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, 20092010
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 whetherif 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.
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 in Rule 12b-2 of the Act).
Dominion Resources, Inc. Yes ¨ No x Virginia Electric and Power Company Yes ¨ No x
The aggregate market value of Dominion Resources, Inc. common stock held by non-affiliates of Dominion was approximately $22.3 billion based on the closing price of Dominion’s common stock as reported on the New York Stock Exchange as of the last day of the registrant’s most recently completed second fiscal quarter. Dominion is the sole holder of Virginia Electric and Power Company common stock. As of January 31, 2011, Dominion had 580,849,359 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding.
DOCUMENT INCORPORATED BY REFERENCE.
(a) Portions of Dominion’s 2011 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.
Item Number | Page Number | |||
1 | ||||
Part I | ||||
1. | 3 | |||
1A. | 21 | |||
1B. | 24 | |||
2. | 24 | |||
3. | 28 | |||
4. | 28 | |||
29 | ||||
Part II | ||||
5. | 31 | |||
6. | 32 | |||
7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 33 | ||
7A. | 53 | |||
8. | 55 | |||
9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 126 | ||
9A. | 126 | |||
9A(T). | 128 | |||
9B. | 129 | |||
Part III | ||||
10. | 129 | |||
11. | 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. | 155 | |||
Part IV | ||||
15. | 156 |
Virginia Electric and Power Company
Item Number |
| Page Number |
| |||
1 | ||||||
1. | 5 | |||||
1A. | 22 | |||||
1B. | 26 | |||||
2. | 26 | |||||
3. | 29 | |||||
4. | 29 | |||||
30 | ||||||
5. | 31 | |||||
6. | 32 | |||||
7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 33 | ||||
7A. | 50 | |||||
8. | 53 | |||||
9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 124 | ||||
9A. | 124 | |||||
9B. | 127 | |||||
10. | 127 | |||||
11. | 128 | |||||
12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 150 | ||||
13. | Certain Relationships and Related Transactions, and Director Independence | 150 | ||||
14. | 151 | |||||
15. | 152 |
The following abbreviations or acronyms used in this Form 10-K are defined below:
Abbreviation or Acronym | Definition | |
2009 Base Rate Review | Order entered by the Virginia Commission in January 2009, pursuant to the Regulation Act, initiating reviews of the base rates and terms and conditions of all investor-owned utilities in Virginia | |
ABO | Accumulated benefit obligation | |
AOCI | Accumulated other comprehensive income (loss) | |
AFUDC | Allowance for funds used during construction | |
AIP | Annual Incentive Plan | |
AMR | Automated meter reading program deployed by East Ohio | |
Antero | Antero Resources | |
AROs | Asset retirement obligations | |
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ASLB | Atomic Safety and Licensing Board | |
bcf | Billion cubic feet | |
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Bear Garden | A 580 MW intermediate combined cycle, natural gas-fired power station under construction in Buckingham County, Virginia | |
BP | BP | |
Brayton Point | Brayton Point power station | |
BREDL | Blue Ridge Environmental Defense League | |
BRP | Dominion Retirement Benefit Restoration Plan | |
BVP | Book Value Performance | |
CAA | Clean Air Act | |
CAIR | Clean Air Interstate Rule | |
CAMR | Clean Air Mercury Rule | |
CAO | Chief | |
Carson-to-Suffolk line | Virginia Power project to construct an approximately 60-mile 500-kV transmission line in southeastern Virginia | |
CEO | Chief Executive Officer | |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act of 1980 | |
CD&A | Compensation Discussion and Analysis | |
CDEP | Connecticut Department of Environmental Protection | |
CDO | Collateralized debt obligation | |
CFTC | Commodity Futures Trading Commission | |
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 | |
Companies | Dominion and Virginia Power, collectively | |
CONSOL | CONSOL Energy, Inc. | |
COO | Chief Operating Officer | |
Cove Point | Dominion Cove Point LNG, LP | |
CWA | Clean Water Act | |
Dallastown | Dallastown Realty | |
DCI | Dominion Capital, Inc. | |
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DD&A | Depreciation, depletion and amortization expense | |
DEI | Dominion Energy, Inc. | |
Dodd-Frank Act | The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 | |
DOE | Department of Energy | |
Dominion | The legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries (other than Virginia Power) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries | |
Dominion Direct® | A dividend reinvestment and open enrollment direct stock purchase plan | |
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DPP | Dominion Pension Plan | |
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Dresden | Partially-completed merchant generation facility sold in 2007 | |
DRS | Dominion Resources Services, Inc. | |
DSM | Demand-side management | |
DTI | Dominion Transmission, Inc. | |
DVP | Dominion Virginia Power operating segment | |
E&P | Exploration & production | |
East Ohio | The East Ohio Gas Company, doing business as Dominion East Ohio | |
ECCP | Energy Conservation Council of Pennsylvania |
1 |
Glossary of Terms, continued
Abbreviation or Acronym | Definition | |
EPA | Environmental Protection Agency | |
EPACT | Energy Policy Act of 2005 | |
EPS | Earnings per share | |
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ERISA | The Employment Retirement Income Security Act of 1974 | |
ERO | Electric Reliability Organization | |
ESRP | Dominion 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 | |
GWSA | Global Warming Solutions Act | |
HAP | Hazardous air pollutant | |
Hayes-to-Yorktown line | Virginia Power project to construct an approximately eight-mile 230-kV transmission line in southeastern Virginia | |
Hope | Hope Gas, Inc., doing business as Dominion Hope | |
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IOGA | Independent Oil and Gas Association of West Virginia, Inc. | |
IRS | Internal Revenue Service | |
ISO | Independent system operator | |
ISO-NE | ISO New England | |
Joint Committee | U.S. Congressional Joint Committee on Taxation | |
June 2006 hybrids | 2006 Series A Enhanced Junior Subordinated Notes due 2066 | |
June 2009 hybrids | 2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to extensions no later than 2079 | |
Kewaunee | Kewaunee nuclear power station | |
Kincaid | Kincaid power station | |
kV | Kilovolt | |
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LIBOR | London Interbank Offered Rate | |
LIFO | Last-in-first-out inventory method | |
LNG | Liquefied natural gas | |
LTIP | Long-term incentive program | |
MACT | Maximum Achievable Control Technology | |
Manchester Street | Manchester Street power station | |
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MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
MDE | Maryland Department of the Environment | |
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 | |
Medicare Act | The Medicare Prescription Drug, Improvement and Modernization Act of 2003 | |
Medicare Part D | Prescription drug benefit introduced in the Medicare Act | |
MISO | Midwest Independent Transmission System Operators, Inc. | |
Millstone | Millstone nuclear power station | |
MNES | Mitsubishi Nuclear Energy Systems, Inc., a wholly-owned subsidiary of Mitsubishi Heavy Industries, Inc. | |
Moody’s | Moody’s Investors Service | |
Mt. Storm-to-Doubs line | Virginia Power project to rebuild approximately 96 miles of an existing 500-kV transmission line in Virginia and West Virginia | |
MW | Megawatt | |
MWh | Megawatt hour | |
NAV | Net asset value | |
NAAQS | National Ambient Air Quality Standards | |
NCEMC | North Carolina Electric Membership Corporation | |
NedPower | A wind-turbine facility joint venture with Shell in Grant County, West Virginia | |
NEIL | Nuclear Electric Insurance Limited | |
NEOs | Named executive officers | |
NERC | North American Electric Reliability Corporation | |
NGLs | Natural gas liquids | |
NO2 | Nitrogen dioxide |
2 |
Abbreviation or Acronym | Definition | |
Non-Employee Directors Plan | Non-Employee Directors Compensation Plan | |
North Anna | North Anna nuclear power station | |
North Carolina Commission | North Carolina Utilities Commission | |
North Carolina Settlement Approval Order | Order issued by the North Carolina Commission in December 2010 approving the Stipulation and Settlement Agreement filed by Virginia Power in connection with the ending of its North Carolina base rate moratorium | |
NOX | Nitrogen oxide | |
NPDES | National Pollutant Discharge Elimination System | |
NRC | Nuclear Regulatory Commission | |
NYMEX | New York Mercantile Exchange | |
NYSE | New York Stock Exchange | |
ODEC | Old Dominion Electric Cooperative | |
Ohio Commission | Public Utilities Commission of Ohio | |
OSHA | Occupational Safety and Health Administration | |
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 | |
PIPP | Percentage of Income Payment Plan | |
PIR | Pipeline Infrastructure Replacement program deployed by East Ohio | |
PJM | PJM Interconnection, LLC | |
PM&P | Pearl Meyer & Partners | |
PNG Companies LLC | An indirect subsidiary of Babcock & Brown Infrastructure Fund North America | |
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Regulation Act |
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REIT | Real estate investment trust | |
RGGI | Regional Greenhouse Gas Initiative | |
Riders C1 and C2 | Rate adjustment clauses associated with the recovery of costs related to certain DSM programs | |
Rider R | A rate adjustment clause | |
Rider S | A rate adjustment clause associated with the recovery of | |
Rider T | A rate adjustment | |
ROE | Return on equity | |
ROIC | Return on invested capital | |
RPM Buyers | The Maryland Public Service Commission, Delaware Public Service Commission, Pennsylvania Commission, New Jersey Board of Public Utilities and several other organizations representing consumers in the PJM region | |
RPS | Renewable Portfolio Standard | |
RTEP | Regional transmission expansion plan | |
RTO | Regional transmission organization | |
SAIDI | Metric used to measure electric service reliability, System Average Interruption Duration Index | |
Salem Harbor | Salem Harbor power station | |
SEC | Securities and Exchange Commission | |
SELC | Southern Environmental Law Center | |
September 2006 hybrids | 2006 Series B Enhanced Junior Subordinated Notes due 2066 | |
Shell | Shell WindEnergy, Inc. | |
SO2 | Sulfur dioxide | |
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Standard & Poor’s | Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc. | |
State Line | State Line power station | |
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TSR | Total shareholder return | |
UEX Rider | Uncollectible Expense Rider | |
U.S. | United States of America | |
US-APWR | Mitsubishi Heavy Industry’s Advanced Pressurized Water Reactor | |
VEBA | Voluntary Employees’ Beneficiary Association | |
VIE | Variable interest entity | |
Virginia |
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| A 585 MW (nominal) baseload carbon-capture compatible, clean coal powered electric generation facility under construction in Wise County, Virginia | |
Virginia Commission | Virginia State Corporation Commission |
3 |
Abbreviation or Acronym | Definition | |
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 | |
| Order issued by the Virginia Commission in March 2010 concluding Virginia Power’s 2009 Base Rate Review | |
VPDES | Virginia | |
VPP | Volumetric production payment | |
VSWCB | Virginia State Water Control Board | |
West Virginia Commission | Public Service Commission of West Virginia |
Part I
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 27,50027,615 MW of generation, 6,000generating capacity, 6,100 miles of electric transmission lines, 56,00056,800 miles of electric distribution lines, in Virginia and North Carolina, 12,00011,000 miles of natural gas transmission, gathering and storage pipeline 21,700and 21,800 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.less. Dominion also owns the nation’s largest underground natural gas storage system, operates approximately 942947 bcf of storage capacity and serves retail energy customers in twelve14 states.
Dominion is focused on expanding its investment in regulated electric generation, transmission and distribution and regulated electric and natural gas transmission and distribution infrastructure within and around its existing footprint. As a result, regulated capital projects will continue to receive priority treatment in its spending plans. Dominion expects this will increase its earnings contribution from regulated operations, while reducing the sensitivity of its earnings to commodity prices.
In 2010, Dominion announced plans to invest more than $10 billion over the next five years to expand and improve its regulated electric and natural gas businesses. A substantial portion of this investment will be essential to meet the anticipated increase in electricity demand in its service territory. Other drivers for the capital investment program include the need to construct infrastructure to handle the expected increase in natural gas production from the Marcellus Shale formation and upgrades to its gas distribution and electric transmission and distribution network. Dominion also announced that it may invest up to an additional $2 billion in its electric generating fleet to meet potential new environmental requirements.
Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations and natural gas and oil exploration and production in the Appalachian basin of the U.S.operations. Dominion’s operations are conducted through various subsidiaries, including Virginia Power.
Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and 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, 2009,2010, Dominion had approximately 17,90015,800 full-time employees, of which approximately 6,6005,900 employees are subject to collective bargaining agreements. As of December 31, 2009,2010, Virginia Power had approximately 7,4006,800 full-time employees, of which approximately 3,3003,000 employees are subject to collective bargaining agreements. See Note 23 for discussion of the Companies’ workforce reduction program.
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 DOMINIONAND 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.
ACQUISITIONSANDDISPOSITIONS
Following are significant acquisitions and divestitures by Dominion and Virginia Power during the last five years.
ASCQUISITIONALEOF KEWAUNEE NUCLEARE&P POWER STATIONROPERTIES
In July 2005,2010, Dominion completed the acquisitionsale of Kewaunee,substantially all of its Appalachian E&P operations, including its rights to associated Marcellus acreage, to a 556 MW facility in northeastern Wisconsinnewly-formed subsidiary of CONSOL for approximately $192 million in cash. The operations of Kewaunee are included in$3.5 billion. See Note 4 to the Dominion Generation operating segment.
ACQUISITIONOF USGEN NEW ENGLAND, INC. POWER STATIONSConsolidated Financial Statements for additional information.
In January 2005,2007, Dominion completed the acquisitionsale of three fossil-fuel fired generation facilitiesits non-Appalachian natural gas and oil E&P operations and assets for $642approximately $13.9 billion.
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 cash. The facilities include Brayton Point, a 1,551 MW facility in Somerset, Massachusetts; Salem Harbor, a 754 MW facility in Salem, Massachusetts;Texas and Manchester Street, a 432 MW facility in Providence, Rhode Island. The operations of these facilities are included in the Dominion Generation operating segment.New Mexico.
The historical results of the non-Appalachian E&P operations are included in the Corporate and Other segment. The historical results of the Appalachian E&P operations are included in the Dominion Energy segment.
SALEOF PEOPLES
In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The historical results of these operations are included in the Corporate and Other segment and presented in discontinued operations. See Note 4 to the Consolidated Financial Statements for additional information.
ASSIGNMENTOF 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 receivesreceived 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.
SALEOF E&P PROPERTIES
In 2007, Dominion completedThe overriding royalty interest was transferred to CONSOL as part of the sale of its non-Appalachian natural gas and oilsubstantially all of Dominion’s Appalachian 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.2010.
SALEOF 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, theThe results of these operations were reclassified to discontinued operations and are presented in the Corporate and Other segment.discontinued operations.
SALEOF DRESDEN
In September 2007, Dominion completed the sale of Dresden to AEP Generating Company for $85 million.
SALEOF CERTAIN DCIDCI 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.
TRANSFEROF 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.
SALEOF 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,August 2007, Dominion completed the sale of Peoples and netted after-tax proceeds of approximately $542 million. A more detailed descriptionGichner, LLC, all of the sale can be found in Note 4 toissued and outstanding shares of the Consolidated Financial Statements.
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, thatwhich includes its corporate, service company and other functions (including unallocated debt) and the net impact of Peoples and certain DCI operations, disposed of or to be disposed of, which are discussed in NoteNotes 4 and 25 to the Consolidated Financial Statements.Statements, respectively. In addition, 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 and storage | X | |||||||||
LNG import and storage | X | |||||||||
Producer services | X |
For additional financial information on businessoperating segments, including revenues from external customers, see Notes 1 andNote 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, which serve residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina.
In December 2010, Virginia Power announced its five-year investment plan, which includes spending approximately $4 billion to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability. The proposed electric delivery infrastructure projects are intended to address both continued population growth and increases in electricity consumption by the typical consumer.
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 changes in rates, 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
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service reliability hasand customer service have improved. The metric used to measure electric service reliability (System Average Interruption Duration Index,SAIDI, excluding major storm events)events, has also steadily improved. The three-year average SAIDI has improved from 139135 minutes at the end of 20042005 to 110114 minutes at the end of 2009.2010. Likewise, ASA has also shown significant improvement. The three-year average ASA has improved from 73 seconds at the end of 2005 to 42 seconds at the end of 2010. 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,moves forward, safety, operational performanceelectric service reliability 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 inElectric Regulation inVirginia underRegulation.
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. SeeFederalRegulations inRegulation 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
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, NERC compliance and execution of PJM’s RTEP.
The DVP Operating Segment of Dominion includes all of Virginia Power’s regulated electric transmission and distribution operations as discussed above, as well as Dominion’s nonregulated retail energy marketing operations.
Dominion’s retail energy marketing operations compete in nonregulated energy markets and have experienced strongcontinued to experience customer growth during the past few years. The retail business requires limited capital investment and currently employs fewer than 150approximately 160 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/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. SeeState Regulations andFederal Regulations inRegulation for additional information.
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. Pursuant to this legislation, the Virginia Commission initiated a review of Virginia Power’s base rates in 2009. A discussion of Virginia Power’s settlement of this case with the Virginia Commission is contained inElectric Regulation in Virginia underRegulation.
PROPERTIES
Virginia Power has approximately 6,0006,100 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’sPower’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 authorized in 2006, which are designed to improve the reliability of service to customers and the region,region—Meadow Brook-to-Loudoun and are subject to applicable state and federal permits and approvals.Carson-to-Suffolk.
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.rights-of-way. 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 anOn appeal and request for stay of the West Virginia Commission’s approval, which was subsequently denied by the SupremeECCP, the Pennsylvania Commonwealth Court of West Virginiaaffirmed in April 2009. An appeal ofMay 2010 the Pennsylvania Commission’s approval and subsequently denied a request for reargument 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.ECCP in June 2010. The Meadow
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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
As part of subsequent annual PJM RTEP processes, PJM authorized additional electric transmission upgrade projects including Hayes-to-Yorktown in December 2008 and Mt. Storm-to-Doubs in December 2010. In June 2010, the Virginia Commission authorized the construction of thesethe Hayes-to-Yorktown line along the proposed eight-mile route utilizing existing easements and property previously acquired for the transmission linesline right-of-way. In accordance with the Virginia Commission’s approval, approximately 4.2 miles of the Hayes-to-Yorktown line will be constructed overhead and approximately 3.8 miles will be installed underground in order to cross under the York River. The Hayes-to-Yorktown line is expected to cost approximately $63 million and, subject to receipt of all regulatory approvals, is expected to be completed by June 2012.
