-based sales tariffs authorized by FERC. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary. In May 2005, FERC issued an order finding that PJM’s existing transmission service rate design may not be just and reasonable, and ordered an investigation and hearings on the matter. In January 2008, FERC affirmed an earlier decision that the PJM transmission rate design for existing facilities had not become unjust and unreasonable. For recovery of costs of investments of new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a regional rate design where all customers pay a uniform rate based on the costs of such investment. For recovery of costs of investment in new PJM-planned transmission facilities that operate below 500 kV, FERC affirmed its earlier decision to allocate costs on a beneficiary pays approach. A notice of appeal of this decision was filed in February 2008 at the U.S. Court of Appeals for the Seventh Circuit. In August 2009, the court denied the petition for review concerning the rate design for existing facilities, but granted the petition concerning the rate design for new facilities that operate at or above 500 kV, and remanded that issue back to FERC for further proceedings. Dominion and Virginia Power cannot predict the outcome of the FERC proceedings on remand.

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 Electric Reliability Organization. The Electric Reliability Organization 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 Electric Reliability Organization and also issued an initial order approving many reliability standards that went into effect on January 1, 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.


 

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Dominion and Virginia Power have planned and operated their facilities in compliance with earlier NERC voluntary standards for many years and are aware of the new requirements. Dominion and Virginia Power participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. While Dominion and Virginia Power expect that there will be some additional cost involved in maintaining compliance as standards evolve, they do not expect the operations and maintenance expenditures to be significant.

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% on the common equity base of these operations, effective as of January 1, 2008. The formula rate is designed to cover the expected cost of service for each calendar year and is trued up based on actual costs. While other transmission owners in the PJM region use a formula rate based on historic costs, Virginia Power’s formula rate is based on projected costs. The FERC ruling did not materially impact Virginia Power’s results of operations; however, the FERC-approved formula method allows Virginia Power to earn a more current return on its growing investment in electric transmission infrastructure.

In July 2008, Virginia Power filed an application with FERC requesting a revision to its cost of service to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 150 basis points or 1.5% for four of the projects (including the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line) and an incentive of 125 basis points or 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008. The total cost for all eleven projects is estimated at $877 million, and all projects are currently expected to be completed by 2012. Numerous parties sought rehearing of the FERC order in August 2008 and rehearing is pending. Virginia Power cannot predict the outcome of the rehearing.

In May 2008, 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 (the RPM Buyers) filed a complaint at FERC claiming that PJM’s Reliability Pricing Model’s transitional auctions have produced unjust and unreasonable capacity prices. The RPM Buyers requested that a refund effective date of June 1, 2008 be established and that FERC provide appropriate relief from unjust and unreasonable capacity charges within 15 months. In September 2008, FERC dismissed the complaint. The RPM Buyers requested rehearing of the FERC order in October 2008 and rehearing was denied in June 2009. A notice of appeal was filed in August 2009 by the Maryland Public Service Commission and the New Jersey Board of Public Utilities at the U.S. Court of Appeals for the Fourth Circuit. Dominion and Virginia Power cannot predict the outcome of the appeal.

In December 2008, FERC approved the Companies’ DRC request to become effective January 1, 2009, which allows recovery of approximately $153 million of Dominion’s RTO costs, including $140 million at Virginia Power, that were deferred due to a statutory base rate cap established under Virginia law. In June 2009, the Virginia Commission approved full recovery of the DRC from Virginia Power’s retail customers through Rider T. Recovery of the DRC began September 1, 2009. In July 2009, FERC issued an order denying the Office of the Attorney General of Virginia and the Virginia Commission’s requests for rehearing of its December 2008 order. Notices of appeal were filed in September 2009 at the U.S. Court of Appeals for the Fourth Circuit and the appeal is currently pending. In the fourth quarter of 2009, Dominion and Virginia Power wrote off substantially all of these regulatory assets, since recovery is no longer probable based on the proposed settlement of Virginia Power’s rate case proceedings discussed further in Note 14 to the Consolidated Financial Statements.

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, DCP 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 Act of 2002 (2002 Act), which mandates 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 the 2002 Act, and has implemented a program of identification, testing and potential remediation activities. These activities are ongoing.

In May 2005, FERC approved a comprehensive rate settlement with Dominion’s subsidiary, DTI, and its customers and interested state commissions. The settlement, which became effective July 1, 2005, revised Dominion’s natural gas transmission rates and reduced fuel retention levels for storage service customers. As part of the settlement, DTI and all signatory parties agreed to a rate moratorium through June 30, 2010.

In December 2007, DTI and the Independent Oil and Gas Association of West Virginia, Inc. reached a settlement agreement on DTI’s gathering and processing rates for the period January 1, 2009 through December 31, 2011. This settlement maintained the gas retainage fee structure that DTI has had since 2001. The rates are 10.5% for gathering and 0.5% for processing. Under the settlement, DTI continues to retain all revenues from its liquids sales, thus maintaining cash flow from the liquids business. In connection with the settlement, DTI has committed to invest at least $20 million annually in Appalachian gathering-related assets. The new rates have been approved by FERC as negotiated rates.


 

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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. 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. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Companies. 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. Additional information can also be found in Item 3. Legal Proceedings and Note 23 to the Consolidated Financial Statements.

GLOBAL CLIMATE CHANGE

General

In recent years there has been increased national and international attention to GHG emissions and their relationship to climate change, which has resulted in federal, regional and state legislative or regulatory action in this area. Dominion and Virginia Power support national climate change legislation to provide a consistent, economy-wide approach to addressing this issue and are 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.

Dominion developed a more comprehensive GHG inventory for calendar year 2008. For Dominion Generation, Dominion’s and Virginia Power’s direct CO2 equivalent emissions, based on equity share (ownership), were approximately 56 million metric tonnes and 33 million metric tonnes, respectively, in 2008. 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 Dominion’s Cove Point LNG facility) direct CO2 equivalent emissions were approximately 2.5 million metric tonnes, Dominion East Ohio’s direct CO2 equivalent emissions were approximately 1.4 million metric tonnes and Dominion E&P’s direct CO2 equivalent emissions were approximately 0.7 million metric tonnes. While the Companies do not have final 2009 emissions data, they do not expect a significant variance in emissions from 2008 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 United States Code. 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 new EPA Mandatory Reporting of Greenhouse Gases Rule, effective December 2009. Although the reporting rule does not apply until calendar year 2010 emissions, Dominion and Virginia Power have proactively implemented the data collection methodologies specified in the 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 Dominion 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. For Dominion E&P emissions, the protocol used was the American Petroleum Institute August 2009 Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry.

Climate Change Legislation and Regulation

See Note 23 to the Consolidated Financial Statements for information on climate change legislation and regulation.

Physical Risks

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. Additionally, 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’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 and are working toward achieving the standards established by existing state regulations as set forth above. The Companies have an integrated strategy for reducing GHG emission intensity that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, hydro and renewable energy, investing in renewable energy projects, and promoting energy conservation and efficiency efforts. See Environmental Strategy above for a description of Dominion and


 

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Virginia Power’s strategy for reducing GHG emission intensity. Some recent efforts that have or are expected to reduce the Companies’ carbon intensity include:

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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 technology. Virginia Power also converted two coal-fired units to cleaner burning natural gas.

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Since 2000, Dominion has added more than 2,500 MW of non-emitting nuclear generation and approximately 3,050 MW of new lower-emitting natural gas-fired generation including 1,450 MW at Virginia Power (excluding Possum Point), to its generation mix.

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Virginia Power has also added 83 MW of renewable biomass.

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Dominion has completed electrical generation uprates of 120 MW at its gas-fired Fairless power station and 77 MW at Millstone.

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Dominion has over 900 MW of wind energy in operation or development. Also, in April 2008, Virginia Power announced an agreement with BP to jointly develop, own and operate wind energy projects in Virginia.

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In 2009, Virginia Power began constructing the 580 MW combined-cycle natural gas-fired Bear Garden generating facility.