After more than 44 years of operation, portions of the 99-mile Mt. Storm-to-Doubs line and certain associated facilities are subjectapproaching the end of their expected service lives and require replacement with new facilities to maintain reliable service. Virginia Power owns and has been designated by PJM to rebuild the 96 miles of the line in West Virginia and Virginia, and The Potomac Edison Company owns and has been designated by PJM to rebuild the remaining three miles of the line in Maryland. Subject to applicable state and federal permitsregulatory approvals, Virginia Power’s portion of the rebuild project is expected to cost approximately $300 million and approvals.is expected to be completed by June 2015.
In addition, Virginia Power’s electric distribution network includes approximately 56,00056,800 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-waysrights-of-way that have been obtained from the apparent owner of real estate, but underlying titles have not been examined. Where right-of-waysrights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.
SOURCESOF 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. SeeDominion Generation for additional information.
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 itstransactions. DVP’s supply of gas to serve its customers is procured through market wholesalers or by Dominion Energy. SeeDominion 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 inProperties, 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 2004Revenue is based primarily on rates established by state regulatory authorities and 2007, revenues forstate law. Approximately 80% of revenue comes from serving Virginia jurisdictional retail load were based on capped rates through 2008. Additionally, fuel costscustomers. Rates 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 toare set using a modified cost-of-service rate model, subject to base rate caps that were 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 reviewThe cost of Virginia Power’s base rates. A discussion of
Virginia Power’s proposal in the case, including a settlement agreement to which itfuel and purchased power is a party, is contained inElectric Regulation inVirginia underRegulation.generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. Variability in earnings for Virginia Power’s generation operations results from changes in rates, the demand for services, which is primarily weather dependent, and labor and benefit costs, as well as the timing, duration and costs of scheduled and unscheduled outages. SeeRegulation—State Regulationsfor additional information, including a discussion of Virginia Power’s 2009 base rate case settlement with the Virginia Commission.
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 inProperties. The Generation
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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, primarily natural gas, and the demand for electricity, which is primarily dependent upon weather. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion manages electric and capacity price volatility of its merchant fleet by hedging a substantial portion of its expected near-term sales with derivative instruments and also entering into long-term power sales agreements, which should help mitigate the adverse impact onagreements. However, earnings from declineshave been adversely impacted due to a sustained decline in commodity prices, such as those experienced during 2008 and 2009.prices. Variability also results from changes in the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages.
COMPETITION
Dominion Generation Operating Segment—Dominion and Virginia Power
Retail choice was made availableVirginia Power’s generation operations are not subject to Virginia Power’ssignificant competition as only a limited number of its Virginia jurisdictional electric utility customers beginning January 1, 2003; however, no significant competition developed. In April 2007, the Virginia General Assembly passed legislation endinghave retail choice for most of these customers effective January 1, 2009.choice. SeeRegulation—State Regulations—Electric for more information. Currently, North Carolina does not offer retail choice to electric customers.
Dominion Generation Operating Segment—Dominion
Unlike Dominion Generation’s regulated generation fleet, its merchant generation fleet is dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that allows for a rate of return on its capital investments. Competition for the merchant fleet is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact the merchant fleet’s ability to profit from the sale of electricity and related products and services.
Dominion Generation’s merchant generation fleet owns and operates several facilities in the Midwest that operate within functioning RTOs. A significant portion of the output from these facilities is sold under long-term contracts, with expiration dates ranging from December 31, 2012 to August 31, 2017, and is therefore largely unaffected by competition.price competition during the term of these contracts. Following expiration of these contracts, earnings could be adversely impacted if prevailing prices for energy, capacity and ancillary services are lower than the levels currently received under these contracts.
Dominion Generation’s other merchant assets also operate within functioning RTOs and primarily compete on the basis of price. Competitors include other generating assets bidding to operate within the RTOs. These RTOs have clearly identified
market rules that ensure the competitive wholesale market is functioning properly. Dominion Generation’s merchant units have a variety of shortshort- 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. SeeState Regulations andFederal Regulations inRegulation for more information.
PROPERTIES
For a listing of Dominion’s and Virginia Power’s existing generation facilities, see Item 2. Properties.
Dominion Generation Operating Segment—Dominion and Virginia Power
Based on available generation capacity and current estimates of growth in customer demand in Virginia Power’sits utility service area, itVirginia Power will need additional generation capacity over the next ten years.decade. Virginia Power has announced a comprehensive generation growth program, referred to asPowering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the anticipated growing demand in its core market in Virginia. As part of this program, the followingSignificant projects have recently been completedunder construction or are in various stages of development:development include:
Ÿ | Bear Garden, which, once operational, will generate about 580 MW. This intermediate, combined-cycle, natural gas-fired power station and transmission interconnection line is estimated to cost $619 million, excluding financing costs. Construction is approximately 94% complete as of January 2011, with commercial operations expected to commence in the second quarter of 2011. |
Ÿ | The Virginia City Hybrid Energy Center located in Wise County, Virginia, which once operational, will generate about 585 MW. The baseload facility is estimated to cost $1.8 billion, excluding financing costs. Construction is approximately 79% complete as of January 2011, and commercial operations are expected to commence in the summer of 2012. |
Ÿ | A power station development project in Warren County, Virginia, intended to be developed as an intermediate, combined-cycle, natural gas-fired power station. In December 2010, the Virginia Department of Environmental Quality approved an air permit to construct the project. Subject to the receipt of additional regulatory approvals, the project is expected to generate more than 1,300 MW of electricity. If the project is approved, construction would begin in 2012, with commercial operations expected to commence by late 2014 or early 2015. |
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.
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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.
projects above, 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,May 2010, Virginia Power terminated a long-lead agreement withannounced its vendor with respectdecision to replace the reactor design identified in itspreviously selected for the potential third nuclear unit with the US-APWR technology.
In June 2010, Virginia Power and ODEC amended the COL application to reflect the selection of the US-APWR technology. In January 2011, Virginia Power and certain related equipment. A competitive process was initiated in 2009the DOE terminated their cooperative agreement to determine if vendors can provide an advancedshare equally the cost of developing a COL. The agreement references the technology reactor that could be licensed and built under terms acceptable topreviously selected by Virginia Power. If, as a resultDOE funding is not available under the agreement for activities related to the US-APWR technology. During the third and fourth quarters of this process,2010, Virginia Power choosesfiled several applications for environmental permits that would be needed to support future construction and operation of a different reactor design, it will amend its COL application, as necessary. third nuclear unit at North Anna.
Virginia Power has not yet committed to building a new nuclear unit.unit at North Anna. In October 2010, Virginia Power announced its decision to slow the development of the potential third reactor. Virginia Power will continue to pursue the COL, along with engineering and preliminary site development work, and will reassess a construction schedule prior to the issuance of the COL currently anticipated in 2013. In December 2010, Virginia Power and MNES reached an agreement regarding pre-construction, engineering, design and planning work in preparation for a possible new unit at North Anna. In February 2011, ODEC informed Virginia Power of its intent to no longer participate in the development of the new unit at North Anna. Virginia Power and ODEC are currently working together to finalize the terms and conditions of such withdrawal.
If Virginia Power decides to build the new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the Atomic Safety and Licensing BoardASLB of the NRC granted a request for a hearing on onepermitted BREDL to intervene in the proceeding. All of eightBREDL’s previous contentions filed by the Blue Ridge Environmental Defense League.in this proceeding have been dismissed. In August 2009, the Atomic Safety and Licensing Board dismissed this contention as moot, but in November 2009 admitted aOctober 2010, BREDL submitted two new contention filed by Blue Ridge Environmental Defense League.contentions that it seeks to litigate that Virginia Power filed a motion for reconsideration of this ruling that is pending beforehas opposed. No other persons sought to intervene in the Atomic Safety and Licensing
Board.proceeding. Absent additional admitted 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 increasein Virginia. In December 2010, Virginia Power and BP terminated their joint development agreement for wind energy projects. As a result of the renewabletermination, Virginia Power has acquired a sole development interest in several wind energy capacity ofdevelopment projects in Virginia. Virginia Power’s utility generation fleet.Power paid BP approximately $1.5 million to acquire BP’s interest in property jointly owned in Tazewell County, Virginia.
Dominion Generation Operating Segment—Dominion
In addition to thePowering Virginia projects, Dominion has invested in several wind farm projects. In December 2006, Dominion acquiredis a 50% interest in NedPower. NedPower consistsowner with BP of two phases totaling 264 MW. Thethe 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 inphase of Fowler Ridge. The first phase consistingPhase one has generating capacity of 300 MW achievedand is in 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.operation. In JuneDecember 2009, Dominion reachedclosed on an agreement with BP to split the 350 MW of development assets associated with the second phase of Fowler Ridge, with Dominion retaining 150 MW of these development assets. In December 2010, Dominion reached an agreement to sell its 150 MW share of 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.second phase to BP. 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 receiptthe approvals of all necessary permitsFERC and approvals.
In 2008 and 2009,the Indiana Utility Regulatory Commission, which are expected by the second quarter of 2011. Dominion completed two uprates totaling 120 MW at Fairless. Additionally, in January 2009, Dominion successfully implemented an NRC-approved 7% uprate at Unit 3will receive approximately $6 million of Millstone. This increasedproceeds from 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.sale.
SOURCESOF 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 inFuture Cash Payments for Contractual Obligations and Planned Capital Expenditures in Item 7. MD&A.
Nuclear FuelFuel——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 FuelFuel——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;regions, purchases from local producers in the Appalachian area;area, purchases from gas marketers;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 PowerPower——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 | 2010 Source | 2009 Source | 2008 Source | ||||||||||||||||
Coal(1) | 33 | % | 33 | % | 35 | % | 31 | % | 33 | % | 33 | % | |||||||||
Purchased power, net | 29 | 25 | 29 | ||||||||||||||||||
Nuclear(2) | 32 | 31 | 29 | 28 | 32 | 31 | |||||||||||||||
Purchased power, net | 25 | 29 | 28 | ||||||||||||||||||
Natural gas | 9 | 6 | 6 | 10 | 9 | 6 | |||||||||||||||
Oil | 1 | 1 | 2 | ||||||||||||||||||
Other(3) | 2 | 1 | 1 | ||||||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
(1) | Excludes ODEC’s |
(2) | Excludes ODEC’s 11.6% ownership interest in North Anna. |
(3) | Includes oil, hydro and biomass. |
SEASONALITY
Sales of electricity for Dominion Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree-days 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 NRC’s 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 20092010 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 other licensed, operating nuclear reactors,reactors: two at Millstone in Connecticut and one at Kewaunee in Wisconsin. A third Millstone unit ceased operations before Dominion acquired the power station. As part of Dominion’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunee’s trust after decommissioning is completed are required to be refunded to Wisconsin ratepayers.
Dominion believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Dominion will continue to monitor these trusts to ensure they meet the NRC’s 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$4.6 billion in 20092010 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 operateIn February 2011, the NRC renewed the operating license, extending Kewaunee’s operation an additional 20 years through December 21, 2033 with full2033. Full decommissioning of Kewaunee is expected 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.
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The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion and Virginia Power are shown in the following table.
NRC license expiration year | Most cost (2009 | Funds in trusts at December 31, 2009 | 2009 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 |
NRC license expiration year | Most recent cost estimate (2010 dollars) | Funds in trusts at December 31, 2010 | 2010 contributions to trusts | |||||||||||||
(dollars in millions) | ||||||||||||||||
Surry | ||||||||||||||||
Unit 1 | 2032 | $ | 541 | $ | 373 | $ | 1.1 | |||||||||
Unit 2 | 2033 | 562 | 368 | 1.2 | ||||||||||||
North Anna | ||||||||||||||||
Unit 1(1) | 2038 | 550 | 298 | 0.8 | ||||||||||||
Unit 2(1) | 2040 | 564 | 280 | 0.8 | ||||||||||||
Total (Virginia Power) | 2,217 | 1,319 | 3.9 | |||||||||||||
Millstone | ||||||||||||||||
Unit 1(2) | n/a | 424 | 317 | — | ||||||||||||
Unit 2 | 2035 | 651 | 385 | — | ||||||||||||
Unit 3(3) | 2045 | 680 | 374 | — | ||||||||||||
Kewaunee | — | |||||||||||||||
Unit 1(4) | 2013 | 658 | 502 | — | ||||||||||||
Total (Dominion) | $ | 4,630 | $ | 2,897 | $ | 3.9 |
(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, |
(4) | Kewaunee Unit 1 original license expiration year is |
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 and 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.customers. Revenue provided by its gas distribution operations is based primarily on rates established by the Ohio and West Virginia Commissions. The profitability of these businesses is dependent on Dominion’s ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from operating and maintenance expenditures, as well as changes in rates and the
demand for services, which can beare 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 Variablestraight-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.
Revenue from Dominion’s Appalachian E&P business generates income from the sale of natural gas transportation, gas storage 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, whichLNG storage and regasification services 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 impactbased 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.firm, fee-based contractual arrangements.
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. SeeRegulation—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. SeeState Regulations andFederal Regulations inRegulation for more information.
PROPERTIES
Dominion Energy’s gas distribution network is located in the states of Ohio and West Virginia. This network involves approximately 21,70021,800 miles of pipe, exclusive of service lines of two inches in diameter or less. The rights-of-way grants for many natural gas pipelines have been obtained from the actual owner of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with
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results that range from reimbursed relocation to revocation of permission to operate.
Dominion Energy has approximately 12,00011,000 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 349,000262,000 acres of operated leaseholds.
The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 942947 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.Point. Dominion Energy has about 134123 compressor stations with more than 747,000768,000 installed compressor horsepower.
Dominion Energy also owns about 1.3 TcfeIn July 2008, East Ohio launched the PIR program to replace approximately 20% of proved natural gasits 21,000-mile pipeline system. The project, which is anticipated to cost approximately $2.6 billion, primarily involves the replacement of East Ohio’s bare steel, cast iron, wrought iron and oil reservescopper pipe over a 25-year period. As part of this program, East Ohio will assume ownership of curb-to-meter service lines and produces approximately 137 million cubic feet equivalentwill be responsible for line repairs or replacement. In October 2008, the Ohio Commission approved cost recovery for an initial five-year period of natural gas and oil per day from its leasehold acreage and facility investments in Appalachia.the PIR program.
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,March 2010, Dominion completed a transactioncommenced construction of the Cove Point Pier Reinforcement Project. The $50 million project is intended to upgrade, expand and modify the existing pier at the Cove Point terminal to accommodate the next generation of LNG vessels (up to 267,000 cubic meters) that are much larger than what can currently be accommodated (no larger than 148,000 cubic meters). The project commenced with Anterothe south berth being taken temporarily out of service to assign drilling rightsaccommodate construction activities. In October 2010, Dominion requested and received FERC authorization 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 productionre-commence service from the assigned acreage. Dominion retainedsouth berth of the drilling rights in traditional formations both above and belowpier for vessels with cargo capacities of no greater than 148,000 cubic meters. When the Marcellus Shale interval and continues its conventional drilling programsouth berth was returned to service, construction commenced 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,north berth, which is designed to transport gas on a firm basiswas taken out of the Appalachian Basin in West Virginiaservice. In December 2010, Dominion
requested and southwestern Pennsylvaniareceived authorization to DTI’s interconnect with Texas Eastern Transmission Corporation at Oakford, Pennsylvania. An open season forplace 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.on January 21, 2011.
DominionDTI 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’sDTI’s West Virginia system. Construction started in 2009 and willis expected to be completed by the fourth quarter of 2012. The cost of the project will be paid for by rates charged to producers.
DominionDTI 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. DominionDTI 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.
DTI has announced the proposed development of a gas pipeline project, known as the Appalachian Gateway Project. The project is expected to provide approximately 484,000 dekatherms per day of firm transportation services for new Appalachian gas supplies from the supply areas in the Appalachian Basin in West Virginia and southwestern Pennsylvania to an interconnection with Texas Eastern Transmission, LP at Oakford, Pennsylvania. Plans call for construction to start in 2011, with transportation services to begin by September 2012. An open season concluded in September 2008 and the project is fully subscribed under long-term binding agreements. In June 2010, DTI filed a certificate application with the FERC seeking approval for the Appalachian Gateway project. DTI estimates the cost of the Appalachian Gateway project to be approximately $634 million.
In June 2010, DTI entered into a 15-year firm transportation agreement with the gas subsidiary of CONSOL. The project, known as the Northeast Expansion Project, is expected to provide approximately 200,000 dekatherms per day of firm transportation services for CONSOL’s Marcellus Shale natural gas production from various receipt points in central and southwestern Pennsylvania to a nexus of market pipelines and storage facilities in Leidy, Pennsylvania. The $97 million project will involve the construction by DTI of new compression facilities at three existing compressor stations in central Pennsylvania, subject to the receipt of regulatory approval. In November 2010, DTI filed a certificate application with FERC seeking approval for the Northeast Expansion Project. If the project is approved, construction is expected to begin in March 2012, with a projected in-service date of November 2012.
In August 2010, DTI entered into a 10-year lease agreement with TGP for firm capacity to move Marcellus shale natural gas supplies from TGP’s 300 Line pipeline system in northern Pennsylvania to its 200 Line pipeline system in upstate New York. The $46 million project, known as the Ellisburg-to-Craigs Project, is expected to have capacity of approximately 150,000 dekatherms per day. Subject to the receipt of regulatory approvals, the project will involve the construction by DTI of additional compression facilities and a new measurement and regulating station at the
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Craigs interconnect with TGP in New York. DTI filed a certificate application with FERC in November 2010. If the Ellisburg-to-Craigs Project is approved, construction is expected to begin in March 2012, with a planned in-service date of November 2012.
In January 2011, Dominion announced that DTI is developing a natural gas processing and fractionation facility near New Martinsville, West Virginia. Dominion reached an agreement with PPG Industries, Inc. to purchase 56 acres at the Natrium site where DTI plans to process natural gas and NGLs.