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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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In 2009, Virginia Power filed with the Virginia Commission for approval of eleven DSM programs, including the demonstration of “smart grid” technologies, which are designed to help reduce the electric energy consumption of Virginia Power’s retail customers and therefore reduce generation requirements.

While, upon entering service, 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, Virginia Power has taken steps to minimize the impact on the environment. The new plant is expected to use at least ten percent biomass for fuel and was designed to be carbon-capture compatible, meaning that technology to capture CO2 can be added to the station when it becomes commercially available. Also, Virginia Power has announced plans to convert its coal units at Bremo power station 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. See Dominion Generation—Properties for more information on the projects above, as well as other projects under current development.

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 2008, 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 15% and 8%, respectively. During such time period the capacity of Dominion and Virginia Power’s electric generation fleet has grown.

Nuclear Regulatory Commission

All aspects of the operation and maintenance of 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.

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.

SPENT NUCLEAR FUEL

Under provisions of the Nuclear Waste Policy Act of 1982, Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Companies’ contracts with the DOE. In January 2004, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims against the DOE requesting damages in connection with its failure to commence accepting spent nuclear fuel. A trial occurred in May 2008 and post-trial briefing and argument concluded in July 2008. On October 15, 2008, the Court issued an opinion and order for Dominion in the amount of approximately $155 million, which includes approximately $112 million in damages incurred by Virginia Power for spent fuel-related costs at its Surry and North Anna power stations and approximately $43 million in damages incurred for spent nuclear fuel-related costs at Dominion’s Millstone power station through June 30, 2006. Judgment was entered by the Court on October 28, 2008. In December 2008, the government appealed the judgment to the U. S. Court of Appeals for the Federal Circuit and the appeal was docketed. In March 2009, the Federal Circuit granted the government’s request to stay the appeal. With the exception of one case, the Federal Circuit has issued such stays in all other currently pending appeals from spent fuel damages awards. In November 2009, Dominion and Virginia Power filed a motion to lift the stay and the government has opposed this motion. Once the stay is lifted, briefing on the appeal will take place. Payment of any damages will not occur until the appeal process has been resolved. Dominion and Virginia Power cannot predict the outcome of this matter; however, in the event that they recover damages, such recovery, including amounts attributable to joint owners, is not expected to have a material impact on their results of operations.


 

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A lawsuit was also filed for Dominion’s Kewaunee power station, and that lawsuit is presently stayed through March 15, 2010. The Companies will continue to manage their spent fuel until it is accepted by the DOE.

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. Additionally, 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 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. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that their 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 require Dominion and Virginia Power to incur additional expenses.

Virginia Power could be subject to penalties as a result of mandatory reliability standards. As a result of EPACT, owners and operators of bulk power transmission systems, including Virginia Power, are subject to mandatory reliability standards enacted by NERC and enforced by FERC. If Virginia Power is found not to be in compliance with the mandatory reliability standards it could be subject to sanctions, including substantial monetary penalties.

Dominion’s and Virginia Power’s costs of compliance with environmental laws are significant, and the cost of compliance with future environmental laws could adversely affect their cash flow and profitability. 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, environ -

mental monitoring, installation and operation of pollution control equipment and purchase of allowances and/or offsets. Additionally, they 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. Costs of compliance with environmental regulations could adversely affect their results of operations and financial condition, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets Dominion and Virginia Power operate increases. 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 related to emissions. 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.

If federal and/or state requirements are imposed on energy companies mandating further emission reductions, including limitations on GHG emissions and reductions in SO2, NOx and mercury emissions and other environmental requirements relating to coal ash disposal and cooling water, such requirements may result in compliance costs that alone or in combination could make some of Dominion’s and Virginia Power’s electric generating units uneconomical to maintain or operate. As related to GHG emissions, the U.S. Congress, environmental advocacy groups, other organizations and some state and 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 federal legislation and/or EPA regulation, and possibly additional state legislation and/or regulation, may pass resulting in the imposition of limitations on GHG emissions from fossil fuel-fired electric generating units. In December 2009, the EPA issued their Final Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, finding that GHGs “endanger both the public health and the public welfare of current and future generations.” If GHGs become regulated pollutants under the CAA, the Companies will be required to obtain permits for GHG emissions from new and modified facilities and amend operating permits for major sources of GHG emissions. Until these actions occur, and the EPA establishes guidance for GHG permitting, including Best Available Control Technology, it is not possible to determine the impact on Dominion’s and Virginia Power’s facilities that emit GHGs. However, such limits could make certain of the Companies’ electric generating units uneconomical to operate in the long term, unless there are significant advancements in the commercial availability and cost of carbon capture and storage technology. There are also potential impacts on Dominion’s natural gas businesses as federal GHG legislation 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


 

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regulations including regions where Dominion has operations. For example, Massachusetts has implemented regulations requiring reductions in CO2 emissions and the Regional Greenhouse Gas Initiative, a cap and trade program covering CO2 emissions from power plants in the Northeast, which affects several of Dominion’s facilities. In addition, a number of bills have been introduced in Congress that would require GHG emissions reductions from fossil fuel-fired electric generation facilities, natural gas facilities and other sectors of the economy, although none have yet been enacted. Compliance with these GHG emission reduction requirements may require 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 expected 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 associated regulations, and the selected compliance alternatives. As a result, Dominion and Virginia Power cannot estimate the effect of any such legislation on their results of operations, financial condition or their customers.

The base rates of Virginia Power are subject to regulatory review. As a result of the Regulation Act, in 2009, the Virginia Commission commenced its review of the base rates of Virginia Power under a modified cost-of-service model. Such rates will be set based on analyses of Virginia Power’s costs and capital structure, as reviewed and approved in regulatory proceedings. Under the Regulation Act, the Virginia Commission may, in a proceeding initiated in 2009, reduce rates or order a credit to customers if Virginia Power is deemed to be earning more than 50 basis points above an ROE level to be established by the Virginia Commission in that proceeding. After the initial rate case, the Virginia Commission will review the base rates of Virginia Power biennially and may order a credit to customers if it is deemed to have earned an ROE more than 50 basis points above an ROE level established by the Virginia Commission and may reduce rates if Virginia Power is found to have had earnings in excess of the established ROE level during two consecutive biennial review periods.

The rates of Virginia Power’s electric transmission operations and Dominion’s gas transmission operations are subject to regulatory review. Revenue provided by Virginia Power’s electric transmission operations and Dominion’s gas transmission operations is based primarily on rates approved by FERC. 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 trued-up 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. Dominion is required to file a general base rate review for the FERC-jurisdictional services of Cove Point, effective not later than July 31, 2011. At that time, Cove Point’s cost of service will be reviewed by the FERC, with rates set based on analyses of the Company’s costs and capital structure. The FERC-jurisdictional rates for DTI are the subject of a 2005 FERC-approved settlement. That settlement established a rate moratorium that continues in effect through June 30, 2010.

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. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of Dominion’s merchant generation, E&P assets and other unregulated business activities could be adversely impacted. In Virginia Power’s regulated operations, conservation could negatively impact its results depending on the regulatory treatment of the associated impacts. Should Virginia Power be required to invest in conservation measures that resulted in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. Dominion and Virginia Power are unable to determine what impact, if any, conservation will have on their financial condition or results of operations.

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 hedge its output, then these changes in market prices could adversely affect its financial results.

In addition, 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.


 

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Lastly, Dominion is exposed to credit risks of its counterparties and the risk that one or more counterparties may fail to perform under their obligations to make payments. Defaults by suppliers or other counterparties may adversely affect Dominion’s financial results.

Dominion’s merchant power business may be negatively affected by possible FERC actions that could weaken competition in the wholesale markets or affect pricing rules in the RTO markets. Dominion’s merchant generation stations operating in PJM, MISO and ISO-NE sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these merchant generation stations to take advantage of market price opportunities, but also exposes 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 or Dominion’s authority to sell power at market-based rates could adversely impact the future results of its merchant power business.