SOURCESOF ENERGY SUPPLY
Dominion Energy’s natural gas supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area and gas marketers. Dominion’s large underground natural gas storage network and the location of its pipeline system are a significant link between the country’s major interstate gas pipelines, including the Rockies Express East pipeline, and large markets in the Northeast and mid-Atlantic regions. Dominion’s pipelines are part of an interconnected gas transmission system, which provides access to supplies nationwide for local distribution companies, marketers, power generators and industrial and commercial customers.
Dominion’s underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Northeast, mid-Atlantic and Midwest regions. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transmission capacity. 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 Variablestraight fixed variable rate design at Dominion East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipelinespipeline 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
commodities that it transports, stores and actively markets and trades.
Corporate and Other
Corporate and Other Segment—Virginia Power
Virginia Power’s Corporate and Other segment primarily includes certain specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Corporate and Other Segment—Dominion
Dominion’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) and the net impact of Peoples and certain DCI operations, disposed of or to be disposed of, which
are discussed in NoteNotes 4 and 25 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.Statements, respectively. 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:
Ÿ | Compliance with applicable environmental laws, regulations and rules; |
Ÿ | Conservation and load management; |
Ÿ | Renewable generation development; |
Ÿ | Other generation development to maintain |
Ÿ | Improvements in other energy |
SeeGlobal Climate Change underRegulation—Environmental Regulations in this item for examples of the Companies’ efforts to reduce their impact on the environment. Environmental Compliance Dominion and Virginia Power remain committed to compliance with all applicable environmental laws, regulations and rules related to their operations. Additional information related to Dominion’s and Virginia Power’s environmental compliance obligations can be found in Note 23 to the Consolidated Financial Statements. Conservation and Load Management |
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Conservation plays a significant role in meeting the growing demand for electricity. Virginia re-regulation legislation enacted in 2007The Regulation Act provides incentives for energy conservation and sets a voluntary goal to reduce electricity consumption by retail customers in 2022 by ten percent of the amount consumed in 2006 through the implementation of conservation programs. A descriptionLegislation in 2009 added definitions of peak-shaving and energy efficiency programs and allowed for a margin on operating expenses and revenue reductions related to energy efficiency programs. Virginia Power’s DSM programs provide the first steps toward achieving the voluntary ten percent energy conservation goal.
Virginia Power continues to assess smart grid technologies through a demonstration designed to indicate how these technologies may enhance Virginia Power’s electric distribution system by allowing energy to be delivered more efficiently. The demonstration involves a limited deployment, within Virginia Power’s Virginia service territory, of smart meters that use digital technology to enable two-way communication between the meter and Virginia Power’s electric distribution system. Dependent upon the outcome of the demonstration and certain regulatory proceedings, Virginia Power may make a significant investment in replacing existing meters with Advanced Metering Infrastructure. The technology is intended to help customers monitor and control their energy use. It is also expected to lead to more efficient
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use of the power grid, which is expected to result in energy savings and lower environmental emissions.
Additionally, the conservation and load management plan includes the following DSM programs, is detailed below.which were approved by the Virginia Commission in March 2010:
Dominion
Ÿ | Residential Lighting Program—an instant, in-store discount on the purchase of qualifying compact fluorescent lights; |
Ÿ | Home Energy Improvement—energy audits and improvements for homes of low-income customers; |
Ÿ | Smart Cooling Rewards—incentives for residential customers who voluntarily enroll to allow Virginia Power to cycle their air conditioners and heat pumps during periods of peak demand; |
Ÿ | Commercial HVAC Upgrade Program—incentives for commercial customers to improve the energy efficiency of their heating and/or cooling units; and |
Ÿ | Commercial Lighting Program—incentives for commercial customers to install energy-efficient lighting. |
Virginia Power are workinghas also proposed a redesigned distributed generation program which was not approved in its original form by the Virginia Commission in 2010. Virginia Power plans to improve their own energy efficiency, bothseek Virginia Commission approval of the redesigned distributed generation program and several other DSM programs in using less fuel2011.
In September 2010, Virginia Power filed with the North Carolina Commission an application for approval and cost recovery of the DSM programs listed above, as well as the redesigned distributed generation program. In February 2011, the North Carolina Commission approved the five DSM programs listed above. The North Carolina Commission will make a decision regarding the appropriate rate making treatment for the programs in a separate proceeding. Virginia Power expects to producelaunch the same amountfive DSM programs within its North Carolina service territory in the second quarter of energy and2011, subject to use less energy in their operations. Recent upratescost recovery approval by the North Carolina Commission. Virginia Power’s request for approval of their facilities have resulted in significant increases inthe redesigned distributed generation capacity and lower emissions to meetprogram remains pending before the needs of their customers.North Carolina Commission.
Renewable Generation
Renewable energy is also an important component of a diverse and reliable energy mix. Both Virginia and North Carolina have
passed legislation setting targets for renewable power. Virginia Power is committed to meeting Virginia’s goals of 12% renewable power by 2022 and 15% by 2025 and North Carolina’s renewable portfolio standardRPS of 12.5% by 2021. In July 2009, Virginia Power applied toMay 2010, the Virginia Commission for approvalapproved Virginia Power’s participation in the state’s RPS program. As a participant, Virginia Power is permitted to participateseek recovery, through rate adjustment clauses, of costs of programs designed to meet RPS goals. Virginia Power plans to meet the respective RPS targets in Virginia’s renewable energy portfolio standard program. The application identifies a Renewable Portfolio Standard Plan for meeting Virginia’s goalsVirginia and includes a combination ofNorth Carolina by utilizing 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) atas well as the Virginia City Hybrid Energy Center.Center, which is expected to use at least 10% biomass. In addition, Virginia Power intends to purchase renewable energy certificates, as permitted by each RPS program, to meet any remaining annual requirement needs. Virginia Power continues to explore opportunities to develop new renewable facilities within its service territory, the energy attributes of which would qualify for inclusion in the RPS programs.
In June 2010, Virginia Power announced its plans to develop an integrated solar and battery storage demonstration project in
Halifax County, Virginia. The proposed facility is intended to manage, store, and optimize solar energy to regulate intermittency, enable peak shaving and increase grid reliability. In November 2010, the Virginia Tobacco Indemnification and Community Revitalization Commission approved a $5 million grant to help fund the proposed project. Other project participants are the Halifax County Industrial Development Authority, the University of Virginia and a battery storage manufacturer. Subject to approval by the Virginia Commission and final project development, the 4 MW facility is expected to be operational in 2013.
In addition, Dominion is a 50% owner of the NedPower wind energy facility in Grant County, West Virginia.NedPower. Dominion’s share of this project produces 132 MW of renewable energy.
Dominion hasis also acquired a 50% interest in a joint ventureowner with BP to developof the first phase of Fowler Ridge, wind-turbine facility in Benton County, Indiana. The first phase withwhich has a generating capacity of 300 MW reached full commercial operations in March 2009.MW. Dominion has a long-term agreement with the joint ventureFowler Ridge to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In June 2009,December 2010, Dominion reached an agreement with BP to splitsell its remaining share of the development assets of the final 350 MW phase. Under the agreement with BP, Dominion will own 150 MWsecond phase of the development assets and BP will retain the remaining development assets. Closing of this transaction was effective in December 2009.Fowler Ridge to BP.
Other Generation Development
Virginia Power has announced a comprehensive generation growth program, referred to asPowering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the growinganticipated growth in demand in theits core market of Virginia. Virginia Power expects that these investments collectively will provide the following benefits: expanded electricity production capability;capability, increased technological and fuel diversity;diversity and a reduction in the CO2 emission intensity of its generation fleet. A critical aspectOne component of thePowering Virginia program isinvolves consideration of the extent to which Virginia Power seeks tocan 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. The focus is on new generation because there is no current economically viable technological solution to retro-fit existing fossil-fueled technology to capture and store GHG emissions. Given that new generation units have useful lives of up to 55 years, Virginia Power will give full consideration toconsider CO2 and other GHG emissions when making these long-term decisions. SeeDominion Generation—Generation—Properties for more information.
Improvements in Other Energy Infrastructure
In December 2010, Virginia Power plansannounced its five-year investment plan, which includes spending approximately $4 billion to make a significant investment in improving the capabilities and reliability of its electricupgrade or add new transmission and distribution system.lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service.service, and are intended to address both continued population growth and increases in electricity consumption by the typical consumer. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed or to be developed in the future. SeeGlobal Climate Change underRegulations 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
related to our operations. Additional information related to our environmental compliance obligations can be foundfuture. SeeGlobal Climate Change underRegulation—Environmental Regulations in Note 23 to the Consolidated Financial Statements.
Energy Efficiency and Peak Shaving Programsthis item for more information.
In July 2009, Virginia Power filed withis taking measures to ensure that its electrical infrastructure can support the Virginia Commission an application for approval and cost recovery of eleven DSM programs.expected demand from electric vehicles, which have significantly lower carbon intensity than conventional vehicles. Virginia Power planshas partnered with Ford Motor Company to use DSM, along with its traditional and renewable supply-side resources, to meet its projected load growth overhelp prepare Virginia for the next 15 years. The DSMoperation of electric vehicles, in a collaboration that involves consumer outreach, educational 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 componentexchange 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:information on vehicle charging requirements.
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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,Prior to the Regulation Act, which significantly changed electricity regulation in Virginia, Virginia Power’s Virginia jurisdictional base rates were to be capped at 1999 levels until December 31, 2010, at which time Virginia was to convert to retail competition for its electric supply service. The Regulation Act ended capped rates two years early, on December 31, 2008, at which time retail competition was made available only to individual retail customers with a demand of more than 5 MW and non-residential retail customers who obtain Virginia Commission approval to aggregate their load to reach the 5 MW threshold. Individual retail customers are also permitted to purchase renewable energy from competitive suppliers if their incumbent electric utility does not offer a 100% renewable energy tariff.
The Regulation Act also authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. The Regulation Act provides for enhanced returns on capital expenditures on specific new generation projects, including but not limited to nuclear generation, clean coal/carbon capture compatible generation and renewable generation projects. The Regulation Act also continues statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.
Pursuant to the Regulation Act, the Virginia Commission entered an order in January 2009 initiating the 2009 Base Rate Review. In connection with the 2009 Base Rate Review, Virginia Power submitted base rate filings and accompanying schedules to the Virginia Commission during 2009. In February 2010, Virginia Power filed a revised Stipulation and Recommendation with the Virginia Commission, pursuant towhich had the Regulation Act, a petition to recover fromsupport of all of the interested parties, including the Staff of the 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 alsoCommission. Virginia Power’s fourth quarter 2009 results included a portioncharge of costs discussed further inFederal Regulations.$782 million ($477 million after-tax) representing its best estimate at the time of the probable outcome of the 2009 Base Rate Review. In a final order in June 2009,March 2010, the Virginia Commission approvedissued the Virginia Settlement Approval Order that concluded the 2009 Base Rate Review and resolved open issues relating to Virginia Power’s fuel factor and Rider T. An ROE issue relating to Riders R, S, C1 and C2 was also resolved.
The Virginia Settlement Approval Order included the following provisions:
Credits from 2008 Revenues
Ÿ | Credits to customers of $400 million from Virginia Power’s 2008 revenues to be applied against base rates and rider charges. |
Base Rates
Ÿ | No change in Virginia Power’s base rates in existence prior to September 1, 2009 until December 1, 2013 (unless emergency rate relief is warranted by statute); |
Ÿ | Refund increased revenues collected under the interim base rates since September 1, 2009; and |
Ÿ | An ROE of 11.9% (inclusive of a performance incentive of 60 basis points) for use in the Virginia Commission’s assessment in the upcoming biennial rate review of Virginia Power’s earnings. |
FTR Credits
Ÿ | Credits to customers of $129 million, inclusive of any carrying charge, relating to revenues from FTRs for the period July 1, 2007 through June 30, 2009. |
Generation Riders R and S
Ÿ | An ROE of 12.3% (inclusive of a 100 basis point statutory enhancement) for the 2010 rate year. |
Transmission Rider T
Ÿ | Waiver of recovery, effective January 1, 2011, of deferred RTO start-up and administrative costs in the amount of $197 million (including carrying charges) that were previously approved for recovery through Rider T. |
DSM Riders C1 and C2
Ÿ | An ROE of 11.3% for the 2010 rate year. |
Commencing in 2011, the Virginia Commission will conduct biennial reviews of approximately $218 million through Rider T, which includes approximately $150 million of transmission-related costs that were traditionally incorporated inVirginia Power’s base rates, plus an incremental increaseterms and conditions. In the biennial review, as in the 2009 Base Rate Review, Virginia Power’s authorized ROE can be no lower than the average of approximately $68 million. Thethat reported by not less than a majority of comparable utilities within the Southeastern U.S., with certain limitations as described in the Regulation Act. If Virginia Commission also ruled that approximately $10 million thatPower’s earnings are
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more than 50 basis points above the Company had proposed to collect in Rider T wouldauthorized level, such earnings will 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.shared with customers.
Virginia Power also haspreviously 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’sVirginia Power’s retail customers by ten percent of what was consumed in 2006. In FebruaryMarch 2010, the Virginia Commission concludedapproved the recovery of approximately $28 million for five of the DSM programs through initiation of Riders C1 and C2, effective May 1, 2010. With respect to the other six DSM programs for which approval was sought, the Virginia Commission made a finding that they were not in the public interest at that time, but allowed Virginia Power the opportunity for further evaluation of similar programs. In July 2010, Virginia Power submitted its annual update filing for Riders C1 and C2 with respect to the five approved DSM programs. The proposed revenue requirements for Riders C1 and C2 were approximately $6 million and $18 million, respectively, which together represent a decrease of approximately $5 million compared to the Riders C1 and C2 revenue requirements included in customer rates currently in effect. In February 2011, 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 approvedwas held 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.update of Riders C1 and C2. The Virginia Commission is required to issue its order by March 30, 2011. Virginia Power plans to seek Virginia Commission approval for several DSM programs in 2011. SeeEnvironmental Strategy for a description of Virginia Power’s DSM programs.
In March 2009, Virginia Power filedconnection with the Virginia Commission its first annual update to the rate adjustment clause for theBear Garden and Virginia City Hybrid Energy Center requestingprojects, in June 2010, Virginia Power filed annual updates for Riders R and S, respectively, with the Virginia Commission. Initially, Virginia Power proposed an approximately $86 million revenue requirement for Rider R for the April 1, 2011 to March 31, 2012 rate year. Due to the application of accelerated tax depreciation provisions in the Small Business Jobs Act of 2010, passed in September 2010, Virginia Power revised the requested revenue requirement for Rider R in November 2010 from $86 million to $78 million. The adjusted $78 million revenue requirement represents an increase of approximately $99$14 million over the revenue requirement associated with the Rider R customer rates currently in effect. The proposed Rider S revenue requirement, effective April 1, 2011, 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 itsrate year ending March 31, 2009 base rate filing be applied to2012 is approximately $200 million, which represents an increase of $46 million over the revenue requirement associated with the Rider S pluscustomer rates currently in effect. The ROE included in both rider filings is 12.3%, which is consistent with the terms of the Virginia Settlement Approval Order. In July 2010, the Virginia Commission issued orders with respect to Riders R and S, which adopted a placeholder ROE of 11.3% (not including the 100 basis point enhancementstatutory enhancement) for construction of a new coal-fired generation facility, for a requested totaluse until the 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 increaseis determined in the revenue requirementcontext of Virginia Power’s upcoming biennial review. Evidentiary hearings were held by approximately $8 millionthe Virginia Commission on Riders R and S in December and November 2010, respectively.
The Virginia Commission is required to $91 million. In December 2009, the hearing examiner’s report
was issued recommending approvalWith respect to Virginia Power’s costs of the Rider S increase as set forthtransmission service, in the proposed Stipulation, and thereafterJune 2010, the Virginia Commission approved theVirginia Power’s annual update to Rider S increase consistent with this recommendation. The Rider ST which was effective September 1, 2010, reflecting the 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 withof approximately $338 million recommended by 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 unilaterallyStaff and agreed to reduce the revenue requirement by $4 million to $73 million. In December 2009, the Virginia Commission approved Rider R with the $73Power. The $338 million revenue requirement for 2010. The Rider Rreflects an increase of approximately $118 million over the previous 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.requirement.
In March 2009,April 2010, 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$82 million for the period July 1, 20092010 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.2011. The proposed fuel factor went into effect on July 1, 20092010 on an interim basis and anbasis. An evidentiary hearing on the Company’sVirginia Power’s application was held on September 1, 2009. Consistent with a proposal made by the Company at the hearing in September 2009,2010, and in October 2010, the Virginia Commission issued an interim fuelits final order effective October 1, 2009, further reducingapproving 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 decreasereduction 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 orderas proposed 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.application.
If the Virginia Commission’s future rate actions,decisions, including actions relating to Virginia Power’s 2009 base rateupcoming biennial 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 Powerhave been subject to file a general rate case to show cause
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 stillcontinued to be subject to annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs.
In February 2010, in preparation for the end of the five-year base rate moratorium, Virginia Power filed an application withto increase its base rates and adjust its fuel rates. Virginia Power’s application included a proposal to recover proportionately more of its purchased power energy costs through fuel rates, which are adjusted annually, instead of being recovered in base rates. In August 2010, Virginia Power filed its annual application for a change in its fuel rates, which updated the fuel application of February 2010 to reflect a proposed decrease of approximately $28 million when compared to current fuel rates. Also in August 2010, Virginia Power updated its base rate application to seek a $27 million increase, instead of $29 million as originally proposed.