Dominion’s and Virginia Power’s operations could be affected by terrorist activities and catastrophic events that could result from terrorism. In the event that their generating facilities or other infrastructure assets are subject to potential terrorist activities, such activities could significantly impair their operations and result in a decrease in revenues and additional costs to repair and insure their assets, which could have a material adverse effect on their business. The effects of potential terrorist activities could also include the risk of a significant decline in the U.S. economy, and the decreased availability and increased cost of insurance coverage, any of which could negatively impact the Companies’ results of operations and financial condition.

Dominion and Virginia Power have incurred increased capital and operating expenses and may incur further costs for enhanced security in response to such risks.

There are risks associated with the operation of nuclear facilities. Dominion and Virginia Power operate nuclear facilities that are subject to risks, including their ability to dispose of spent nuclear fuel, the disposal of which is subject to complex federal and state regulatory constraints. These risks also include the cost of and ability to maintain adequate reserves for decommissioning, costs of replacement power, costs of plant maintenance and exposure to potential liabilities arising out of the operation of these facilities. Decommissioning trusts and external insurance coverage are maintained to mitigate the financial exposure to these risks. However, it is possible that decommissioning costs could exceed the amount in the trusts or that costs arising from claims could exceed the amount of any insurance coverage.

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 as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform

under a contract. 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 underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, Dominion uses derivatives primarily to hedge its merchant generation and gas and oil production. The use of such derivatives to hedge future electric and gas 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 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 they have 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.

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 in the location and 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, counterparty credit strength and price volatility. These market risks are beyond their control and could adversely affect their results of operations and future growth.

For additional information concerning derivatives and commodity-based trading contracts, see Market Risk Sensitive Instruments and Risk Management in Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 2 and 8 to the Consolidated Financial Statements.

Dominion’s E&P business is affected by factors that cannot be predicted or controlled and that could damage facilities, disrupt production or reduce the book value of Dominion’s assets. Factors that may affect Dominion’s financial results include, but are not limited to: damage to or suspension of operations caused by weather, fire, explosion or other events at Dominion’s or third-party gas and oil facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities, Dominion’s ability to acquire additional land positions in competitive lease areas, drilling cost pressures, operational risks that could disrupt production, drilling rig availability and geological and other uncertainties inherent in the estimate of gas and oil reserves.

Declines in natural gas and oil prices could adversely affect Dominion’s financial results by causing a permanent write-down of its natural gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues from the production of proved gas and oil reserves using trailing twelve month average natural gas and oil prices (the ceiling test) at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.


 

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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. Management anticipates that they will be required to seek additional financing in the future to fund current and future plant construction and expansion projects and may not be able to secure such financing on favorable terms. In addition, 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, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Further, 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. Any of these or other factors could adversely affect their ability to realize the anticipated benefits from the plant construction and expansion projects.

An inability to access financial markets could affect the execution of Dominion’s and Virginia Power’s business plans. Dominion and Virginia Power rely on access to short-term money markets, longer-term capital markets and banks 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 primarily associated with Dominion’s merchant generation and gas and oil production. Management believes that the Companies will maintain sufficient access to these financial markets based upon their current credit ratings and market reputation. However, certain disruptions outside of Dominion’s and Virginia Power’s control may increase their cost of borrowing or restrict their ability to access one or more financial markets. Such disruptions could include delays in the current economic recovery, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, changes to their credit ratings or the failure of financial institutions on which they rely. Restrictions on the Companies’ ability to access financial markets may 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 then could 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. A

decline in the market value of the assets may increase the funding requirements of the obligations to decommission Dominion’s nuclear plants and under its pension and other postretirement benefit 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 benefit plans. If the decommissioning trust funds and benefit plan assets are not successfully managed, Dominion’s results of operations and financial condition could be negatively affected.

Changing rating agency requirements could negatively affect Dominion’s and Virginia Power’s growth and business strategy. As of February 1, 2010, Dominion’s senior unsecured debt is rated A-, stable outlook, by Standard & Poor’s; Baa2, stable outlook, by Moody’s; and BBB+, stable outlook, by Fitch. As of February 1, 2010, Virginia Power’s senior unsecured debt is rated A-, stable outlook, by Standard & Poor’s; Baa1, positive outlook, by Moody’s; and A-, stable outlook, by Fitch. In order to maintain current credit ratings in light of existing or future 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 by Standard & Poor’s, Moody’s or Fitch 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 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

As of December 31, 2009, 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


 

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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.

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, 2009; 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.

In 2007, Dominion sold its non-Appalachian E&P operations, whose historical results are included in the Corporate and Other segment. Dominion’s remaining Appalachian E&P operations, which are included in the Dominion Energy segment, do not qualify as significant gas and oil producing activities for 2009 or 2008. As a result, the following information only details Dominion’s gas and oil operations for 2007.

 

 

COMPANY-OWNED PROVED GAS AND OIL RESERVES

Estimated net quantities of proved gas and oil reserves were as follows:

 

At December 31,    2007
      Proved
Developed
   Total
Proved

Proved gas reserves (bcf)

   636    1,019

Proved oil reserves (000 bbl)

   12,613    12,613

Total proved gas and oil reserves (bcfe)(1)

   712    1,095

bbl = barrel

(1) Ending reserves for 2007 included 0.3 million barrels of oil/condensate and 12.3 million barrels of NGLs.

Certain of Dominion’s subsidiaries file Form EIA-23 with the DOE which reports gross proved reserves, including the working interest shares of other owners, for properties operated by such subsidiaries. The proved reserves reported in the previous table represent Dominion’s share of proved reserves for all properties, based on its ownership interest in each property. For properties Dominion operates, the difference between the proved reserves reported on Form EIA-23 and the gross reserves associated with the Dominion-owned proved reserves reported in the previous table, does not exceed five percent. Estimated proved reserves as of December 31, 2007 are based upon studies for each of Dominion’s properties prepared by its staff engineers and audited by Ryder Scott Company, L.P., an engineering firm registered by the Texas Board of Professional Engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines.

 

 

QUANTITIES OF GAS AND OIL PRODUCED

Quantities of gas and oil produced follow:

 

Year Ended December 31,    2007

Gas production (bcf)

  

U.S.

   206

Canada

   8

Total gas production

   214

Oil production (000 bbl)

  

U.S.

   11,626

Canada

   559

Total oil production

   12,185

Total gas and oil production (bcfe)

   287

bbl = barrel

The average realized price per mcf of gas with hedging results (including transfers to other Dominion operations at market prices) during 2007 was $5.99 and the average realized prices without hedging results per mcf of gas produced was $6.63. The average realized prices for oil with hedging results during 2007 was $37.78 per barrel and the average realized price without hedging results was $50.08 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during 2007 was $1.39.

 

 

NET WELLS DRILLED IN THE CALENDAR YEAR

The number of net wells completed follows:

 

Year Ended December 31,    2007

Development:

  

U.S.

  

Productive

   804

Dry

   10

Total U.S.

   814

Canada

  

Productive

   10

Dry

  

Total Canada

   10

Total wells drilled (net)

   824

 

 

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, 2009, Dominion Generation’s total utility and merchant generating capacity was 27,507 MW.