In September 2010, all parties to the base rate and fuel case except one, which did not oppose the settlement, filed an Agreement and Stipulation of Settlement and requested approval from the North Carolina Commission. In December 2010, the North Carolina Commission to increase its electric retail rates inissued the North Carolina by approximately $46 million effective January 2011.Settlement Approval Order. The requested rateNorth Carolina Settlement Approval Order authorizes an increase would consist of ain base rate increaserevenues of approximately $29$8 million and a one-year decrease in combined fuel revenues of approximately $17$32 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 underrevenues produced from current rates. In addition, the currently approved rates. IfNorth Carolina Settlement Approval Order permits the entire $17 million increase relatedrecovery through fuel rates of 85% of the net energy costs of power purchases from both PJM and other wholesale suppliers and from the non-utility generators subject to purchased power costs were to be approvedeconomic dispatch that do not provide actual cost data. The
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North Carolina Settlement Approval Order authorizes an ROE of 10.7% and a capital structure composed of 49% long-term debt and 51% common equity. Virginia Power does not agree that the foregoing ROE represents its anticipated or actual cost of equity or capital structure, but accepted the resulting revenue requirement for recoverythe purpose of a global settlement of disputed issues in the 2011proceedings. The new base and fuel adjustment charge, and if none of those costs are offset by reductions in costs for other fuel types, the additional impactrates became effective 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.January 1, 2011.
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
EachBoth of the three states in which Dominion has gas distribution operations has enacted orhave 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 offeredoffers retail choice to residential and commercial customers. At December 31, 2009,2010, 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 butand places Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills. Subject to ultimatethe Ohio CommissionCommission’s approval, Dominion East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. Dominion East Ohio will continuecontinues 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, threeone-, 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 base rate revenue increase and an 8.49% allowed rate of return on rate base for Dominion East Ohio, which were reflected in revised base rates commencing December 22, 2008.
In October 2008, the Ohio Commission approved cost recovery for an initial five-year period of East Ohio’s 25-year PIR program to replace approximately 20% of its 21,000-mile pipeline system. In August 2009, East Ohio filed an application with the Ohio Commission seeking approval of the first annual adjustment to the PIR cost recovery charge approved as part of East Ohio’s 2008 base rate case. The application included a revenue requirement of approximately $16 million, which was subsequently reduced to approximately $13 million by an order issued by the Ohio Commission in December 2009. East Ohio opposed the order, however, its application for rehearing of the decision was denied. In March 2010, East Ohio filed a notice of appeal with the Supreme Court of Ohio alleging that the Ohio Commission’s order in the matter was unlawful, unjust and unreasonable. Dominion cannot predict the outcome of the appeal, however, it is not expected to have a material effect on results of operations.
In August 2010, East Ohio filed its second annual application to adjust the cost recovery charge associated with its PIR program for actual costs and a return on investments made through June 30, 2010. The application reflected a revenue requirement of approximately $28 million. In November 2010, the Ohio Commission approved a settlement agreement filed by East Ohio and the Staff of the Ohio Commission reflecting a revenue requirement of approximately $27 million. Other interested parties to the case neither supported nor objected to the settlement agreement.
Under the Ohio PIPP program, eligible customers can receive energy assistance based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP plan payment amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. Due to increased participation in the program and increases in gas costs in the period since the previous rider rate went into effect, unrecovered costs increased. Accordingly, in March 2010, the Ohio Commission approved a 12-month recovery of approximately $259 million of uncollected receivables associated with the PIPP program, comprised of accumulated PIPP arrearages of $163 million and projected arrearages of $96 million for the 12 months that the PIPP rider rate will be in effect. The PIPP
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rider rate went into effect in April 2010. The Ohio Commission directed East Ohio to file an application, with arrearages calculated on a calendar year basis, to update its PIPP rider within one year of implementation of the new PIPP rider rate and annually thereafter.
In November 2010, rule changes adopted by the Ohio Commission to the PIPP program became effective. The rule changes established a new program, PIPP Plus, which replaced PIPP. The PIPP Plus program reduces the customer’s monthly payments from 10% to 6% of household income and provides for forgiveness credits to the customer’s balance when required payments are received in full by the due date. Such credits may result in the elimination of the customer’s arrearage balance over 24 months.
East Ohio files an annual UEX Rider with the Ohio Commission, pursuant to which it seeks recovery of the bad debt expense of most customers not participating in PIPP Plus. The UEX Rider is adjusted annually to achieve dollar-for-dollar recovery of East Ohio’s actual write-offs of uncollectable amounts. In 2010, East Ohio deferred approximately $55 million of bad debt expense for recovery through the UEX Rider.
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.
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,June 2010, the West Virginia Commission deniedauthorized an additional base rate increase of less than $1 million to correct a miscalculation of rates attached to the application for the sale of Hope.November 2009 order.
Dominion decided to retain Hope, but continue with the sale of Peoples, which closed in February 2010.
Federal Regulations
EPACTANDTHE REPEALOF 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 thatthe issue of existing facilities back to FERC for further proceedings. Although Dominion and Virginia Power cannot predict the outcome of the FERC proceedings on remand.remand, the impact of any PJM rate design changes on the Companies’ results of operations is not expected to be material.
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.
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 coverrecover the expected cost of servicerevenue requirement for each calendar year and is trued upupdated based on actual costs. While other transmission owners in the PJM region use aThe FERC-approved formula rate based on historic costs, Virginia Power’s formula ratemethod, which is based on projected costs. The FERC ruling did not materially impact Virginia Power’s results of operations; however, the FERC-approved formula methodcosts, 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 servicerevenue requirement 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. Although Virginia Power cannot predict the outcome of the rehearing.rehearing, it is not expected to have a material effect on results of operations.
In March 2010, ODEC and NCEMC filed a complaint with FERC against Virginia Power claiming that approximately $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. ODEC and NCEMC requested that FERC estab-
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lish procedures to determine the amount of costs for each applicable project that should be excluded from Virginia Power’s rates. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. While Virginia Power cannot predict the outcome of this proceeding, it is not expected to have a material effect on results of operations.
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)Buyers filed a complaint atwith 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 JuneNovember 2009, the Virginia Commission approved full recovery ofCourt transferred the DRC from Virginia Power’s retail customers through Rider T. Recovery ofappeal to 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 CircuitDistrict of Columbia Circuit. In February 2011, the Court of Appeals denied the petition for review, concluding that FERC had adequately explained why the rates were just and reasonable.
EPACT included provisions to create an ERO. The ERO is required to promulgate mandatory reliability standards governing the appeal is currently pending. Inoperation of the fourth quarterbulk power system in the U.S. FERC has certified NERC as the ERO and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of 2009, between $1 thousand and $1 million per day, and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
Dominion and Virginia Power wrote off substantially allplan and operate their facilities in compliance with approved NERC reliability requirements. Dominion and Virginia Power employees participate on various NERC committees, track the development and implementation of these regulatory assets, since recoverystandards, and maintain proper compliance registration with NERC’s regional organizations. Dominion and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cyber security programs as well as efforts to ensure appropriate facility ratings for Virginia Power’s transmission lines. In October 2010, NERC issued an industry alert identifying possible discrepancies between the design and actual field conditions of transmission facilities as a potential reliability issue. The alert recommends that entities review their current facilities rating methodology to verify that the methodology is no longer probable based on actual field conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power is evaluating its transmission facilities for any discrepancies between design and actual field conditions. In addition, NERC has requested the proposed settlementindustry to increase the number of assets subject to NERC reliability standards that are designated as critical assets, including cyber security assets. While Dominion and Virginia Power’s rate case proceedings discussed furtherPower expect to incur additional compliance costs in Note 14connection with the above NERC requirements and initiatives, such expenses are not expected to the Consolidated Financial Statements.significantly affect results of operations.
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, DCPCove Point and the Dominion South Pipeline Company, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.
Dominion’s interstate gas transmission and storage activities are generally conducted on an “open access”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 2002this 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’sDTI’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. DTI remains subject to the terms of the tariff rates established pursuant to the settlement.
In December 2007, DTI and the Independent Oil and Gas Association of West Virginia, Inc. reachedIOGA entered into a settlement agreement on DTI’s gathering and processing rates, for the period January 1, 2009which DTI and IOGA agreed in May 2010 to extend through December 31, 2011. This2014. DTI, at its option, may elect to extend the agreement for an additional year through December 31, 2015. The settlement maintainedextension maintains 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 connectionDTI will file the negotiated rates associated with the settlement, DTI has committedagreement extension with FERC in December 2011.
Dominion is required to invest at least $20 million annually in Appalachian gathering-related assets. The newfile a general base rate review for the FERC-jurisdictional services of Cove Point, effective no later than July 1, 2011. At that time, Cove Point’s cost of service will be reviewed by the FERC, with rates have been approved by FERC as negotiated rates.set based on analyses of Cove Point’s costs and capital structure.
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 applicableappli-
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cable 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, seeEnvironmental Matters inFuture Issues and Other Matters in MD&A.&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 23 to the Consolidated Financial Statements.
GLOBAL CLIMATE CHANGE
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 has developed a more comprehensive GHG inventory for calendar year 2008.2009. For Dominion Generation, Dominion’s and Virginia Power’s direct CO2 equivalent emissions, based on equity share (ownership), were approximately 5654 million metric tonnes and 33 million metric tonnes, respectively, in 2008.2009. 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)Point) direct CO2 equivalent emissions were approximately 2.5 million metric tonnes Dominionand 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 20092010 emissions data, they do not expect a significant variance in emissions from 20082009 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.U.S. Electric Code of Federal Regulation. For those emission sources not covered under 40 CFR Part
75, and for methane and nitrous oxide emissions, quantification is based on fuel combustion, higher heating values, emission factors, and global warming potentials as specified in the new EPAEPA’s 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.Rule. For the DVP operating segment’s electric transmission and distribution emissions, the protocol used wasThe 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 wasGreenhouse Gas Emission Estimation Guidelines for NaturalGas Transmission and Storage, Volume 1—GHG1-GHG EstimationMethodologies and Procedures—RevisionProcedures-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. SeeEnvironmental Strategy above for a description of Dominion and
Virginia Power’s strategy for reducing GHG emission intensity. Some recentBelow are some of the Companies’ efforts that have or are expected to reduce the Companies’ carbon intensity include:emissions or intensity:
Ÿ | 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 |
Ÿ | Since 2000, Dominion has added |
Ÿ | Virginia Power |
Ÿ | Dominion has |
Ÿ |
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Ÿ | Virginia Power has announced its plans to develop the Warren County power station development project, which is designed to be a 3-on-1, combined-cycle, natural gas-fired power station expected to generate more than 1,300 MW of electricity. In connection with the air permit process for the Warren County project, Virginia Power reached an agreement with the National Park Service to permanently retire the North Branch power station, a 74 MW coal fired plant located in West Virginia, once the Warren County power station begins commercial operations. |
Ÿ | Virginia Power and ODEC have 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. |
Ÿ | In |
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DSM programs |
Ÿ | Virginia Power has initiated a demonstration of |
While, upon entering service, Virginia Power’s new Virginia City Hybrid Energy Center, which is currently under construction in Southwestsouthwest 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 percent10% biomass for fuel and wasis 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. SeeDominion 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 2008,2009, 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%16% and 8%5%, 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 Dominion’s and Virginia Powers’ nuclear power stations, which are part of the Dominion Generation segment, are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.
From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining Dominion’s and Virginia Power’s nuclear generating units.
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, seeDominion Generation—NuclearDecommissioning 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. WithIn May 2010, the exceptionstay was lifted, and the government’s initial brief in the appeal was filed in June 2010. The issues raised by the government on appeal pertain to the damages awarded to Dominion for Millstone. The government did not take issue with the damages awarded to Virginia Power for Surry or North Anna. As a result, Virginia Power recognized a receivable in the amount of one case,$174 million, largely offset against property, plant and equipment and regulatory assets and liabilities, representing certain spent nuclear fuel-related costs incurred through June 30, 2010. Briefing on the appeal was concluded in September 2010 and oral argument took place before 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.January 2011. 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.
A lawsuit was also filed for Kewaunee. In August 2010, Dominion and the federal government reached a settlement resolving Dominion’s claims for damages incurred at Kewaunee power station, and that lawsuit is presently stayed through March 15,December 31, 2008. The approximately $21 million settlement payment was received in September 2010.
The Companies will continue to manage their spent fuel until it is accepted by the DOE.
Virginia Power and Kewaunee continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE.
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
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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 results of operations. Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. 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 result in substantial expense.
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 generation facilities and bulk powerelectric transmission systems, including Dominion and Virginia Power, are subject to mandatory reliability standards enacted by NERC and enforced by FERC. Compliance with the mandatory reliability standards may subject the Companies to higher operating costs and may result in increased capital expenditures. If either Dominion or Virginia Power is found not to be in compliance with the mandatory reliability standards it could be subject to remediation costs, as well as sanctions, including substantial monetary penalties.
Dominion’s and Virginia Power’s costs of compliance with environmental laws are significant, and the costsignificant. The costs of compliance with future environmentalenvironmental laws, including laws and regulations designed to addressglobal climate change, air quality, coal combustion by-products, cooling water and other matters could adversely affect their cash flow and profitability.make certain of the Companies’ generation facilities uneconomical to maintain or operate.Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environ - -
mentalenvironmental monitoring, installation and operation of pollution control equipment and purchase of allowances and/or offsets. Additionally, theythe Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and Dominion and Virginia Power expect that they will remain significant in the future. Costs
Existing environmental laws and regulations may be revised and/or new laws may be adopted or become applicable to Domin-
ion or Virginia Power. The EPA is expected to issue additional regulations with respect to air quality under the CAA, including revised NAAQS, a replacement of compliance with environmental regulations could adversely affect their resultsthe CAIR relating to NOX and SO2emissions, and a MACT rule for coal and oil-fired electric generation plants that will likely address numerous HAPs, including mercury. Risks relating to potential regulation of operations and financial condition, especially if emission and/or discharge limitsGHG emissions are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assetsdiscussed below. Dominion and Virginia Power operate increases. also expect additional federal water and waste regulations, including regulations concerning cooling water intake structures and coal combustion by-product handling and disposal practices.
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. However, such expenditures, if excessive, could make the Companies’ generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.
If additional federal and/or state requirements are imposed on energy companies mandating 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, suchrequirements may result in compliance costs that alone or in combinationcombination could make some of Dominion’s andor Virginia Power’s electric generatinggeneration units uneconomical to maintain or operate. As related to GHG emissions, theThe 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 additional EPA regulation, and possibly additional state legislation and/or regulation, may pass resulting in the imposition of additional limitations on GHG emissions from fossil fuel-fired electric generating units. In December 2009, the EPA issued theirFinal 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 and regulations may require GHG emission reductions from the natural gas sector and could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products. Several regions of the U.S. have moved forward with GHG emission
regulations including regions where Dominion has operations. For example, Massachusetts has implemented regulations requiring reductions in CO2 emissions and the Regional Greenhouse Gas Initiative,through RGGI, 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 increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon capture and storage technology, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower emitting generation facilities. The cost of compliance with 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
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and associated regulations, and the selected compliance alternatives. As a result, Dominion and Virginia Powerthe Companies cannot estimate the effect of any such legislation on their results of operations, financial condition or their customers. However, such expenditures, if excessive, could make the Companies’ generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.
The base rates and rider 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 ofThat review culminated in a final order in March 2010, in which the Commission ordered that Virginia Power’s costs and capital structure, as reviewed and approved in regulatory proceedings. Under the Regulation Act,base rates be frozen at their pre-September 1, 2009 levels until December 1, 2013. In 2011, however, the Virginia Commission may,will commence biennial reviews of the rates and terms and conditions of Virginia Power and, in a proceeding initiated in 2009, reduce rates orthat first biennial review, may order a credit to customers if Virginia Power is deemed to be earningfor a portion of earnings 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.authorized ROE.
The rates of Virginia Power’s electric transmission operations and Dominion’s gas transmission and distribution operations are subject to regulatory review. Revenue provided by Virginia Power’s electric transmission operations and Dominion’s gas transmission and distribution operations is based primarily on rates approved by FERC.federal and state regulatory agencies. The profitability of these businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.
Virginia Power’s wholesale charges for electric transmission service are adjusted on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism, Virginia Power’s wholesale electric transmission cost of service is estimated and thereafter trued-upadjusted 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 notno later than July 31, 2011. At that time, Cove Point’s cost of servicecost-of-service will be reviewed by the FERC, with rates set based on analyses of the Company’sCove Point’s costs and capital structure. The FERC-jurisdictional rates for DTI
Dominion’s gas distribution businesses are subject to state regulatory review in the subject of a 2005 FERC-approved settlement. That settlement established a rate moratorium that continuesjurisdictions in effect through June 30, 2010.which they operate.
Energy conservationRisks arising from the reliability of electric generation, transmission and distribution equipment could negatively impact Dominion’sresult in lost revenues and increased expenses, including higher maintenance costs.Operation of the Companies’ generation, transmission and distribution facilities involves risk, including, the risk of potential breakdown or failure of equipment or processes, due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions
resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution facilities. Because Virginia Power’s financial results. Certain regulatory and legislative bodies have introduced ortransmission facilities are considering requirements and/or incentives to reduce energy consumption by a fixed date. Tointerconnected with those of third parties, the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the valueoperation of Dominion’s merchant generation, E&P assets and other unregulated business activitiesits facilities could be adversely impacted. In Virginia Power’s regulated operations, conservation could negatively impact its results dependingaffected by unexpected or uncontrollable events occurring on the regulatory treatmentsystems of such third parties.
Operation of the associated impacts. Should Virginia Power be requiredCompanies’ generation facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of generating units and extensions of scheduled outages due to investmechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less energy or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement energy and capacity from third parties in 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. Dominionopen market to satisfy forward energy and Virginia Powercapacity obligations. Moreover, if the Companies are unable to determine what impact, if any, conservation will have onperform their financial conditioncontractual obligations, penalties or results of operations.liability for damages could result.
Dominion’s merchant power business is operating in a challenging market, which could adversely affect its results of operations and future growth.
The success of Dominion’s merchant power business depends upon favorable market conditions including the ability to purchase and sell power at prices sufficient to cover its operating costs. Dominion operates in active wholesale markets that expose it to price volatility for electricity and fuel as well as the credit risk of counterparties. Dominion attempts to manage its price risk by entering into hedging transactions, including short-term and long-term fixed price sales and purchase contracts.
In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion does not enter into long-term power purchase agreements or otherwise 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.
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 electricityelec-
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tricity markets regulated by FERC. The wholesale markets allow these merchant generation stations to take advantage of market price opportunities, but also exposesexpose 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.