 

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The following table lists Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2009:

VIRGINIA POWER UTILITY GENERATION

 

Plant    Location    Net Summer
Capability (MW)
   

Percentage

Net Summer
Capability

 

Coal

       

Mt. Storm

   Mt. Storm, WV    1,560     

Chesterfield

   Chester, VA    1,235     

Chesapeake

   Chesapeake, VA    595     

Clover

   Clover, VA    433 (1)   

Yorktown

   Yorktown, VA    323     

Bremo

   Bremo Bluff, VA    227     

Mecklenburg

   Clarksville, VA    138     

North Branch

   Bayard, WV    74     

Altavista

   Altavista, VA    63     

Polyester

   Hopewell, VA    63     

Southampton

   Southampton, VA    63         

Total Coal

      4,774      26

Gas

       

Ladysmith (CT)

   Ladysmith, VA    783     

Remington (CT)

   Remington, VA    608     

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    245     

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

      3,977      22   

Nuclear

       

Surry

   Surry, VA    1,598     

North Anna

   Mineral, VA    1,596 (2)       

Total Nuclear

      3,194      18   

Oil

       

Yorktown

   Yorktown, VA    818     

Possum Point

   Dumfries, VA    786     

Gravel Neck (CT)

   Surry, VA    198     

Darbytown (CT)

   Richmond, VA    168     

Chesapeake (CT)

   Chesapeake, VA    115     

Possum Point (CT)

   Dumfries, VA    72     

Low Moor (CT)

   Covington, VA    48     

Northern Neck (CT)

   Lively, VA    47     

Kitty Hawk (CT)

   Kitty Hawk, NC    31         

Total Oil

      2,283      12   

Hydro

       

Bath County

   Warm Springs, VA    1,802 (3)   

Gaston

   Roanoke Rapids, NC    220     

Roanoke Rapids

   Roanoke Rapids, NC    95     

Other

   Various    3         

Total Hydro

      2,120      12   

Biomass

       

Pittsylvania

   Hurt, VA    83        

Various

       

Other

   Various    11        
          16,442         

Power Purchase Agreements

        1,861      10   

Total Utility Generation

        18,303      100

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

(1) Excludes 50% undivided interest owned by ODEC.
(2) Excludes 11.6% undivided interest owned by ODEC.
(3) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.

 

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DOMINION MERCHANT GENERATION

 

Plant    Location    Net Summer
Capability (MW)
   

Percentage

Net Summer
Capability

 

Coal

       

Kincaid

   Kincaid, IL    1,158 (1)   

Brayton Point

   Somerset, MA    1,105     

State Line

   Hammond, IN    515     

Salem Harbor

   Salem, MA    314     

Morgantown

   Morgantown, WV    25 (1),(2)       

Total Coal

      3,117      34

Nuclear

       

Millstone

   Waterford, CT    2,023 (3)   

Kewaunee

   Kewaunee, WI    556         

Total Nuclear

      2,579      28   

Gas

       

Fairless (CC)

   Fairless Hills, PA    1,196 (4)   

Elwood (CT)

   Elwood, IL    712 (1),(5)   

Manchester (CC)

   Providence, RI    432         

Total Gas

      2,340      25   

Oil

       

Salem Harbor

   Salem, MA    440     

Brayton Point

   Somerset, MA    438         

Total Oil

      878      10   

Wind

       

Fowler Ridge

   Benton County, IN    150 (1),(6)   

NedPower Mt. Storm

   Grant County, WV    132 (1),(7)       

Total Wind

      282      3   

Various

       

Other

   Various    8        

Total Merchant Generation

        9,204      100

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

(1) Subject to a lien securing the facility’s debt.
(2) Excludes 50% partnership interest owned by RCM Morgantown Power, Ltd. and Hickory Power LLC.
(3) Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation.
(4) Includes generating units that Dominion operates under leasing arrangements.
(5) Excludes 50% membership interest owned by J. POWER Elwood, LLC.
(6) Excludes 50% membership interest owned by BP.
(7) 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 them, or permits issued by various local, state and 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 are involved in various legal proceedings. Dominion and Virginia Power believe that the ultimate resolution of these proceedings will not have a material adverse effect on their financial position, liquidity or results of operations.

See Regulation in Item 1. Business, Future Issues and Other Matters in Item 7. MD&A, and Notes 14 and 23 to the Consolidated Financial Statements for additional information on various environmental, rate matters and other regulatory proceedings to which Dominion and Virginia Power are parties.

In December 2006 and January 2007, Dominion submitted self-disclosure notifications to EPA Region 8 regarding three E&P facilities in Utah that potentially violated CAA permitting requirements. In July 2007, a third party purchased Dominion’s E&P assets in Utah, including these facilities. In September 2008, Dominion received a draft Consent Decree related to the potential CAA infractions, which imposes obligations on Dominion’s subsidiary, DEPI and the purchaser, including payment of a civil penalty to the U.S. Department of Justice in the amount of $250,000. In November 2009, the U.S. District Court, District of Utah, Northern Division entered the final Consent Decree. Per Dominion’s asset purchase agreement, the third-party purchaser paid the civil penalty as required by the Consent Decree.

In February 2009, DCP and its contractor Sheehan Pipeline Construction Company received notice from Maryland’s Attorney General’s Office that the Maryland Department of the Environment (MDE) had referred to them, for enforcement, alleged violations of state wetlands, water pollution, and sediment pollution laws during construction of a pipeline associated with the Cove Point expansion project in Maryland. This served notice that the MDE would be seeking civil penalties for some of the alleged violations. In May 2009, Dominion received a letter from the MDE detailing all alleged violations and their maximum penalty liabilities. In December 2009, the MDE entered into a consent order with Dominion and Sheehan dismissing its claims. Per the consent order, Dominion and Sheehan denied the MDE’s allegations, and agreed to pay $175,000 to the MDE and restore a pond. Of that penalty, Sheehan and its subcontractor agreed to pay $119,000; Dominion agreed to pay $56,000 and restore the pond.

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 Dominion’s State Line and Kincaid power stations. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April, Dominion received a Notice and Finding of Violations from the EPA claiming new source review violations, new source performance standards violations, and Title V permit program violations pursuant to the CAA and the respective State Implementation Plans. Dominion is currently evaluating the impact of the Notice and cannot predict the outcome of this matter.

Item 4. Submission of Matters to a Vote of Security Holders

None.


 

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Executive Officers of Dominion

 

 

Name and Age    Business Experience Past Five Years(1)

Thomas F. Farrell II (55)

   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; President and COO of Dominion and CNG from January 2004 to December 2005.

Mark F. McGettrick (52)

   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; President and CEO—Generation of Virginia Power from January 2003 to January 2006.

Paul D. Koonce (50)

   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; CEO—Energy of Virginia Power from January 2004 to January 2006.

David A. Christian (55)

   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 (52)

   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; Vice President—Fossil & Hydro System Operations of Virginia Power from December 2003 to March 2005.

Gary L. Sypolt (56)

   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; President—Transmission of Virginia Power from January 2003 to January 2006.

Robert M. Blue (42)

   Senior Vice President – Public Policy and Environment of Dominion and DRS from February 2010 to date; 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; Managing Director State Affairs and Corporate Policy of DRS from July 2005 to August 2006; Counselor to former Virginia Governor Mark R. Warner and Director of Policy from January 2002 to May 2005.

Mary C. Doswell (51)

   Senior Vice President—Alternative Energy Solutions of Virginia Power and DRS from April 2009 to date; Senior Vice President—Regulation and Integrated Planning of Dominion, Virginia Power and DRS from October 2007 to March 2009; Senior Vice President and CAO of Dominion from January 2003 to September 2007; President and CEO of DRS from January 2004 to September 2007.

James K. Martin (45)

   Senior Vice President—Regulation and Integrated Planning of Virginia Power and DRS from April 2009 to date; Senior Vice President—Business Development & Generation Construction of Virginia Power and DEI from October 2007 to March 2009; Vice President—Fossil & Hydro Technical Services of Virginia Power from January 2006 to September 2007; Vice President—Fossil & Hydro Technical Services of DEI from April 2005 to September 2007; Vice President—Business Development of DEI from June 2000 to April 2005.

Steven A. Rogers (48)

   Senior Vice President and CAO of Dominion and President and CAO of DRS from October 2007 to date; Senior Vice President and Chief Accounting Officer of Dominion and Virginia Power from January 2007 to September 2007 and CNG from January 2007 to June 2007; Senior Vice President and Controller of Dominion and CNG from April 2006 to December 2006; Senior Vice President and Principal Accounting Officer of Virginia Power from April 2006 to December 2006; Vice President and Controller of Dominion and CNG and Vice President and Principal Accounting Officer of Virginia Power from June 2000 to April 2006.

James F. Stutts (65)

   Senior Vice President and General Counsel of Dominion and Virginia Power from January 2007 to date and CNG from January 2007 to June 2007; Vice President and General Counsel of Dominion from September 1997 to December 2006; Vice President and General Counsel of Virginia Power from January 2002 to December 2006; Vice President and General Counsel of CNG from September 1999 to December 2006.

 

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Name and Age    Business Experience Past Five Years(1)

Carter M. Reid (41)

   Vice President—Governance and Corporate Secretary of Dominion and Virginia Power from December 2007 to date; Vice President—Governance of Dominion from October 2007 to November 2007; Director Executive Compensation and Legal Advisor of DRS from February 2006 to September 2007; Director Executive Compensation of DRS from July 2003 to January 2006.

Ashwini Sawhney (60)

   Vice President and Controller (Chief Accounting Officer) of Dominion from July 2009 to date; 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; Vice President—Accounting of Dominion and CNG from April 2006 to December 2006; Assistant Corporate Controller of Dominion from June 2002 to April 2006; Assistant Corporate Controller of Virginia Power from January 1999 to April 2006.

 

(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 New York Stock Exchange. At February 1, 2010, there were approximately 148,000 registered shareholders, including approximately 54,000 certificate holders. Discussions of the restrictions on Dominion’s payment of dividends required by this Item are contained in Dividend Restrictions in Item 7. MD&A and Note 21 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 2009 and 2008. Quarterly information concerning stock prices and dividends is disclosed in Note 29 to the Consolidated Financial Statements.

The following table presents certain information with respect to Dominion’s common stock repurchases during the fourth quarter of 2009.

 

 

DOMINION PURCHASES OF EQUITY SECURITIES

 

Period   

Total
Number
of Shares
(or Units)
Purchased(1)

  

Average
Price
Paid per
Share
(or Unit)

   

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(2)

10/1/09 – 10/31/09

   1,334    $ 34.50      N/A    53,971,148 shares/$ 2.68 billion

11/1/09 – 11/30/09

   211    $ 34.90      N/A    53,971,148 shares/$ 2.68 billion

12/1/09 – 12/31/09

   7,176    $ 37.78      N/A    53,971,148 shares/$ 2.68 billion

Total

   8,721    $ 37.21 (3)    N/A    53,971,148 shares/$ 2.68 billion

 

(1) Amount reflects registered shares tendered by employees to satisfy tax withholding obligations on vested restricted stock.
(2) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Board of Directors in February 2005, as modified in June 2007.
(3) Represents the weighted-average price paid per share during the fourth quarter of 2009.

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 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)                         

2009

   $ 101    $ 75    $ 190    $ 97    $ 463

2008

   $ 115    $ 83    $ 163    $ 80    $ 441

 

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Item 6. Selected Financial Data

DOMINION

 

Year Ended December 31,    2009    2008     2007     2006     2005
(millions, except per share amounts)                            

Operating revenue

   $ 15,131    $ 16,290      $ 14,816      $ 17,276      $ 16,766

Income from continuing operations before extraordinary item and cumulative effect of changes in accounting principles(1)

     1,287      1,836        2,705        1,530        1,033

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

     —        (2     (8     (150     6

Extraordinary item, net of tax(1)

     —        —          (158     —          —  

Net income attributable to Dominion

     1,287      1,834        2,539        1,380        1,033

Income from continuing operations before extraordinary item and cumulative effect of changes in accounting principles per common share—basic

     2.17      3.17        4.15        2.19        1.51

Net income attributable to Dominion per common share—basic

     2.17      3.17        3.90        1.97        1.51

Income from continuing operations before extraordinary item and cumulative effect of changes in accounting principles per common share—diluted

     2.17      3.16        4.13        2.17        1.50

Net income attributable to Dominion per common share—diluted

     2.17      3.16        3.88        1.96        1.50

Dividends paid per share

     1.75      1.58        1.46        1.38        1.34

Total assets

     42,554      42,053        39,139        49,296        52,683

Long-term debt

     15,481      14,956        13,235        14,791        14,653

 

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

2009 results include a $435 million after-tax charge in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings. For more information see 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 E&P properties.

2008 results include a $136 million after-tax net income benefit due to the reversal of deferred tax liabilities associated with the planned sale of Peoples and Hope. In addition, 2008 includes $109 million after-tax charges reflecting other-than-temporary declines in the fair value of certain securities held as investments in nuclear decommissioning trusts.

2007 results include a $1.5 billion after-tax net income 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 as discussed in Note 4 to the Consolidated Financial Statements. 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 regulation to the Virginia jurisdiction of Virginia Power’s generation operations in 2007 resulted in a $158 million after-tax extraordinary charge. See Note 2 to the Consolidated Financial Statements.

2006 results include a $104 million after-tax charge resulting from the write-off of certain regulatory assets related to the planned sale of Peoples and Hope. In addition, 2006 reflects the net impact of the discontinued operations of Canadian E&P operations sold in June 2007 and the Peaker facilities sold in March 2007. Discontinued operations for the Peaker facilities included a $164 million after-tax impairment charge to reduce the facilities’ carrying amount to its estimated fair value less cost to sell. See Note 4 to the Consolidated Financial Statements.

2005 results include a $272 million after-tax loss related to the discontinuance of hedge accounting for certain gas and oil derivatives, resulting from an interruption of gas and oil production in the Gulf of Mexico caused by Hurricanes Katrina and Rita.

VIRGINIA POWER

 

Year Ended December 31,    2009    2008    2007      2006     2005  
(millions)                            

Operating revenue

   $ 6,584    $ 6,934    $ 6,181      $ 5,603    $ 5,712   

Income from operations before extraordinary item and cumulative effect of changes in accounting principles

     356      864      606        478      485   

Loss from discontinued operations, net of tax

                           (471

Extraordinary item, net of tax

               (158            

Net income

     356      864      448        478      10   

Balance available for common stock

     339      847      432        462      (6

Total assets

     20,118      18,802      17,063        15,683      15,449   

Long-term debt

     6,213      6,000      5,316        3,619      3,888   

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

2007 results reflect the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations, which resulted in a $158 million after-tax extraordinary charge. See Note 2 to the Consolidated Financial Statements.

2005 results reflect the net impact of the discontinued operations of Virginia Power’s indirect wholly-owned subsidiary, Virginia Power Energy Marketing, Inc., which was transferred to Dominion through a series of dividend distributions on December 31, 2005.

 

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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

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Accounting Matters

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Dominion

  Ÿ  

Results of Operations

  Ÿ  

Segment Results of Operations

  Ÿ  

Selected Information—Energy Trading Activities

Ÿ  

Virginia Power

  Ÿ  

Results of Operations

  Ÿ  

Segment Results of Operations

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Liquidity and Capital Resources

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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,” “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, including hurricanes, high winds and severe storms, 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 greenhouse gases 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;

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Unplanned outages of the Companies’ generation facilities;

Ÿ  

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

   

ion’s and Virginia Power’s liquidity position and the underlying value of their assets;

Ÿ  

Counterparty credit risk;

Ÿ  

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

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

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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;

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Changes in federal and state tax laws and regulations;

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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  

Completion and timing of the planned monetization of Dominion’s Marcellus Shale assets;

Ÿ  

Changes in rules for RTOs in which Dominion and Virginia Power participate, including changes in rate designs and new and evolving capacity models;

Ÿ  

Political and economic conditions, including the threat of domestic terrorism, inflation and deflation;

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Changes to regulated electric rates collected by Virginia Power, including the outcome of the base rate review initiated in 2009;

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.

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

 

 

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

Dominion 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 con -


 

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

 

 

dition or results of operations under different conditions or using different assumptions. Dominion and Virginia Power have discussed the development, selection and disclosure of each of these policies with the Audit Committee of their Board 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.