War, acts and threats of terrorism, natural disaster and other significant events could adversely affect Dominion’s and Virginia Power’soperations.We cannot predict the impact that any future terrorist attacks may have on the energy industry in general, or on our business in particular. Any retaliatory military strikes or sustained military campaign may affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets. In addition, infrastructure facilities, such as electric generation, electric and gas transmission and distribution facilities could be affected by terrorist activities and catastrophic events thatdirect targets of, or indirect casualties of, an act of terror. Furthermore, the physical or cyber security compromise of our facilities, could adversely affect our ability to manage these facilities effectively. Instability in financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors could result 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, including 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 haveit has hedged future sales, Dominion may be required to use a material portion of its available liquidity or obtain additional liquidity to cover these collateral requirements. In some circumstances, this could have a compounding effect on Dominion’s financial liquidity and results of operations.
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 inbetween the location andand/or specifications of the derivative hedging instrument and the hedged item and could adversely affect Dominion’s results of operations.
Dominion’s and Virginia Power’s operations in regards to these transactions are subject to multiple market risks including market liquidity, counterparty credit strength and price volatility. These market risks are beyond theirthe Companies’ control and could adversely affect their results of operations and future growth.
For additional information concerningThe Dodd-Frank Act, which was enacted into law in July 2010, includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and commodity-basedexecuted through an exchange or other approved trading contracts, see Market Risk Sensitive Instrumentsplatform. Final rules for the over-the-counter derivatives-related provisions of the Dodd-Frank Act, including the clearing, exchange trading and Risk Managementcapital and margin requirements, will be established through the CFTC’s rulemaking process, which is required to be completed by July 2011. If, as a result of the rulemaking process, Dominion’s or Virginia Power’s derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs for their derivative activities, including from higher margin requirements. In addition, implementation of, and compliance with, the over-the-counter derivatives provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 2 and 8increased costs related to the Consolidated Financial Statements.Companies’ derivative activities.
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.
Dominion and Virginia Power may not complete plant construction or expansion projects that they commence, or they may complete projectsprojects 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
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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.
Exposure to counterparty performance may adversely affect the Companies’ financial results of operations.Dominion and Virginia Power are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Such defaults by customers, suppliers or other third parties may adversely affect the Companies’ financial results.
Energy conservation could negatively impact Dominion’s and Virginia Power’s financial results. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices, including lighting and electric heat pumps, could lead to declines in per capita energy consumption. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of the Companies’ business activities could be adversely impacted.
An inability to access financial markets could adversely affect the execution of Dominion’s and Virginia Power’s business plans.Dominion and Virginia Power rely on access to short-term money markets and longer-term capital markets 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 thatcommodities. Deterioration in the Companies will maintain sufficient access to theseCompanies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or market reputation, or general financial markets based upon their current credit ratings and market reputation. However, certain disruptions outside of Dominion’s and Virginia Power’s control maycould increase their cost of borrowing or restrict their ability to access one or more financial markets. SuchFurther market disruptions could includestem from 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 theythe Companies rely. RestrictionsIncreased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.
Market performance and other changes may decrease the value of decommissioning trust funds and benefit plan assets or increase Dominion’s liabilities, which 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 and other postretirement benefit plans. If the decommissioning trust funds and benefit plan assets are not successfully managed,negatively impacted by market fluctuations, 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 currentappropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, Dominion and Virginia Power may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in Dominion’s credit ratings or the credit ratings of Virginia Power 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.
As of December 31, 2009,2010, Dominion owned its principal executive office and three other corporate offices, all located in Richmond, Virginia. Dominion also leases corporate offices in other cities in which its subsidiaries operate. Virginia Power shares its
principal office in Richmond, Virginia, which is owned by Dominion. In addition, Virginia Power’s DVP and Generation segments share certain leased buildings and equipment. See Item 1. Business for additional information about each segment’s principal properties.properties, which information is incorporated herein by reference.
Dominion’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described here and in Item 1. Business.
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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;2010; 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 GASAND 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
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.
QUANTITIESOF GASAND OIL PRODUCED
Quantities of gas and oil produced follow:
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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 DRILLEDINTHE CALENDAR YEAR
The number of net wells completed follows:
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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, 2009,2010, Dominion Generation’s total utility and merchant generating capacity was 27,50727,615 MW.
The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2010:
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 | 1,242 | ||||||||||
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 | (2) | |||||||||
Altavista | Altavista, VA | 63 | (2) | |||||||||
Polyester | Hopewell, VA | 63 | ||||||||||
Southampton | Southampton, VA | 63 | ||||||||||
Total Coal | 4,781 | 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 | 267 | ||||||||||
Gordonsville Energy (CC) | Gordonsville, VA | 218 | ||||||||||
Rosemary (CC) | Roanoke Rapids, VA | 165 | ||||||||||
Gravel Neck (CT) | Surry, VA | 170 | ||||||||||
Darbytown (CT) | Richmond, VA | 168 | ||||||||||
Total Gas | 3,999 | 22 | ||||||||||
Nuclear | ||||||||||||
Surry | Surry, VA | 1,642 | ||||||||||
North Anna | Mineral, VA | 1,638 | (3) | |||||||||
Total Nuclear | 3,280 | 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 | (4) | |||||||||
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 | — | |||||||||
16,557 | ||||||||||||
Power Purchase Agreements | 1,861 | 10 | ||||||||||
Total Utility Generation | 18,418 | 100 | % |
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 | |||||
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) | Facility has been placed into cold reserve status, but can be restarted within a reasonably short period if necessary. North Branch will be permanently retired upon commencement of commercial operations at the proposed Warren County power station currently under development. |
(3) | Excludes 11.6% undivided interest owned by ODEC. |
Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc. |
DOMINION MERCHANT GENERATION
Plant | Location | Net Summer Capability (MW) | Percentage Net Summer | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | ||||||||||||||
Coal | ||||||||||||||||||||
Kincaid | Kincaid, IL | 1,158 | (1) | Kincaid, IL | 1,158 | (1) | ||||||||||||||
Brayton Point | Somerset, MA | 1,105 | Somerset, MA | 1,105 | ||||||||||||||||
State Line | Hammond, IN | 515 | Hammond, IN | 515 | ||||||||||||||||
Salem Harbor | Salem, MA | 314 | Salem, MA | 314 | ||||||||||||||||
Morgantown | Morgantown, WV | 25 | (1),(2) | Morgantown, WV | 25 | (1),(2) | ||||||||||||||
Total Coal | 3,117 | 34 | % | 3,117 | 34 | % | ||||||||||||||
Nuclear | ||||||||||||||||||||
Millstone | Waterford, CT | 2,023 | (3) | Waterford, CT | 2,016 | (3) | ||||||||||||||
Kewaunee | Kewaunee, WI | 556 | Kewaunee, WI | 556 | ||||||||||||||||
Total Nuclear | 2,579 | 28 | 2,572 | 28 | ||||||||||||||||
Gas | ||||||||||||||||||||
Fairless (CC) | Fairless Hills, PA | 1,196 | (4) | Fairless Hills, PA | 1,196 | (4) | ||||||||||||||
Elwood (CT) | Elwood, IL | 712 | (1),(5) | Elwood, IL | 712 | (1),(5) | ||||||||||||||
Manchester (CC) | Providence, RI | 432 | Providence, RI | 432 | ||||||||||||||||
Total Gas | 2,340 | 25 | 2,340 | 25 | ||||||||||||||||
Oil | ||||||||||||||||||||
Salem Harbor | Salem, MA | 440 | Salem, MA | 438 | ||||||||||||||||
Brayton Point | Somerset, MA | 438 | Somerset, MA | 440 | ||||||||||||||||
Total Oil | 878 | 10 | 878 | 10 | ||||||||||||||||
Wind | ||||||||||||||||||||
Fowler Ridge | Benton County, IN | 150 | (1),(6) | Benton County, IN | 150 | (1),(6) | ||||||||||||||
NedPower Mt. Storm | Grant County, WV | 132 | (1),(7) | Grant County, WV | 132 | (1),(7) | ||||||||||||||
Total Wind | 282 | 3 | 282 | 3 | ||||||||||||||||
Various | ||||||||||||||||||||
Other | Various | 8 | — | Various | 8 | — | ||||||||||||||
Total Merchant Generation | 9,204 | 100 | % | 9,197 | 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. Dominion completed the sale of its partnership interest in this facility in January 2011. |
(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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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.
SeeRegulation in Item 1. Business,Future Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference 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.Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming 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. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the CAA. Dominion is currently evaluatingcannot predict the impactoutcome of this matter. However, an adverse resolution could have a material effect on future results of operations and/or cash flows.
In May 2010, Dominion received a request for information pursuant to Section 114 of the NoticeCAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at Brayton Point and Salem Harbor. Dominion submitted its response to the request in November 2010 and cannot predict the outcome of this matter.
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Executive Officers of Dominion
Name and Age | Business Experience Past Five Years(1) | |
Thomas F. Farrell II | 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 | |
Mark F. McGettrick | 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 | |
Paul D. Koonce | 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 | |
David A. Christian | 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 | 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 | |
Gary L. Sypolt | 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 | |
Robert M. Blue | Senior Vice | |
| ||
| ||
Steven A. Rogers | Senior Vice President and | |
|
| Vice President— | |
| date; Vice President and Controller |
(1) | Any service listed for Virginia Power, CNG, DTI |
30 |
Part II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
DOMINIONDominion
Dominion’s common stock is listed on the New York Stock Exchange.NYSE. At February 1, 2010,January 31, 2011, there were approximately 148,000 registered shareholders, including approximately 54,000144,000 record holders of Dominion’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion’s transfer agent records and includes accounts with shares held in (1) certificate holders.form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion’s direct stock purchase and dividend reinvestment plan. Discussions of the restrictions on Dominion’s payment of dividends required by this Item are contained inDividend Restrictions in Item 7. MD&A and NoteNotes 18 and 21 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 20092010 and 2008.2009. Quarterly information concerning stock prices and dividends is disclosed in Note 2928 to the Consolidated Financial Statements.Statements, which information is incorporated herein by reference.
The following table presents certain information with respect to Dominion’s common stock repurchases during the fourth quarter of 2009.2010.
DOMINION PURCHASESOF EQUITY SECURITIES
Period | Total | Average | Total Number | Maximum Number (or 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 |
Period | Total Number of Shares (or Units) Purchased(1) | Average Paid per | Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Yet Be Purchased under the Plans or Programs(3) | ||||||||||||
10/1/2010-10/31/10 | 1,821 | $ | 43.66 | N/A | 32,586,412 shares/$ | 1.78 billion | ||||||||||
11/1/2010-11/30/10 | 2,708 | $ | 43.46 | N/A | 32,586,412 shares/$ | 1.78 billion | ||||||||||
12/1/2010-12/31/10 | 956 | $ | 42.03 | N/A | 32,586,412 shares/$ | 1.78 billion | ||||||||||
Total | 5,485 | $ | 43.28 | N/A | 32,586,412 shares/$ | 1.78 billion |
(1) |
(2) | Represents the weighted-average price paid per share. |
(3) | The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Board of Directors in February 2005, as modified in June 2007. |
VIRGINIA POWERVirginia 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 inDividend 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 | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year | ||||||||||||||||||||||||||
(millions) | |||||||||||||||||||||||||||||||||||
2010 | $ | 108 | $ | 81 | $ | 171 | $ | 140 | $ | 500 | |||||||||||||||||||||||||
2009 | $ | 101 | $ | 75 | $ | 190 | $ | 97 | $ | 463 | 101 | 75 | 190 | 97 | 463 | ||||||||||||||||||||
2008 | $ | 115 | $ | 83 | $ | 163 | $ | 80 | $ | 441 |
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Item 6. Selected Financial Data
DOMINIONDominion
Year Ended December 31, | 2009 | 2008 | 2007 | 2006 | 2005 | 2010 | 2009(1) | 2008(1) | 2007(1) | 2006(1) | ||||||||||||||||||||||||||||
(millions, except per share amounts) | ||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 15,131 | $ | 16,290 | $ | 14,816 | $ | 17,276 | $ | 16,766 | $ | 15,197 | $ | 14,798 | $ | 15,895 | $ | 14,456 | $ | 16,893 | ||||||||||||||||||
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 from continuing operations before extraordinary item(2) | 2,963 | 1,261 | 1,644 | 2,661 | 1,725 | |||||||||||||||||||||||||||||||||
Income (loss) from discontinued operations, net of tax | — | (2 | ) | (8 | ) | (150 | ) | 6 | (155 | ) | 26 | 190 | 36 | (345 | ) | |||||||||||||||||||||||
Extraordinary item, net of tax(1) | — | — | (158 | ) | — | — | ||||||||||||||||||||||||||||||||
Extraordinary item, net of tax(2) | — | — | — | (158 | ) | — | ||||||||||||||||||||||||||||||||
Net income attributable to Dominion | 1,287 | 1,834 | 2,539 | 1,380 | 1,033 | 2,808 | 1,287 | 1,834 | 2,539 | 1,380 | ||||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||||||||||
Income from continuing operations before extraordinary item per common share-basic | 5.03 | 2.13 | 2.84 | 4.09 | 2.46 | |||||||||||||||||||||||||||||||||
Net income attributable to Dominion per common share-basic | 4.77 | 2.17 | 3.17 | 3.90 | 1.97 | |||||||||||||||||||||||||||||||||
Income from continuing operations before extraordinary item per common share-diluted | 5.02 | 2.13 | 2.83 | 4.06 | 2.45 | |||||||||||||||||||||||||||||||||
Net income attributable to Dominion per common share-diluted | 4.76 | 2.17 | 3.16 | 3.88 | 1.96 | |||||||||||||||||||||||||||||||||
Dividends paid per common share | 1.83 | 1.75 | 1.58 | 1.46 | 1.38 | |||||||||||||||||||||||||||||||||
Total assets | 42,554 | 42,053 | 39,139 | 49,296 | 52,683 | 42,817 | 42,554 | 42,053 | 39,139 | 49,296 | ||||||||||||||||||||||||||||
Long-term debt | 15,481 | 14,956 | 13,235 | 14,791 | 14,653 | 15,758 | 15,481 | 14,956 | 13,235 | 14,791 |
(1) | Recast to reflect the discontinued operations of Peoples as described in Note 4 to the Consolidated Financial Statements. |
(2) | Amounts attributable to Dominion’s common shareholders. |
2010 results include a $1.4 billion after-tax net income benefit from the sale of substantially all of Dominion’s Appalachian E&P operations, net of charges related to the divestiture and a $206 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, as discussed in Notes 4 and 23 to the Consolidated Financial Statements, respectively. Also in 2010, Dominion recorded $127 million of after-tax impairment charges at certain merchant generation facilities, as discussed in Note 7 to the Consolidated Financial Statements. The loss from discontinued operations in 2010 includes a $140 million after-tax loss on the sale of Peoples.
2009 results include a $435 million after-tax charge in connection with the proposed settlement of Virginia Power’s 2009 base rate case proceedings. For more information seeproceedings discussed in Note 14 to the Consolidated Financial Statements. Also in 2009, Dominion recorded a $281 million after-tax ceiling test impairment charge related to the carrying value of its E&P properties.
2008 results include a $136$109 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. In addition, income from discontinued operations in 2008 includes a $120 million after-tax benefit due to the reversal of deferred tax liabilities associated with the sale of Peoples.
2007 results include a $1.5 billion after-tax 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.Dresden. Also in 2007, Dominion recorded a $137 million after-tax charge resulting from the termination of the long-term power sales agreement associated with State Line. In addition, the reapplication of accounting guidance for cost-based rate regulation to the Virginia jurisdiction of Virginia Power’s generation operations in 2007 resulted in a $158 million after-tax extraordinary charge. 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 Peoples sold in 2010, Canadian E&P operations sold in June 2007 and the Peaker facilities sold in March 2007. Discontinued operations for Peoples includes a $119 million after-tax charge primarily due to the recognition of deferred tax liabilities, as well as a $114 million after-tax charge resulting from the write-off of certain regulatory assets, both in connection with the sale. Discontinued operations for the Peaker facilities includedincludes a $164 million after-tax impairment charge to reduce the facilities’ carrying amountamounts to itstheir estimated fair valuevalues less cost to sell. See
Virginia Power
Year Ended December 31, | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||
(millions) | ||||||||||||||||||||
Operating revenue | $ | 7,219 | $ | 6,584 | $ | 6,934 | $ | 6,181 | $ | 5,603 | ||||||||||
Income from operations before extraordinary item | 852 | 356 | 864 | 606 | 478 | |||||||||||||||
Extraordinary item, net of tax | — | — | — | (158 | ) | — | ||||||||||||||
Net income | 852 | 356 | 864 | 448 | 478 | |||||||||||||||
Balance available for common stock | 835 | 339 | 847 | 432 | 462 | |||||||||||||||
Total assets | 22,262 | 20,118 | 18,802 | 17,063 | 15,683 | |||||||||||||||
Long-term debt | 6,702 | 6,213 | 6,000 | 5,316 | 3,619 |
2010 results include a $123 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, discussed in Note 423 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 base rate case proceedings. For more information seeproceedings discussed in Note 14 to the Consolidated Financial Statements.
2007 results reflect the reapplication of accounting guidance for cost-based rate regulation to the Virginia jurisdiction of Virginia Power’s generation operations, which resulted in a $158 million after-tax extraordinary charge. 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.
CONTENTSOF MD&A
MD&A consists of the following information:
Ÿ | Forward-Looking Statements |
Ÿ | Accounting Matters |
Ÿ | Dominion |
Ÿ | Results of Operations |
Ÿ | Segment Results of Operations |
|
Ÿ | Virginia Power |
Ÿ | Results of Operations |
Ÿ | Segment Results of Operations |
Ÿ | Liquidity and Capital Resources |
Ÿ | Future Issues and Other Matters |
FORWARD-LOOKING STATEMENTS
This report contains statements concerning Dominion’s and Virginia Power’s expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words.