As discussed further in Note 2 to the Consolidated Financial Statements, in April 2007, Virginia Power reapplied accounting guidance for cost-based regulation to the Virginia jurisdiction of its generation operations resulting in a $259 million ($158 million after-tax) extraordinary charge and the reclassification of $195 million ($119 million after-tax) of unrealized gains from AOCI related to nuclear decommissioning trust funds. This established a $454 million long-term regulatory liability for amounts previously collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s nuclear generation stations, in excess of the related ARO. In connection with the reapplication of this guidance, Virginia Power prospectively changed certain of its accounting policies for the Virginia jurisdiction of its generation operations to those used by cost-of-service rate-regulated entities. Other than the extraordinary item previously discussed, the overall impact of these changes was not material to Virginia Power’s results of operations or financial condition in 2007.

As discussed in Note 14 to the Consolidated Financial Statements, in February 2010, Virginia Power filed a revised Stipulation and Recommendation with the Virginia Commission that could resolve its pending rate proceedings in Virginia. Virginia Power’s 2009 results include a charge of $782 million ($477 million after-tax) representing its best estimate of the probable outcome of this matter. Of this amount, $700 million ($427 million after-tax) represents a partial refund of 2008 revenues and other amounts, and $82 million ($50 million after-tax) represents an expected refund of 2009 revenues collected from customers as a result of the implementation of a base rate increase that became effective on an interim basis on September 1, 2009. Of the total $782 million pre-tax charge, $523 million was recorded in operating revenue, $129 million was recorded in electric fuel and other energy-related purchases expense, and $130 million was

recorded in other operations and maintenance expense in Virginia Power’s Consolidated Statement of Income. The charge resulted in a $259 million decrease in regulatory assets, reflecting the write off of $129 million of previously deferred fuel costs and $130 million of previously deferred RTO costs since recovery is no longer probable based on the proposed February 2010 Stipulation, as well as a $473 million increase in regulatory liabilities with the remainder recorded to other receivables and payables in Virginia Power’s Consolidated Balance Sheet. Dominion’s 2009 results include an additional charge of $12 million ($8 million after-tax) recorded in other operations and maintenance expense, reflecting the write-off of previously deferred RTO costs since recovery is no longer probable based on the proposed February 2010 Stipulation.

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. In 2006, Dominion wrote off $166 million of its regulatory assets as a result of the planned sale of Peoples and Hope to Equitable since the recovery of those assets was no longer probable. In January 2008, Dominion and Equitable announced the termination of that agreement, primarily due to the continued delays in achieving final regulatory approvals. Dominion continued to seek other offers for the purchase of these utilities and in July 2008 entered into an agreement with the SteelRiver Buyer to sell Peoples and Hope and recognized a benefit of $47 million due to the re-establishment of certain of these regulatory assets. In September 2009, Dominion recorded a reduction to these regulatory assets of $22 million. The Companies currently believe the recovery of their regulatory assets is probable. See Notes 13 and 14 to the Consolidated Financial Statements.

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. 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. AROs currently reported in the Consolidated Balance Sheets were measured during a period of historically low interest 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 2009, 2008 and 2007, Dominion recognized $89 million, $94 million and $99 million, respectively, of accretion, and expects to incur $88 million in 2010. In 2009, 2008 and 2007, Virginia Power recognized


 

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$35 million, $38 million and $38 million, respectively, of accretion, and expects to incur $36 million in 2010. Upon reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of its generation operations, Virginia Power began recording accretion and depreciation associated with utility nuclear decommissioning AROs, formerly charged to expense, as an adjustment to the regulatory liability for nuclear decommissioning trust funds previously discussed, in order to match the recognition for rate-making purposes.

A significant portion of the Companies’ AROs relates to the future decommissioning of their nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2009, Dominion’s nuclear decommissioning AROs totaled $1.3 billion, representing approximately 81% of its total AROs. At December 31, 2009, Virginia Power’s nuclear decommissioning AROs totaled $587 million, representing approximately 92% 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 selection of these cost escalation rates is dependent on subjective factors which are considered to be a critical assumption.

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. As a result of the updated decommissioning cost studies and applicable escalation rates obtained in 2009, 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 examined by tax authorities with full knowledge of all relevant information. At December 31, 2009, Dominion had $291 million and Virginia Power had $121 million of unrecognized tax benefits. For the majority of these unrecognized tax benefits, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility.

Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of 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, 2009, Dominion had established $62 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 the 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 to 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.


 

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

 

 

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

As of December 31, 2009, Dominion reported $3.4 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 2009, 2008 and 2007 annual tests did not result in the recognition of any goodwill impairment.

As a result of the 2007 disposition of Dominion’s non-Appalachian E&P operations, goodwill was allocated to such operations based on the relative fair values of the E&P operations being disposed of and the Appalachian portion being retained. The impairment test performed on the goodwill allocated to the retained Appalachian operations showed no impairment. Also, in connection with the 2007 segment realignment, the goodwill allocated to Dominion’s three gas distribution subsidiaries was tested for impairment during the fourth quarter of 2007. This interim test did not result in the recognition of any goodwill impairment, as the estimated fair values of these businesses exceeded their respective carrying amounts.

In December 2009, Dominion made the decision to retain Hope and include it with Dominion East Ohio in Dominion’s gas distribution business within the Dominion Energy segment. Goodwill was allocated from the Corporate and Other segment to the Dominion Energy segment based on the relative fair values of Hope and Peoples, which remained held-for-sale within the Dominion Corporate and Other segment. Dominion did not perform an interim impairment test as no events occurred that would more-likely-than-not reduce the reporting units’ fair values below their carrying values.

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 non-Appalachian E&P operations, Peoples and Hope and certain DCI operations, negotiated sales prices were used as fair value for the tests conducted in 2009, 2008 and 2007. 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.

 

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 circumstances that 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.

In the third quarter of 2008, Dominion tested SO2 emissions allowances held for consumption, with a carrying amount of $144 million, as a result of a decline in the market value of such allowances resulting from the July 2008 D.C. Appeals Court decision vacating CAIR that affected certain emission allowance surrender ratios. Based on the results of Dominion’s test, including an analysis of recoverability through undiscounted cash flows from plant operations, no impairment charges were recognized. In December 2008, the court issued a decision to reinstate CAIR that resulted in an increase in the market value of SO2 allowances. As a result of a decline in SO2 allowance prices during 2009, Dominion updated its fair value assessment of excess allowances quarterly in 2009. Based on the result of these assessments, Dominion did not record any impairment adjustments.

In 2006, Dominion tested Dresden for impairment and concluded that its carrying amount, as well as the estimated cost to complete, was recoverable based on the probability of continued construction and use at that time. As part of Dominion’s ongoing asset review to improve its return on invested capital, Dominion began the process of exploring the sale of Dresden in the second quarter of 2007. Non-binding indicative bids were received and based on its evaluation of these bids, Dominion believed that it was likely that Dresden would be sold rather than completed and operated in its merchant fleet. This change in intended use represented a triggering event for Dominion to evaluate whether it could recover the carrying amount of its investment in Dresden. This analysis indicated that the carrying amount of Dresden would not be recovered. As a result, in the second quarter of 2007, Dominion recognized a $387 million ($252 million after- tax) impairment charge to reduce Dresden’s carrying amount to its estimated fair value in connection with the planned sale of Dresden, which closed in September 2007.


 

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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  

Historical return analysis to determine 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;

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Expected inflation and risk-free interest rate assumptions; and

Ÿ  

Investment allocation of plan assets. The strategic target asset allocation for Dominion’s pension funds is 34% U.S. equity, 12% non-U.S. equity, 22% fixed income, 7% real estate and 25% other, such as private equity investments.

Strategic investment policies are established for each of 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.