Dominion and Virginia Power make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:
Ÿ | Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; |
Ÿ | Extreme weather events, 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 |
Ÿ | Cost of environmental compliance, including those costs related to climate change; |
Ÿ | Risks associated with the operation of nuclear facilities; |
Ÿ | Unplanned outages of the Companies’ |
Ÿ | Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and |
|
Ÿ | Counterparty credit and performance risk; |
Ÿ | Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; |
Ÿ | Risks associated with Virginia Power’s membership and participation in PJM related to obligations created by the default of other participants; |
Ÿ | Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion; |
Ÿ | Fluctuations in interest rates; |
Ÿ | Changes in federal and state tax laws and regulations; |
Ÿ | Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; |
Ÿ | Changes in financial or regulatory accounting principles or policies imposed by governing bodies; |
Ÿ | Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; |
Ÿ | The risks of operating businesses in regulated industries that are subject to changing regulatory structures; |
Ÿ | Receipt of approvals for and timing of closing dates for acquisitions and divestitures; |
Ÿ |
|
Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs and new and evolving capacity models; |
Ÿ | Political and economic conditions, including the threat of domestic terrorism, inflation and deflation; |
Ÿ | Industrial, commercial and residential growth or decline in the Companies’ service areas and changes in customer growth or usage patterns, including as a result of energy conservation programs; |
Ÿ | Additional competition in electric markets in which Dominion’s merchant generation facilities operate; |
Ÿ | Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; |
Ÿ | Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including |
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 - -
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
ditioncondition 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.
33 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
ACCOUNTINGFOR 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 2010, 2009 2008 and 2007,2008, Dominion recognized $85 million, $89 million $94 million and $99$94 million, respectively, of accretion, and expects to incur $88recognize $81 million in 2010.2011. In 2010, 2009 2008 and 2007,2008, Virginia Power recognized
$35 $35 million, $38$35 million and $38 million, respectively, of accretion, and expects to incur $36recognize $37 million in 2010. Upon reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of its generation operations,2011. Virginia Power began recordingrecords accretion and depreciation associated with utility nuclear decommissioning AROs formerly charged to expense, as an adjustment to theits regulatory liability for nuclear decommissioning trust funds previously discussed, in order to match the recognition for rate-making purposes.decommissioning.
A significant portion of the Companies’ AROs relates to the future decommissioning of theirDominion’s merchant and Virginia
Power’s utility nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2009,2010, Dominion’s nuclear decommissioning AROs totaled $1.3$1.4 billion, representing approximately 81%87% of its total AROs. At December 31, 2009,2010, Virginia Power’s nuclear decommissioning AROs totaled $587$620 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-notmore-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, 2009,2010, Dominion had $291$307 million and Virginia Power had $121$117 million of unrecognized tax benefits. For the majoritya substantial amount 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,recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power evaluate quarterlyquar-
34 |
terly 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, 2009,2010, Dominion had established $62$68 million of valuation allowances and Virginia Power had no valuation allowances.
ACCOUNTINGFOR DERIVATIVE CONTRACTSAND OTHER INSTRUMENTSAT 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 toand 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.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
USEOF ESTIMATESIN GOODWILL IMPAIRMENT TESTING
As of December 31, 2009,2010, Dominion reported $3.4$3.1 billion of goodwill in its Consolidated Balance Sheet. A significant portion resulted from the acquisition of the former CNG in 2000.
In April of each year, Dominion tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2010, 2009 and 2008 annual tests and 2007 annualany interim 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-AppalachianAppalachian E&P operations, Peoples and Hope and certain DCI operations, negotiated sales prices were used as fair value for the tests conducted in 2010, 2009 2008 and 2007.2008. Fair value estimates are dependent on subjective factors such as Dominion’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present. See Note 12 to the Consolidated Financial Statements for additional information.
USEOF ESTIMATESIN LONG-L-IVEDLIVED ASSET IMPAIRMENT TESTING
Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances that indicate an impairment may exist;exist, identifying and grouping affected assets;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 See Note 7 to the third quarterConsolidated Financial Statements for a discussion 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 affectedimpairments related to 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.long-lived assets.
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.
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
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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; |
Ÿ | 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 |
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 2010, 2009 and 2008, and 8.75% for 2007.2008. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 7.75% for 2010, 2009 and 2008, and 8.00% for 2007.2008. 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 2010 and 2009, compared to 6.60% and 6.50%, respectively, in 2008 and 6.20% and 6.10%, respectively, in 2007.2008. Dominion selected a discount rate of 6.60%5.90% for determining its December 31, 20092010 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, 20092010 is 8.0%7.0% and is expected to gradually decrease to 4.90%4.60% by 2060 and continue at that rate for years thereafter.
The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed, while holding all other assumptions constant:
Increase in Net Periodic Cost | Increase in Net Periodic Cost | ||||||||||||||||||||
Change in Actuarial Assumption | Pension Benefits | Other Postretirement Benefits | Change in Actuarial Assumption | Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
(millions, except percentages) | |||||||||||||||||||||
Discount rate | (0.25 | )% | $ | 12 | $ | 5 | (0.25 | )% | $ | 13 | $ | 5 | |||||||||
Long-term rate of return on plan assets | (0.25 | )% | 12 | 2 | (0.25 | )% | 13 | 3 | |||||||||||||
Healthcare cost trend rate | 1.00 | % | N/A | 24 | 1.00 | % | N/A | 23 |
In addition to the effects on cost, at December 31, 2009,2010, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $126$138 million and its accumulated postretirement benefit obligation by $45$52 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $191$217 million. See Note 22 to the Consolidated Financial Statements for additional information.
ACCOUNTINGFOR GASAND 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 - -
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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$397 million and $341$355 million of accrued unbilled revenue at December 31, 20092010 and 2008,2009, 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 STANDARDSAND POLICIES
During 2009 2008 and 2007,2008, Dominion and Virginia Power were required to adopt several new accounting standards, which are discussed in Note 3 to the Consolidated Financial Statements.
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DOMINION
RESULTSOF 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 |
Year Ended December 31, | 2010 | $ Change | 2009 | $ Change | 2008 | |||||||||||||||
(millions, except EPS) | ||||||||||||||||||||
Net Income attributable to Dominion | $ | 2,808 | $ | 1,521 | $ | 1,287 | $ | (547 | ) | $ | 1,834 | |||||||||
Diluted EPS | 4.76 | 2.59 | 2.17 | (0.99 | ) | 3.16 |
Overview
2010VS. 2009
Net income attributable to Dominion increased by 118%. Favorable drivers include a gain on the sale of Dominion’s Appalachian E&P operations, lower ceiling test impairment charges related to these properties, the absence of a charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings and the impact of favorable weather on electric utility operations. Unfavorable drivers include charges related to a workforce reduction program, a loss on the sale of Peoples, lower margins from merchant generation operations and impairment charges related to certain merchant generation facilities.
2009VS. 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 base 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.
2008VS. 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:
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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.
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:
2009VS. 2008
Net Revenue decreased 5%, primarily reflecting:
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These decreases were partially offset by:
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Other operations and maintenance expense increased 17%, primarily reflecting the combined effects of:
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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 chargesincreased 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.
2008VS. 2007
Net Revenue increased 6%, primarily reflecting:
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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These increases were partially offset by:
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Other operations and maintenance expense decreased 21%, primarily reflecting the combined effects of:
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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:
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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. SeeForward-Looking Statements for additional factors that could cause actual results to differ materially from predicted results.
SEGMENT RESULTSOF 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 | 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 |
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 |
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
2009VS. 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 | $ | — |
2008VS. 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 |
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 | 45.3 | (2 | ) | 46.0 | ||||||
Degree days (electric utility service area): | ||||||||||||
Cooling | 1,477 | (9 | ) | 1,621 | (10 | ) | 1,794 | |||||
Heating | 3,747 | 9 | 3,426 | (2 | ) | 3,500 |
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
2009VS. 2008
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Merchant generation margin | $ | 95 | $ | 0.16 | ||||
Outage costs | 7 | 0.01 | ||||||
Regulated electric sales: | ||||||||
Customer growth | 10 | 0.02 | ||||||
Rate adjustment clause(1) | 53 | 0.09 | ||||||
Other(2) | (59 | ) | (0.10 | ) | ||||
Depreciation and amortization | (42 | ) | (0.07 | ) | ||||
Sales of emissions allowances | (18 | ) | (0.03 | ) | ||||
Other | 8 | 0.01 | ||||||
Share dilution | — | (0.04 | ) | |||||
Change in net income contribution | $ | 54 | $ | 0.05 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
2008VS. 2007
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Virginia fuel expenses(1) | $ | 243 | $ | 0.37 | ||||
Merchant generation margin | 174 | 0.27 | ||||||
Interest expense | 41 | 0.06 | ||||||
Depreciation and amortization | (37 | ) | (0.06 | ) | ||||
Regulated electric sales: | ||||||||
Weather | (27 | ) | (0.04 | ) | ||||
Customer growth | 16 | 0.03 | ||||||
Other(2) | 26 | 0.04 | ||||||
Other | 35 | 0.05 | ||||||
Share accretion | — | 0.24 | ||||||
Change in net income contribution | $ | 471 | $ | 0.96 |
Dominion Energy
Presented below are operating statistics related to Dominion Energy’s operations:
Year Ended December 31, | 2009 | % Change | 2008 | % Change | 2007 | ||||||||||
Gas distribution throughput (bcf): | |||||||||||||||
Sales | 43 | (31 | )% | 62 | (2 | )% | 63 | ||||||||
Transportation | 208 | (8 | ) | 225 | 3 | 219 | |||||||||
Heating degree days | 5,847 | (4 | ) | 6,065 | 5 | 5,783 | |||||||||
Average gas distribution customer accounts (thousands)(1): | |||||||||||||||
Sales | 321 | (36 | ) | 503 | (4 | ) | 525 | ||||||||
Transportation | 988 | 21 | 814 | 2 | 800 | ||||||||||
Production(2) (bcfe) | 52.3 | (19 | ) | 64.6 | 12 | 57.6 | |||||||||
Average realized prices without hedging results (per mcfe) | $ | 4.11 | (53 | ) | $ | 8.73 | 33 | $ | 6.55 | ||||||
Average realized prices with hedging results (per mcfe) | 7.25 | (15 | ) | 8.50 | 30 | 6.55 | |||||||||
DD&A (unit of production rate per mcfe) | 1.50 | (22 | ) | 1.93 | 15 | 1.68 | |||||||||
Average production (lifting) cost (per mcfe)(3) | 1.21 | (12 | ) | 1.37 | 7 | 1.28 | |||||||||
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:
2009VS. 2008
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Cove Point expansion revenue | $ | 88 | $ | 0.15 | ||||
DD&A—gas and oil | 28 | 0.04 | ||||||
Producer services | 10 | 0.02 | ||||||
Gas and oil—production(1) | (63 | ) | (0.11 | ) | ||||
Change in state tax legislation(2) | (16 | ) | (0.02 | ) | ||||
Share dilution | — | (0.02 | ) | |||||
Change in net income contribution | $ | 47 | $ | 0.06 |
2008VS. 2007
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Gas and oil—prices | $ | 44 | $ | 0.07 | ||||
Gas and oil—production(1) | 40 | 0.06 | ||||||
DD&A—gas and oil | (17 | ) | (0.03 | ) | ||||
Producer services | (6 | ) | (0.01 | ) | ||||
Other | 22 | 0.04 | ||||||
Share accretion | — | 0.09 | ||||||
Change in net income contribution | $ | 83 | $ | 0.22 | ||||
Included below are the volumes and weighted-average prices associated with hedges in place for Dominion’s Appalachian E&P operations as of December 31, 2009, by applicable time period.
Natural Gas | |||||
Year | Hedged production (bcf) | Average hedge price (per mcf) | |||
2010 | 26.6 | $ | 7.67 | ||
2011 | 6.5 | 6.83 |
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results:
Year Ended December 31, | 2009 | 2008 | 2007 | |||||||||
(millions, except EPS amounts) | ||||||||||||
Specific items attributable to operating segments | $ | (677 | ) | $ | (137 | ) | $ | (618 | ) | |||
Sale of U.S. E&P business | — | (26 | ) | 1,426 | ||||||||
Divested U.S. E&P operations | — | — | 252 | |||||||||
Peoples operations | 26 | 71 | 45 | |||||||||
Other corporate operations | (244 | ) | (151 | ) | (124 | ) | ||||||
Total net benefit (expense) | $ | (895 | ) | $ | (243 | ) | $ | 981 | ||||
EPS impact | $ | (1.51 | ) | $ | (0.41 | ) | $ | 1.50 |
SPECIFIC ITEMS ATTRIBUTABLETO OPERATING SEGMENTS
Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 27 to the Consolidated Financial Statements for discussion of these items.
SALEOF U.S. E&P BUSINESS
The sale of Dominion’s U.S. non-Appalachian E&P business reflects the $2.1 billion after-tax gain recognized in 2007 on the sale, partially offset by charges related to the divestitures as well as charges associated with the early retirement of debt with proceeds from the sale. The 2008 amount reflects post-closing adjustments to the gain on the sale. See Note 4 to the Consolidated Financial Statements for discussion of these items.
PEOPLES OPERATIONS
Income from Peoples decreased $45 million in 2009 as compared to 2008 and increased $26 million in 2008 as compared to 2007 primarily reflecting a $47 million ($28 million after-tax) benefit in 2008 from the re-establishment of certain regulatory assets in connection with the agreement to sell these subsidiaries to the SteelRiver Buyer. Regulatory assets of $166 million ($104 million after-tax) were written off in 2006 in connection with the previous sales agreement with Equitable. See Notes 4 and 6 to the Consolidated Financial Statements for discussion of these items.
OTHER CORPORATE OPERATIONS
The net expenses associated with other corporate operations for 2009 increased by $93 million as compared to 2008, primarily due to the absence of the following 2008 items:
|
|
The net expenses associated with other corporate operations for 2008 increased by $27 million as compared to 2007, primarily reflecting a decrease in tax benefits, higher interest expense and the absence of interest income earned on the proceeds received from the sale of Dominion’s non-Appalachian E&P business in 2007. The decrease in tax benefits primarily reflects the net impact of the following items:
|
|
|
The increase in net expenses was partially offset by the impact of lower impairment charges in 2008 related to the disposition of certain DCI investments.
SELECTED INFORMATION—ENERGY TRADING ACTIVITIES
Dominion engages in energy trading, marketing and hedging activities to complement its integrated energy businesses and facilitate its risk management activities. As part of these operations, Dominion enters into contracts for purchases and sales of energy-related commodities, including electricity, natural gas and other energy-related products. Settlements of contracts may require physical delivery of the underlying commodity or cash settlement. Dominion also enters into contracts with the objective of benefiting from changes in prices. For example, after entering into a contract to purchase a commodity, Dominion typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, Dominion may receive a net cash margin (a realized gain), or may pay a net cash margin (a realized loss). Dominion continually monitors its contract positions, considering location and timing of delivery or settlement for each energy commodity in relation to market price activity.
A summary of the changes in the unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes follows:
Amount | ||||
(millions) | ||||
Net unrealized gain at December 31, 2008 | $ | 43 | ||
Contracts realized or otherwise settled during the period | (40 | ) | ||
Net unrealized gain at inception of contracts initiated during the period | — | |||
Change in unrealized gains and losses | 39 | |||
Changes in unrealized gains and losses attributable to changes in valuation techniques | — | |||
Net unrealized gain at December 31, 2009 | $ | 42 |
The balance of net unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes at December 31, 2009, is summarized in the following table based on the approach used to determine fair value:
Maturity Based on Contract Settlement or Delivery Date(s) | |||||||||||||||||
Source of Fair Value | 2010 | 2011 - 2012 | 2013 - 2014 | 2015 and thereafter | Total | ||||||||||||
(millions) | |||||||||||||||||
Actively-quoted – | $ | 8 | $ | 7 | $ | — | $ | — | $ | 15 | |||||||
Other external | 24 | (11 | ) | — | — | 13 | |||||||||||
Models and other valuation methods – Level 3(3) | 4 | 10 | 1 | (1 | ) | 14 | |||||||||||
Total | $ | 36 | $ | 6 | $ | 1 | $ | (1 | ) | $ | 42 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
VIRGINIA POWER
RESULTSOF OPERATIONS
Presented below is a summary of Virginia Power’s consolidated results:
Year Ended December 31, | 2009 | $ Change | 2008 | $ Change | 2007 | |||||||||||
(millions) | ||||||||||||||||
Net Income | $ | 356 | $ | (508 | ) | $ | 864 | $ | 416 | $ | 448 | |||||
Overview
2009VS. 2008
Net income decreased 59%, primarily due to a charge in connection with the proposed settlement of the 2009 rate case proceedings and an increase in outage costs related to scheduled outages at certain nuclear and fossil generating facilities.
2008VS. 2007
Net income increased 93%, primarily due to the reinstatement of annual fuel rate adjustments for the Virginia jurisdiction of Virginia Power’s generation operations effective July 1, 2007, with deferred fuel accounting for over- or under-recoveries of fuel costs, and the absence of an extraordinary charge incurred in 2007 in connection with the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion’s results of operations:
Year Ended) December 31, | 2010 | $ Change | 2009 | $ Change | 2008 | |||||||||||||||
(millions) | ||||||||||||||||||||
Operating Revenue | $ | 15,197 | $ | 399 | $ | 14,798 | $ | (1,097 | ) | $ | 15,895 | |||||||||
Electric fuel and other energy-related purchases | 4,150 | (135 | ) | 4,285 | 262 | 4,023 | ||||||||||||||
Purchased electric capacity | 453 | 42 | 411 | — | 411 | |||||||||||||||
Purchased gas | 2,050 | (150 | ) | 2,200 | (966 | ) | 3,166 | |||||||||||||
Net Revenue | 8,544 | 642 | 7,902 | (393 | ) | 8,295 | ||||||||||||||
Other operations and maintenance | 3,724 | 12 | 3,712 | 428 | 3,284 | |||||||||||||||
Depreciation, depletion and amortization | 1,055 | (83 | ) | 1,138 | 104 | 1,034 | ||||||||||||||
Other taxes | 532 | 49 | 483 | (10 | ) | 493 | ||||||||||||||
Gain on sale of Appalachian E&P operations | 2,467 | 2,467 | — | — | — | |||||||||||||||
Other income (loss) | 169 | (25 | ) | 194 | 236 | (42 | ) | |||||||||||||
Interest and related charges | 832 | (57 | ) | 889 | 60 | 829 | ||||||||||||||
Income tax expense | 2,057 | 1,461 | 596 | (357 | ) | 953 | ||||||||||||||
Income (loss) from discontinued operations | (155 | ) | (181 | ) | 26 | (164 | ) | 190 |
An analysis of Dominion’s results of operations follows:
2010VS. 2009
Net Revenue increased 8%, primarily reflecting:
Ÿ | A $1.1 billion increase from electric utility operations, primarily reflecting: |
Ÿ | The absence of a charge for the settlement of Virginia Power’s 2009 base rate case proceedings ($570 million); |
Ÿ | The impact of Riders C1 and C2, R, S and T ($279 million); |
Ÿ | An increase in sales to retail customers primarily due to an increase in cooling degree days ($248 million); and |
Ÿ | An increase in ancillary revenues received from PJM ($78 million), primarily reflecting an increase in the scheduled dispatch of gas and oil-fired generation units to meet higher demand; partially offset by |
Ÿ | A decrease primarily due to the impact of unfavorable economic conditions on customer usage and other factors ($75 million); |
Ÿ | A $98 million increase from regulated natural gas distribution operations primarily reflecting increased rider revenue associated with the recovery of bad debt expense ($60 million) and an increase in base rates ($40 million); and |
Ÿ | A $46 million increase related to natural gas transmission operations largely due to the completion of the Cove Point expansion project. |
These increases were partially offset by:
Ÿ | A $356 million decrease from merchant generation operations due to a decrease at certain nuclear generating facilities ($237 million) primarily due to lower realized prices, a decline in margins at certain fossil generation facilities ($70 million) |
37 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
primarily due to an increase in fuel prices and the expiration of certain requirements-based power sales contracts in December 2009 ($49 million); |
Ÿ | A $222 million decrease reflecting the sale of substantially all of Dominion’s Appalachian E&P operations in April 2010; and |
Ÿ | A $40 million decrease in producer services primarily related to unfavorable price changes on economic hedging positions and lower physical margins, all associated with natural gas aggregation, marketing and trading activities. |
Other operations and maintenance increased $12 million primarily reflecting:
Ÿ | A $240 million net increase in salaries, wages and benefits primarily related to a workforce reduction program. As a result of the program, Dominion expects to avoid future annualized operations and maintenance expenses of approximately $100 million that would have otherwise been incurred; |
Ÿ | Impairment charges related to certain merchant generating facilities ($194 million); |
Ÿ | A $103 million increase due to the absence of a benefit in 2009 from a downward revision in the nuclear decommissioning ARO for a unit that is no longer in service; |
Ÿ | A $56 million increase in bad debt expense at regulated natural gas distribution operations, primarily related to low income assistance programs ($60 million). These expenses are recovered through rates and do not impact net income; and |
Ÿ | A $42 million increase in certain electric transmission-related expenditures. |
These increases were partially offset by:
Ÿ | A $434 million decrease in ceiling test impairment charges related to the carrying value of Dominion’s E&P properties; |
Ÿ | The absence of a $142 million write-off of previously deferred RTO costs in connection with the settlement of Virginia Power’s 2009 base rate case proceedings; and |
Ÿ | A $48 million decrease in outage costs due to a decrease in scheduled outage days primarily at certain merchant generation facilities. |
DD&Adecreased 7%, primarily due to the sale of Dominion’s Appalachian E&P operations ($45 million) and lower amortization due to decreased cost of emissions allowances consumed ($37 million).
Other taxesincreased 10%, primarily due to additional property tax from increased investments and higher rates ($16 million), an increase in gross receipts tax due to new non-regulated retail energy customers ($14 million) and higher payroll taxes associated with a workforce reduction program ($12 million).
Gain on sale of Appalachian E&P operationsreflects a gain on the sale of these operations, as described in Note 4 to the Consolidated Financial Statements.
Other incomedecreased 13%, primarily reflecting an increase in charitable contributions ($46 million) and a decrease in interest income ($15 million); partially offset by the absence of an impairment loss on an equity method investment ($30 million) and higher realized gains (including investment income) on nuclear decommissioning trust funds ($12 million).
Interest and related charges decreased 6%, primarily due to a benefit resulting from the net effect of the discontinuance of hedge accounting for certain interest rate hedges and subsequent changes in fair value of these interest rate derivatives ($73 million), partially offset by an increase in interest expense associated with the June 2009 hybrid issuance ($26 million).
Income tax expense increased $1.5 billion, primarily reflecting higher federal and state taxes largely due to the gain on the sale of Dominion’s Appalachian E&P business.
Loss from discontinued operationsprimarily reflects a loss on the sale of Peoples.
2009VS. 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 settlement of Virginia Power’s 2009 base 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 13%, 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 settlement of Virginia Power’s 2009 base rate case proceedings; and |
Ÿ | A $74 million increase in salaries, wages and benefits largely due to higher pension and other postretirement benefit costs. |
These increases were 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 electric transmission-related expenditures collectible under certain rate adjustment clauses. |
38 |
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 (loss) increased $236 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 chargesincreased 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 37%, primarily reflecting lower pre-tax income in 2009.
Outlook
In order to deliver favorable returns to investors, Dominion’s strategy is to continue focusing on its regulated businesses while maintaining upside potential in well-positioned nonregulated businesses. The goals of this strategy are to provide earnings per share growth, a growing dividend and a stable credit profile. Dominion’s 2010 results were positively impacted by the gain on the sale of substantially all of its Appalachian E&P operations. In 2011, Dominion’s operating businesses will likely experience a decrease in net income on a per share basis as compared to 2010. Dominion’s anticipated 2011 results reflect the following significant factors:
Ÿ | Lower realized margins from its merchant generation operations due to lower commodity prices and an increase in planned outages at certain nuclear and fossil facilities; |
Ÿ | A return to normal weather in its electric utility operations; and |
Ÿ | The absence of earnings from Appalachian E&P operations sold in April 2010; partially offset by |
Ÿ | Growth in electric sales resulting from the recovering economy; |
Ÿ | A benefit from rate adjustment clause revenue associated with Bear Garden and Virginia City Hybrid Energy Center; |
Ÿ | A reduction in certain operations and maintenance expenses resulting largely from the implementation of cost-containment measures, including the workforce reduction program discussed in Note 23 to the Consolidated Financial Statements; and |
Ÿ | Lower outage costs at certain electric utility generating facilities. |
Dominion also expects the bonus depreciation provisions of the tax legislation recently enacted by the U.S. Congress in 2010, discussed in Note 6 to the Consolidated Financial Statements, to reduce income taxes otherwise payable by $1.2 billion to $2.1 billion during 2011 through 2013. The acceleration of these tax deductions is expected to reduce the domestic production activities income tax deduction through 2012 and will also increase deferred taxes, thereby reducing rate base for regulated operations. However, Dominion plans to partially mitigate the earnings per share impact of these items by using the cash tax savings to
repurchase common stock in 2011 and reduce the amount of debt that would have otherwise been issued over the next three years. In addition, Dominion does not plan any market issuances of common stock in 2011 or 2012.
Dominion expects its operating businesses to provide five percent to six percent growth in net income on a per share basis in 2012 as compared to 2011 primarily due to its assumptions regarding construction and operation of new infrastructure in its utility operations, fewer merchant outages and an anticipated rise in commodity prices and energy demand.
SEGMENT RESULTSOF 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, | 2010 | 2009 | 2008 | |||||||||||||||||||||
Net Income attribut- | Diluted EPS | Net Income attribut- | Diluted EPS | Net Income attribut- | Diluted EPS | |||||||||||||||||||
(millions, except EPS) | ||||||||||||||||||||||||
DVP | $ | 448 | $ | 0.76 | $ | 384 | $ | 0.65 | $ | 380 | $ | 0.65 | ||||||||||||
Dominion Generation | 1,291 | 2.19 | 1,281 | 2.16 | 1,227 | 2.11 | ||||||||||||||||||
Dominion Energy | 475 | 0.80 | 517 | 0.87 | 470 | 0.81 | ||||||||||||||||||
Primary operating segments | 2,214 | 3.75 | 2,182 | 3.68 | 2,077 | 3.57 | ||||||||||||||||||
Corporate and Other | 594 | 1.01 | (895 | ) | (1.51 | ) | (243 | ) | (0.41 | ) | ||||||||||||||
Consolidated | $ | 2,808 | $ | 4.76 | $ | 1,287 | $ | 2.17 | $ | 1,834 | $ | 3.16 |
DVP
Presented below are operating statistics related to DVP’s operations:
Year Ended December 31, | 2010 | % Change | 2009 | % Change | 2008 | |||||||||||||||
Electricity delivered (million MWh) | 84.5 | 4 | % | 81.4 | (3 | )% | 84.0 | |||||||||||||
Degree days: | ||||||||||||||||||||
Cooling(1) | 2,090 | 42 | 1,477 | (9 | ) | 1,621 | ||||||||||||||
Heating(2) | 3,819 | 2 | 3,747 | 9 | 3,426 | |||||||||||||||
Average electric distribution customer accounts (thousands)(3) | 2,422 | 1 | 2,404 | 1 | 2,386 | |||||||||||||||
Average retail energy marketing customer accounts (thousands)(3) | 2,037 | 19 | 1,718 | 7 | 1,601 |
(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. |
39 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
2010VS. 2009
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Regulated electric sales: | ||||||||
Weather | $ | 48 | $ | 0.08 | ||||
FERC transmission revenue | 40 | 0.07 | ||||||
Other | (4 | ) | (0.01 | ) | ||||
Depreciation and amortization | (15 | ) | (0.03 | ) | ||||
Storm damage and service restoration-distribution operations(1) | (11 | ) | (0.02 | ) | ||||
Other | 6 | 0.01 | ||||||
Share accretion | — | 0.01 | ||||||
Change in net income contribution | $ | 64 | $ | 0.11 |
(1) | Reflects an increase in storm damage and service restoration costs associated with electric distribution operations resulting from more severe weather during 2010. |
2009VS. 2008
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Regulated electric sales: | ||||||||
FERC transmission revenue | $ | 28 | $ | 0.05 | ||||
Customer growth | 5 | 0.01 | ||||||
Other(1) | (14 | ) | (0.02 | ) | ||||
Storm damage and service restoration-distribution operations(2) | 5 | 0.01 | ||||||
Depreciation and amortization | (7 | ) | (0.01 | ) | ||||
Other | (13 | ) | (0.03 | ) | ||||
Share dilution | — | (0.01 | ) | |||||
Change in net income contribution | $ | 4 | $ | — |
(1) | Primarily reflects the impact of unfavorable economic conditions on customer usage and other factors. |
(2) | Reflects a decrease in storm damage and service restoration costs associated with electric distribution operations resulting from less severe weather during 2009. |
Dominion Generation
Presented below are operating statistics related to Dominion Generation’s operations:
Year Ended December 31, | 2010 | % Change | 2009 | % Change | 2008 | |||||||||||||||
Electricity supplied (million MWh): | ||||||||||||||||||||
Utility | 84.5 | 4% | 81.4 | (3)% | 84.0 | |||||||||||||||
Merchant | 47.3 | (1) | 48.0 | 6 | 45.3 | |||||||||||||||
Degree days (electric utility service area): | ||||||||||||||||||||
Cooling | 2,090 | 42 | 1,477 | (9) | 1,621 | |||||||||||||||
Heating | 3,819 | 2 | 3,747 | 9 | 3,426 |
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
2010VS. 2009
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Regulated electric sales: | ||||||||
Weather | $ | 104 | $ | 0.18 | ||||
Rate adjustment clause revenue | 95 | 0.16 | ||||||
Other | (23 | ) | (0.04 | ) | ||||
Outage costs | 29 | 0.05 | ||||||
Other O&M expenses(1) | 32 | 0.05 | ||||||
PJM ancillary services | 27 | 0.05 | ||||||
Merchant generation margin | (209 | ) | (0.36 | ) | ||||
Income and other taxes(2) | (44 | ) | (0.08 | ) | ||||
Other | (1 | ) | — | |||||
Share accretion | — | 0.02 | ||||||
Change in net income contribution | $ | 10 | $ | 0.03 |
(1) | Reflects the 2010 implementation of cost containment measures including a workforce reduction program. |
(2) | Reflects the absence of 2009 investment tax credits related to Fowler Ridge and a decrease in the domestic production activities deduction, primarily due to the absence of a 2009 benefit from the remeasurement of tax uncertainties related to this deduction, as well as the 2010 impact of bonus depreciation on this deduction. |
2009VS. 2008
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Merchant generation margin | $ | 95 | $ | 0.16 | ||||
Outage costs | 7 | 0.01 | ||||||
Regulated electric sales: | ||||||||
Customer growth | 10 | 0.02 | ||||||
Rate adjustment clause revenue(1) | 53 | 0.09 | ||||||
Other(2) | (59 | ) | (0.10 | ) | ||||
Depreciation and amortization | (42 | ) | (0.07 | ) | ||||
Sales of emissions allowances | (18 | ) | (0.03 | ) | ||||
Other | 8 | 0.01 | ||||||
Share dilution | — | (0.04 | ) | |||||
Change in net income contribution | $ | 54 | $ | 0.05 |
(1) | Reflects the incremental impact of Rider S. |
(2) | Primarily reflects lower sales to wholesale customers, as well as the impact of unfavorable economic conditions on customer usage and other factors. |
Dominion Energy
Presented below are selected operating statistics related to Dominion Energy’s operations. As discussed in Note 4, in April 2010 Dominion completed the sale of substantially all of its Appalachian E&P operations. As a result, production-related operating statistics for the Dominion Energy segment are no longer significant.
Year Ended December 31, | 2010 | % Change | 2009 | % Change | 2008 | |||||||||||||||
Gas distribution throughput (bcf): | ||||||||||||||||||||
Sales | 31 | (28)% | 43 | (31)% | 62 | |||||||||||||||
Transportation | 241 | 16 | 208 | (8) | 225 | |||||||||||||||
Heating degree days | 5,682 | (3) | 5,847 | (4) | 6,065 | |||||||||||||||
Average gas distribution customer accounts (thousands)(1): | ||||||||||||||||||||
Sales | 260 | (19) | 321 | (36) | 503 | |||||||||||||||
Transportation | 1,042 | 5 | 988 | 21 | 814 |
(1) | Thirteen-month average. |
40 |
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:
2010VS. 2009
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
E&P disposed operations | $ | (61 | ) | $ | (0.11 | ) | ||
Producer services | (27 | ) | (0.05 | ) | ||||
Gas distribution margin: | ||||||||
AMR and PIR revenue(1) | 11 | 0.02 | ||||||
Base gas sale(2) | 10 | 0.02 | ||||||
Weather | (2 | ) | — | |||||
Other | 15 | 0.03 | ||||||
Cove Point expansion revenue | 20 | 0.03 | ||||||
Other | (8 | ) | (0.02 | ) | ||||
Share accretion | — | 0.01 | ||||||
Change in net income contribution | $ | (42 | ) | $ | (0.07 | ) |
(1) | Primarily reflects an allowed return on investment through the AMR and PIR programs. |
(2) | Reflects East Ohio’s sale of 3 bcf of base gas in December 2010 as the Company determined that it could operate its storage system and meet existing and anticipated contractual commitments with less base gas. |
2009VS. 2008
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Cove Point expansion revenue | $ | 88 | $ | 0.15 | ||||
DD&A-gas and oil | 28 | 0.04 | ||||||
Producer services | 10 | 0.02 | ||||||
Gas and oil-production(1) | (63 | ) | (0.11 | ) | ||||
Change in state tax legislation(2) | (16 | ) | (0.02 | ) | ||||
Share dilution | — | (0.02 | ) | |||||
Change in net income contribution | $ | 47 | $ | 0.06 |
(1) | Primarily reflects a decrease in volumes associated with VPP royalty interests that expired in February 2009. |
(2) | Reflects the absence of a 2008 benefit resulting from the reduction of deferred tax liabilities related to the enactment of West Virginia income tax rate reductions. |
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results:
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||||
(millions, except EPS amounts) | ||||||||||||
Specific items attributable to operating segments | $ | 1,014 | $ | (688 | ) | $ | (134 | ) | ||||
Specific items attributable to Corporate and Other segment: | ||||||||||||
Peoples discontinued operations | (155 | ) | 26 | 192 | ||||||||
Other | (22 | ) | 7 | (61 | ) | |||||||
Total specific items | 837 | (655 | ) | (3 | ) | |||||||
Other corporate operations | (243 | ) | (240 | ) | (240 | ) | ||||||
Total net benefit (expense) | $ | 594 | $ | (895 | ) | $ | (243 | ) | ||||
EPS impact | $ | 1.01 | $ | (1.51 | ) | $ | (0.41 | ) |
TOTAL SPECIFIC ITEMS
Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 27 to the Consolidated Financial Statements for discussion of these items.
VIRGINIA POWER
RESULTSOF OPERATIONS
Presented below is a summary of Virginia Power’s consolidated results:
Year Ended December 31, | 2010 | $ Change | 2009 | $ Change | 2008 | |||||||||||||||
(millions) | ||||||||||||||||||||
Net Income | $ | 852 | $ | 496 | $ | 356 | $ | (508 | ) | $ | 864 | |||||||||
Overview
2010VS. 2009
Net income increased by 139%, primarily reflecting the absence of a charge in connection with the settlement of the 2009 base rate case proceedings, favorable weather and a benefit from rate adjustment clauses, partially offset by charges related to a workforce reduction program.