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 2009 and 2008, and 8.75% for 2007. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 7.75% for 2009 and 2008, and 8.00% for 2007. 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 6.60% in 2009, compared to 6.60% and 6.50%, respectively, in 2008 and 6.20% and 6.10%, respectively, in 2007. Dominion selected a discount rate of 6.60% for determining its December 31, 2009 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, 2009 is 8.0% and is expected to gradually decrease to 4.90% 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 )%    $ 12    $ 5

Long-term rate of return on plan assets

   (0.25 )%      12      2

Healthcare cost trend rate

   1.00     N/A      24

In addition to the effects on cost, at December 31, 2009, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $126 million and its accumulated postretirement benefit obligation by $45 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $191 million. See Note 22 to the Consolidated Financial Statements for additional information.

ACCOUNTING FOR GAS AND OIL OPERATIONS

Dominion follows the full cost method of accounting for gas and oil E&P activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depleted using the units-of-production method. Capitalized costs in the depletable base are subject to a ceiling test prescribed by the SEC. Dominion performs the ceiling test quarterly and recognizes asset impairments to the extent that total capitalized costs exceed the ceiling. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a cost pool.

Dominion’s estimate of proved reserves requires a large degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to develop the proved reserves, and estimates of future production from the proved reserves. Dominion’s estimated proved reserves as of December 31, 2009 are based upon studies for each of its properties prepared by staff engineers and audited by Ryder Scott Company, L.P. Calculations were prepared using standard geological and engineering methods generally accepted by the petro -


 

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leum industry and in accordance with SEC guidelines. Given the volatility of natural gas and oil prices, it is possible that Dominion’s estimate of discounted future net cash flows from proved natural gas and oil reserves that is used to calculate the ceiling could materially change in the near-term.

The process to estimate reserves is imprecise, and estimates are subject to revision. If there is a significant variance in any of Dominion’s estimates or assumptions in the future and revisions to the value of its proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur. See Notes 2, 4 and 27 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 amounts 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 $355 million and $341 million of accrued unbilled revenue at December 31, 2009 and 2008, 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.

Other

ACCOUNTING STANDARDS AND POLICIES

During 2009, 2008 and 2007, 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,
   2009    $ Change     2008    $ Change     2007
(millions, except EPS)                           

Net Income attributable to Dominion

   $ 1,287    $ (547   $ 1,834    $ (705   $ 2,539

Diluted EPS

     2.17      (0.99     3.16      (0.72     3.88

 

Overview

2009 VS. 2008

Net income attributable to Dominion decreased by 30%. Unfavorable drivers include an impairment charge related to the carrying value of Dominion’s E&P properties due to declines in gas and oil prices during the first quarter of 2009 and a charge in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings. Favorable drivers include higher margins in Dominion’s merchant generation operations and a higher contribution from Dominion’s gas transmission operations due to the completion of the Cove Point expansion project.

2008 VS. 2007

Net income attributable to Dominion decreased by 28%. Unfavorable drivers include the absence of a $2.1 billion after-tax gain on the sale of Dominion’s U.S. non-Appalachian E&P business and the absence of ongoing earnings from this business due to the sale. Favorable drivers include the absence of the following items incurred in 2007:

Ÿ  

Charges related to the sale of the majority of its E&P operations;

Ÿ  

An impairment charge related to the sale of Dresden;

Ÿ  

An extraordinary charge in connection with the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations; and

Ÿ  

A charge in connection with the termination of a long-term power sales agreement at State Line.

Additional favorable drivers include the reinstatement of annual fuel rate adjustments for the Virginia jurisdiction of Virginia Power’s generation operations effective July 1, 2007, a higher contribution from merchant generation operations and the reversal of deferred tax liabilities associated with the planned sale of Peoples and Hope. Diluted EPS decreased to $3.16 and includes $0.36 of share accretion resulting from the repurchase of shares in 2007 with proceeds received from the sale of the majority of Dominion’s E&P operations.


 

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Analysis of Consolidated Operations

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

 

Year Ended) December 31,   2009   $ Change     2008     $ Change     2007  
(millions)                            

Operating Revenue

  $ 15,131   $ (1,159   $ 16,290      $ 1,474      $ 14,816   

Electric fuel and other energy-related purchases

    4,285     262        4,023        400        3,623   

Purchased electric capacity

    411            411        (28     439   

Purchased gas

    2,381     (1,017     3,398        623        2,775   

Net Revenue

    8,054     (404     8,458        479        7,979   

Other operations and maintenance

    3,795     538        3,257        (868     4,125   

Gain on sale of U.S. non-Appalachian E&P business

        (42     42        3,677        (3,635

Depreciation, depletion and amortization

    1,139     105        1,034        (334     1,368   

Other taxes

    491     (8     499        (53     552   

Other income (loss)

    181     239        (58     (160     102   

Interest and related charges

    894     57        837        (324     1,161   

Income tax expense

    612     (267     879        (904     1,783   

Loss from discontinued operations, net of tax

        2        (2     6        (8

Extraordinary

item, net of tax

                      158        (158

An analysis of Dominion’s results of operations follows:

2009 VS. 2008

Net Revenue decreased 5%, primarily reflecting:

Ÿ  

A $614 million decrease in net revenue from electric utility operations primarily due to a charge for the proposed settlement of Virginia Power’s 2009 rate case proceedings;

Ÿ  

An $86 million decrease in sales of gas production from E&P operations primarily reflecting the expiration of VPP royalty interests; and

Ÿ  

A $21 million decrease in net gas revenue from retail energy marketing operations primarily due to lower prices ($39 million), partially offset by higher volumes ($18 million).

These decreases were partially offset by:

Ÿ  

A $161 million increase from merchant generation operations, primarily reflecting lower fuel expenses due to the impact of lower commodity prices ($190 million) and higher sales volumes primarily from fewer scheduled nuclear refueling outages and higher demand for natural gas generation ($143 million), partially offset by lower sales prices ($79 million) and increased fuel consumption ($93 million) at certain fossil generation facilities;

Ÿ  

A $158 million increase related to gas transmission operations largely due to the completion of the Cove Point expansion project; and

Ÿ  

A $70 million increase in net electric revenue from retail energy marketing operations primarily attributable to higher volumes ($36 million) and the acquisition of a retail energy marketing business in September 2008 ($34 million).

Other operations and maintenance expense increased 17%, primarily reflecting the combined effects of:

Ÿ  

A $455 million ceiling test impairment charge related to the carrying value of E&P properties due to declines in natural gas and oil prices;

Ÿ  

A $142 million write-off of previously deferred RTO costs in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings;

Ÿ  

A $74 million increase in salaries, wages and benefits largely due to higher pension and other postretirement benefit costs; and

Ÿ  

A $69 million increase reflecting the absence of the net benefit recorded in 2008 related to the re-establishment of a regulatory asset in connection with the planned sale of Peoples and Hope ($47 million) and a 2009 charge due to a reduction in this regulatory asset ($22 million); partially offset by

Ÿ  

A $103 million downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service;

Ÿ  

The absence of a $59 million charge related to the impairment of a DCI investment sold in 2008; and

Ÿ  

A $29 million decrease largely due to the deferral of transmission-related expenditures collectible under certain rate adjustment clauses.

DD&A increased 10%, principally due to higher depreciation from property additions ($100 million) and higher amortization due to increased consumption of emissions allowances ($37 million), partially offset by decreased DD&A reflecting lower gas and oil production ($19 million) and a decrease in DD&A rates ($28 million) at Dominion’s E&P properties.

Other income increased $239 million primarily due to the impact of net realized gains (including investment income) on merchant nuclear decommissioning trust funds in 2009 as compared to net realized losses (net of investment income) in 2008.

Interest and related charges increased 7%, primarily due to the impact of additional borrowings ($34 million) and the absence of a $23 million benefit related to the redemption of Virginia Power’s Callable and Puttable Enhanced Securities in 2008.

Income tax expense decreased by 30%, primarily reflecting lower pre-tax income in 2009.

2008 VS. 2007

Net Revenue increased 6%, primarily reflecting:

Ÿ  

A $500 million increase from merchant generation operations, primarily reflecting higher realized sales prices for nuclear and fossil operations ($500 million) and the absence of a charge related to the termination of a long-term power sales agreement at State Line in 2007 ($231 million), partially offset by lower overall sales volumes due to outages at certain fossil and nuclear generating facilities ($105 million), increased fuel expenses primarily reflecting the impact of higher commodity prices ($54 million) and increased fuel consumption ($72 million) at certain fossil generation facilities;

Ÿ  

A $453 million increase in net revenue from electric utility operations resulting primarily from the reinstatement of annual fuel rate adjustments, effective July 1, 2007, for the Virginia jurisdiction of Virginia Power’s generation operations, with deferred fuel accounting for over- or under-recoveries of fuel costs; and


 

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

 

 

Ÿ  

A $129 million increase in sales of gas production from Dominion’s remaining E&P operations, primarily due to:

  Ÿ  

A $70 million increase in sales from Appalachian properties due to higher prices ($51 million) and increased production ($19 million); and

  Ÿ  

Increased production associated with VPP royalty interests ($59 million).

These increases were partially offset by:

Ÿ  

A $656 million decrease due to the sale of the majority of U.S. E&P operations in 2007, reflecting the absence of $1.4 billion of net revenue from these operations, partially offset by the absence of a $541 million charge predominantly due to the discontinuance of hedge accounting for certain gas and oil derivatives and subsequent changes in the fair value of these derivatives; and a $171 million charge primarily due to the termination of VPP agreements in connection with the sale.

Other operations and maintenance expense decreased 21%, primarily reflecting the combined effects of:

Ÿ  

A $443 million decrease reflecting the sale of the majority of U.S. E&P operations, including the absence of charges incurred in 2007 in connection with the sale;

Ÿ  

The absence of a $387 million impairment charge in 2007 related to the sale of Dresden; and

Ÿ  

The absence of $54 million of litigation-related charges in 2007.

Gain on sale of U.S. non-Appalachian E&P business primarily reflects the absence of the gain of $3.6 billion resulting from the completion of the sale of Dominion’s U.S. non-Appalachian E&P business in 2007.

DD&A decreased 24%, principally due to decreased gas and oil production resulting from the sale of the majority of U.S. E&P operations in 2007, partially offset by an increase in rates and production from remaining E&P operations, property additions and an increase in depreciation rates for utility generation assets.

Other taxes decreased 10%, primarily due to lower severance and property taxes resulting from the sale of the majority of U.S. E&P operations in 2007.

Other income (loss) was a loss of $58 million in 2008 as compared to income of $102 million in 2007, primarily due to higher other-than-temporary impairments for nuclear decommissioning trust investments.

Interest and related charges decreased 28%, resulting principally from the absence of charges related to the early extinguishment of outstanding debt associated with Dominion’s debt tender offer completed in July 2007 and lower interest rates on variable rate debt.

Income tax expense decreased by 51%, primarily due to lower pre-tax income in 2008 largely reflecting the absence of the gain realized in 2007 from the sale of Dominion’s U.S. non-Appalachian E&P business.

Extraordinary item reflects the absence of a $158 million after-tax charge in 2007 in connection with the reapplication of guidance for accounting for certain types of regulation to the Virginia jurisdiction of Virginia Power’s generation operations.

Outlook

In order to deliver favorable returns to investors, Dominion’s strategy is to focus 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 stable credit ratings. In 2010, Dominion believes its operating businesses will provide stable growth in net income on a per share basis, including the impact of higher expected average shares outstanding. Dominion’s anticipated 2010 results reflect the following significant factors:

Ÿ  

The absence of an impairment charge in 2009 related to the carrying value of Dominion’s E&P properties due to declines in gas and oil prices;

Ÿ  

The absence of a charge in 2009 in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings;

Ÿ  

A benefit from rate adjustment clauses associated with the recovery of construction-related financing costs for Bear Garden and Virginia City Hybrid Energy Center;

Ÿ  

Minimal exposure to commodity prices reflecting hedges in place due to Dominion’s commodities hedging program;

Ÿ  

Favorable interest rates reflecting hedges in place for Dominion’s and Virginia Power’s planned debt issuances in 2010;

Ÿ  

The planned monetization of Dominion’s Marcellus Shale acreage with proceeds used to offset its anticipated 2010 equity financing needs;

Ÿ  

Implementation of operations and maintenance cost-containment measures; and

Ÿ  

An expected after-tax loss, as well as after-tax expenses, including transaction and benefit-related costs, in connection with the February 2010 sale of Peoples discussed in Note 4 to the Consolidated Financial Statements.

If the final resolution of Virginia Power’s 2009 rate case proceedings differs materially from management’s expectations it could adversely affect Dominion’s results of operations, financial condition and cash flows. See Forward-Looking Statements for additional factors that could cause actual results to differ materially from predicted results.

 

 

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,
  2009     2008     2007
     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

  $ 384      $ 0.65      $ 380      $ 0.65      $ 415   $ 0.64

Dominion Generation

    1,281        2.16        1,227        2.11        756     1.15

Dominion Energy

    517        0.87        470        0.81        387     0.59

Primary operating segments

    2,182        3.68        2,077        3.57        1,558     2.38

Corporate and Other

    (895     (1.51     (243     (0.41     981     1.50

Consolidated

  $ 1,287      $ 2.17      $ 1,834      $ 3.16      $ 2,539   $ 3.88

 

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DVP

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

 

Year Ended December 31,    2009    % Change     2008    % Change     2007

Electricity delivered (million MWh)

   81.4    (3 )%    84.0    (1 )%    84.7

Degree days:

            

Cooling(1)

   1,477    (9   1,621    (10   1,794

Heating(2)

   3,747    9      3,426    (2   3,500

Average electric distribution customer accounts (thousands)(3)

   2,404    1      2,386    1      2,361

Average retail energy marketing customer accounts (thousands)(3)

   1,718    7      1,601    3      1,551

 

(1) Cooling degree days are units measuring the extent to which the average daily temperature is greater than 65 degrees, and are calculated as the difference between 65 degrees and the average temperature for that day.
(2) Heating degree days are units measuring the extent to which the average daily temperature is less than 65 degrees, and are calculated as the difference between 65 degrees and the average temperature for that day.
(3) Thirteen-month average.

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

2009 VS. 2008

 

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

Regulated electric sales:

    

Customer growth

   $ 5      $ 0.01   

Rate adjustment clause(1)

     13        0.02   

Other(2)

     (6     (0.01

Storm damage and service restoration—distribution operations(3)

     5        0.01   

Retail energy marketing operations

     (1       

Other

     (12     (0.02

Share dilution

            (0.01

Change in net income contribution

   $ 4      $   

 

(1) Reflects the incremental impact of a rate adjustment clause associated with the recovery of transmission-related expenditures.
(2) Primarily reflects the impact of unfavorable economic conditions on customer usage and other factors.
(3) Reflects a decrease in storm damage and service restoration costs associated with electric distribution operations resulting from less severe weather during 2009.

 

2008 VS. 2007

 

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

Regulated electric sales:

    

Weather

   $ (14   $ (0.03

Customer growth

     9        0.01   

Other

     (9     (0.01

Storm damage and service restoration—distribution operations(1)

     (10     (0.02

Interest expense

     (9     (0.01

Retail energy marketing operations

     (2     (0.01

Share accretion

            0.08   

Change in net income contribution

   $ (35   $ 0.01   

 

(1) Reflects an increase in storm damage and service restoration costs resulting from more severe weather during 2008.

Dominion Generation

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

 

<
Year Ended December 31,    2009    % Change     2008    % Change     2007

Electricity supplied (million MWh):

            

Utility

   81.4    (3 )%    84.0    (1 )%    84.7

Merchant

   48.0    6