2009VS. 2008
Net income decreased 59%, primarily due to a charge in connection with the settlement of the 2009 base rate case proceedings and an increase in outage costs related to scheduled outages at certain nuclear and fossil generating facilities.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Power’s results of operations:
Year Ended December 31, | 2009 | $ Change | 2008 | $ Change | 2007 | 2010 | $ Change | 2009 | $ Change | 2008 | ||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||
Operating Revenue | $ | 6,584 | $ | (350 | ) | $ | 6,934 | $ | 753 | $ | 6,181 | $ | 7,219 | $ | 635 | $ | 6,584 | $ | (350 | ) | $ | 6,934 | ||||||||||||||||
Electric fuel and other energy-related purchases | 2,972 | 265 | 2,707 | 319 | 2,388 | 2,495 | (477 | ) | 2,972 | 265 | 2,707 | |||||||||||||||||||||||||||
Purchased electric capacity | 409 | (1 | ) | 410 | (19 | ) | 429 | 449 | 40 | 409 | (1 | ) | 410 | |||||||||||||||||||||||||
Net Revenue | 3,203 | (614 | ) | 3,817 | 453 | 3,364 | 4,275 | 1,072 | 3,203 | (614 | ) | 3,817 | ||||||||||||||||||||||||||
Other operations and maintenance | 1,623 | 218 | 1,405 | 8 | 1,397 | 1,745 | 122 | 1,623 | 218 | 1,405 | ||||||||||||||||||||||||||||
Depreciation and amortization | 641 | 33 | 608 | 40 | 568 | 671 | 30 | 641 | 33 | 608 | ||||||||||||||||||||||||||||
Other taxes | 191 | 8 | 183 | 10 | 173 | 218 | 27 | 191 | 8 | 183 | ||||||||||||||||||||||||||||
Other income | 104 | 52 | 52 | (3 | ) | 55 | 100 | (4 | ) | 104 | 52 | 52 | ||||||||||||||||||||||||||
Interest and related charges | 349 | 40 | 309 | 5 | 304 | 347 | (2 | ) | 349 | 40 | 309 | |||||||||||||||||||||||||||
Income tax expense | 147 | (353 | ) | 500 | 129 | 371 | 542 | 395 | 147 | (353 | ) | 500 | ||||||||||||||||||||||||||
Extraordinary item, net of tax | — | — | — | 158 | (158 | ) | ||||||||||||||||||||||||||||||||
41 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
An analysis of Virginia Power’s results of operations follows:
2010VS. 2009
Net Revenue increased 33%, primarily reflecting:
Ÿ | The absence of a charge for the settlement of the 2009 base rate case proceedings ($570 million); |
Ÿ | The impact of Riders C1 and C2, R, S and T ($279 million); |
Ÿ | An increase in sales to retail customers primarily due to an increase in cooling degree days ($248 million); and |
Ÿ | An increase in ancillary revenues received from PJM ($78 million), primarily reflecting an increase in the scheduled dispatch of gas and oil-fired generation units to meet higher demand. |
These increases were partially offset by:
Ÿ | A decrease primarily due to the impact of unfavorable economic conditions on customer usage and other factors ($75 million). |
Other operations and maintenance increased 8%, primarily reflecting:
Ÿ | A $177 million net increase in salaries, wages and benefits primarily due to a workforce reduction program. As a result of the program, Virginia Power expects to avoid future annualized operations and maintenance expenses of approximately $50 million that would have otherwise been incurred; |
Ÿ | A $42 million increase in certain electric transmission-related expenditures; and |
Ÿ | A $19 million increase in storm damage and service restoration costs. |
These increases were partially offset by:
Ÿ | The absence of a $130 million write-off of previously deferred RTO costs in connection with the settlement of Virginia Power’s 2009 base rate case proceedings. |
Depreciation and amortization expense increased 5%, primarily due to property additions.
Other taxes increased 14%, primarily reflecting additional property tax due to increased investments and higher rates ($12 million), incremental use tax that is recoverable through a customer surcharge ($8 million) and higher payroll taxes associated with a workforce reduction program ($7 million).
Income tax expense increased $395 million, primarily reflecting higher pretax income in 2010.
2009VS. 2008
Net Revenue decreased 16%, primarily due to a charge for the proposed settlement of the 2009 base rate case proceedings.
Other operations and maintenance expenseincreased 16%, primarily reflecting:
Ÿ | A $130 million write-off of previously deferred RTO costs in connection with the |
Ÿ | A $64 million increase in outage costs related to scheduled outages at certain nuclear and fossil generating facilities; |
Ÿ | A $43 million increase resulting from higher salaries, wages and benefits largely due to higher pension and other postretirement benefit costs, and other general and administrative costs; and |
Ÿ | A $28 million decrease in gains from the sale of emissions |
These increases were partially offset by:
Ÿ | A $29 million decrease largely due to the deferral of transmission-related expenditures collectible under certain rate adjustment clauses. |
Depreciation and amortization expense increased 5%, primarily due to property additions.
Other income increased by $52 million primarily due to an increase in the equity component of AFUDC as a result of construction and expansion projects.
Interest and related chargesincreased 13%, primarily due to the absence of a $23 million benefit related to the redemption of Virginia Power’s Callable and Puttable Enhanced Securities in 2008, and a $17 million impact largely due to the impact from additional borrowings.
Income tax expense decreased 71%, reflecting lower pre-tax income in 2009.
2008VS. 2007
Net Revenue increased 13%, primarily reflecting 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.
Other operations and maintenance expense increased 1%, primarily reflecting:
|
|
Depreciation and amortization expense increased 7%, primarily due to an increase in depreciation rates for generation assets ($36 million) and property additions ($15 million), partially offset by an $11 million decrease in amortization expense primarily associated with lower consumption of emissions allowances.
Interest and related chargesincreased 2%, primarily due to a $43 million impact from additional borrowings, partially offset by a $23 million benefit related to the redemption of Virginia Power’s Callable and Puttable Enhanced Securities due to a difference between the amount of interest expense accrued and the amount of interest expense paid and lower interest rates on variable rate debt ($15 million).
Income tax expense increased 35%, reflecting higher pre-tax income in 2008.
Extraordinary item reflects the absence of a $158 million after-tax charge in 2007 in connection with the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations.
Outlook
Virginia Power expects to provide stable growth in net income in 2010.2011. Virginia Power’s anticipated 20102011 results reflect the following significant factors:
Ÿ |
|
Ÿ | A benefit from rate adjustment |
Ÿ | A reduction in certain operations and maintenance expenses resulting largely from the implementation of cost-containment measures, including the workforce reduction program discussed in Note 23 to the Consolidated Financial Statements; and |
Ÿ |
|
Ÿ | A return to normal weather in |
IfVirginia Power also expects the final resolutionbonus depreciation provisions of the tax legislation recently enacted by the U.S. Congress in 2010, discussed in Note 6 to the Consolidated Financial Statements, to reduce income taxes otherwise payable by $600 million to $1.2 billion during 2011 through 2013. The acceleration of these tax deductions is expected to reduce the domestic production activities income tax deduction through 2012 and will also increase deferred taxes, thereby reducing the regulated rate base. However, Virginia Power’s 2009 rate case proceedings differs materially from management’s expectations it could adversely affect Virginia Power’s resultsPower plans to partially mitigate the earnings impact of operations, financial condition andthese items by using the cash flows. SeeForward-Looking Statements for additional factorstax savings to reduce the amount of debt that could cause actual results to differ materially from predicted results.would have otherwise been issued over the next three years.
SEGMENT RESULTSOF OPERATIONS
Presented below is a summary of contributions by Virginia Power’s operating segments to net income:
Year Ended December 31, | 2009 | $ Change | 2008 | $ Change | 2007 | 2010 | $ Change | 2009 | $ Change | 2008 | ||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
DVP | $ | 313 | $ | 6 | $ | 307 | $ | (35 | ) | $ | 342 | $ | 377 | $ | 64 | $ | 313 | $ | 6 | $ | 307 | |||||||||||||||||||
Dominion Generation | 475 | (108 | ) | 583 | 307 | 276 | 630 | 155 | 475 | (108 | ) | 583 | ||||||||||||||||||||||||||||
Primary operating segments | 788 | (102 | ) | 890 | 272 | 618 | 1,007 | 219 | 788 | (102 | ) | 890 | ||||||||||||||||||||||||||||
Corporate and Other | (432 | ) | (406 | ) | (26 | ) | 144 | (170 | ) | (155 | ) | 277 | (432 | ) | (406 | ) | (26 | ) | ||||||||||||||||||||||
Consolidated | $ | 356 | $ | (508 | ) | $ | 864 | $ | 416 | $ | 448 | $ | 852 | $ | 496 | $ | 356 | $ | (508 | ) | $ | 864 |
42 |
DVP
Presented below are operating statistics related to Virginia Power’s DVP segment:
Year Ended December 31, | 2009 | % Change | 2008 | % Change | 2007 | 2010 | % Change | 2009 | % Change | 2008 | ||||||||||||||||||||||
Electricity delivered (million MWh) | 81.4 | (3 | )% | 84.0 | (1 | )% | 84.7 | 84.5 | 4% | 81.4 | (3 | )% | 84.0 | |||||||||||||||||||
Degree days (electric service area): | ||||||||||||||||||||||||||||||||
Cooling | 1,477 | (9 | ) | 1,621 | (10 | ) | 1,794 | 2,090 | 42 | 1,477 | (9 | ) | 1,621 | |||||||||||||||||||
Heating | 3,747 | 9 | 3,426 | (2 | ) | 3,500 | 3,819 | 2 | 3,747 | 9 | 3,426 | |||||||||||||||||||||
Average electric delivery customer accounts (thousands)(4) | 2,404 | 1 | 2,386 | 1 | 2,361 | |||||||||||||||||||||||||||
Average electric distribution customer accounts (thousands)(3) | 2,422 | 1 | 2,404 | 1 | 2,386 | |||||||||||||||||||||||||||
(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. |
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. |
Thirteen-month average. |
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
20092010VS. 20082009
Increase (Decrease) | Increase (Decrease) | |||||||
(millions) | ||||||||
(millions, except EPS) | ||||||||
Regulated electric sales: | ||||||||
Customer growth | $ | 5 | ||||||
Rate adjustment clause(1) | 13 | |||||||
Weather | $ | 48 | ||||||
FERC transmission revenue | 40 | |||||||
Other | (6 | ) | (4 | ) | ||||
Storm damage and service restoration—distribution operations(3) | 5 | |||||||
Depreciation and amortization | (15 | ) | ||||||
Storm damage and service restoration—distribution operations(1) | (11 | ) | ||||||
Other | (11 | ) | 6 | |||||
Change in net income contribution | $ | 6 | $ | 64 |
(1) | Reflects |
2009VS. 2008
Increase (Decrease) | ||||
(millions) | ||||
Regulated electric sales: | ||||
FERC transmission revenue | $ | 28 | ||
Customer growth | 5 | |||
Other(1) | (14 | ) | ||
Storm damage and service restoration—distribution operations(2) | 5 | |||
Depreciation and amortization | (7 | ) | ||
Other | (11 | ) | ||
Change in net income contribution | $ | 6 |
Primarily reflects the impact of unfavorable economic conditions on customer usage and other factors. |
Reflects a decrease in storm damage and service restoration costs associated with electric distribution operations resulting from less severe weather during 2009. |
2008VS. 2007
Increase (Decrease) | ||||
(millions) | ||||
Regulated electric sales: | ||||
Weather | $ | (14 | ) | |
Customer growth | 9 | |||
Other | (9 | ) | ||
Storm damage and service restoration—distribution operations(1) | (10 | ) | ||
Interest expense | (9 | ) | ||
Other | (2 | ) | ||
Change in net income contribution | $ | (35 | ) |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion Generation
Presented below are operating statistics related to Virginia Power’s Dominion Generation segment:
Year Ended December 31, | 2009 | % Change | 2008 | % Change | 2007 | 2010 | % Change | 2009 | % Change | 2008 | ||||||||||||||||||||||
Electricity supplied (million MWh) | 81.4 | (3 | )% | 84.0 | (1 | )% | 84.7 | 84.5 | 4% | 81.4 | (3)% | 84.0 | ||||||||||||||||||||
Degree days (electric service area): | ||||||||||||||||||||||||||||||||
Cooling | 1,477 | (9 | ) | 1,621 | (10 | ) | 1,794 | 2,090 | 42 | 1,477 | (9) | 1,621 | ||||||||||||||||||||
Heating | 3,747 | 9 | 3,426 | (2 | ) | 3,500 | 3,819 | 2 | 3,747 | 9 | 3,426 | |||||||||||||||||||||
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
2010VS. 2009
Increase (Decrease) | ||||
(millions) | ||||
Regulated electric sales: | ||||
Weather | $ | 104 | ||
Rate adjustment clause revenue | 95 | |||
Other | (23 | ) | ||
PJM ancillary services | 27 | |||
Income and other taxes(1) | (24 | ) | ||
Energy supply margin(2) | (13 | ) | ||
Other | (11 | ) | ||
Change in net income contribution | $ | 155 |
(1) | Reflects a decrease in the domestic production activities deduction, primarily due to the absence of a 2009 benefit from the remeasurement of tax uncertainties related to this deduction, as well as the 2010 impact of bonus depreciation on this deduction. |
(2) | Primarily reflects a reduced benefit from FTRs, due to the crediting of certain FTRs allocated to Virginia Power against Virginia jurisdictional fuel factor expenses subject to deferral accounting beginning July 1, 2009. |
2009VS. 2008
Increase (Decrease) | Increase (Decrease) | |||||||
(millions) | ||||||||
Outage costs | $ | (36 | ) | $ | (36 | ) | ||
Ancillary service revenue | (21 | ) | ||||||
PJM ancillary services | (21 | ) | ||||||
Sale of emissions allowances | (17 | ) | (17 | ) | ||||
Interest expense | (15 | ) | (15 | ) | ||||
Depreciation expense | (13 | ) | (13 | ) | ||||
Regulated electric sales: | ||||||||
Customer growth | 10 | 10 | ||||||
Rate adjustment clause(1) | 53 | |||||||
Rate adjustment clause revenue(1) | 53 | |||||||
Other(2) | (59 | ) | (59 | ) | ||||
Other | (10 | ) | (10 | ) | ||||
Change in net income contribution | $ | (108 | ) | $ | (108 | ) |
(1) | Reflects the incremental impact of |
(2) | Primarily reflects lower sales to wholesale customers, as well as the impact of unfavorable economic conditions on customer usage and other factors. |
2008VS. 2007
Increase (Decrease) | ||||
(millions) | ||||
Virginia fuel expenses(1) | $ | 243 | ||
Outage costs | 38 | |||
Regulated electric sales: | ||||
Weather | (27 | ) | ||
Customer growth | 16 | |||
Other(2) | 26 | |||
Capacity expense | 13 | |||
Sale of emissions allowances | 7 | |||
Depreciation expense | (27 | ) | ||
Other | 18 | |||
Change in net income contribution | $ | 307 |
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results.
Year Ended December 31, | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Specific items attributable to operating segments | $ | (430 | ) | $ | (23 | ) | $ | (166 | ) | $ | (153 | ) | $ | (430 | ) | $ | (23 | ) | ||||||
Other corporate operations | (2 | ) | (3 | ) | (4 | ) | (2 | ) | (2 | ) | (3 | ) | ||||||||||||
Total net expense | $ | (432 | ) | $ | (26 | ) | $ | (170 | ) | $ | (155 | ) | $ | (432 | ) | $ | (26 | ) |
43 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
SPECIFIC ITEMS ATTRIBUTABLETO OPERATING SEGMENTS
Corporate and Other primarily includes specific items attributable to Virginia Power’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 27 to the Consolidated Financial Statements for a discussion of these items.
LIQUIDITYAND CAPITAL RESOURCES
Dominion and Virginia Power depend on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.
At December 31, 2009,2010, Dominion had $3.3$2 billion of unused capacity under its credit facilities, including $2.3 billion$559 million of unused capacity under a joint credit facilityfacilities available to Virginia Power. See additional discussion underCredit Facilities and Short-Term Debt.
A summary of Dominion’s cash flows is presented below:
Year Ended December 31, | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Cash and cash equivalents at beginning of year | $ | 71 | $ | 287 | $ | 142 | $ | 50 | $ | 71 | $ | 287 | ||||||||||||
Cash flows provided by (used in): | ||||||||||||||||||||||||
Operating activities | 3,786 | 2,676 | (230 | ) | 1,825 | 3,786 | 2,676 | |||||||||||||||||
Investing activities | (3,695 | ) | (3,490 | ) | 10,192 | 419 | (3,695 | ) | (3,490 | ) | ||||||||||||||
Financing activities | (112 | ) | 598 | (9,817 | ) | (2,232 | ) | (112 | ) | 598 | ||||||||||||||
Net increase (decrease) in cash and cash equivalents | (21 | ) | (216 | ) | 145 | 12 | (21 | ) | (216 | ) | ||||||||||||||
Cash and cash equivalents at end of year(1) | $ | 50 | $ | 71 | $ | 287 | $ | 62 | $ | 50 | $ | 71 |
(1) | 2009 |
A summary of Virginia Power’s cash flows is presented below:
Year Ended December 31, | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Cash and cash equivalents at beginning of year | $ | 27 | $ | 49 | $ | 18 | $ | 19 | $ | 27 | $ | 49 | ||||||||||||
Cash flows provided by (used in): | ||||||||||||||||||||||||
Operating activities | 1,970 | 1,235 | 1,216 | 1,409 | 1,970 | 1,235 | ||||||||||||||||||
Investing activities | (2,568 | ) | (2,003 | ) | (1,306 | ) | (2,425 | ) | (2,568 | ) | (2,003 | ) | ||||||||||||
Financing activities | 590 | 746 | 121 | 1,002 | 590 | 746 | ||||||||||||||||||
Net increase (decrease) in cash and cash equivalents | (8 | ) | (22 | ) | 31 | |||||||||||||||||||
Net decrease in cash and cash equivalents | (14 | ) | (8 | ) | (22 | ) | ||||||||||||||||||
Cash and cash equivalents at end of year | $ | 19 | $ | 27 | $ | 49 | $ | 5 | $ | 19 | $ | 27 |
Operating Cash Flows
In 2009,2010, net cash provided by Dominion’s operating activities increaseddecreased by approximately $1.1$2 billion, primarily due to higherlower deferred fuel and gas cost recoveries, higher margins in itscontributions to Dominion’s pension plans, the absence of disposed Appalachian E&P operations, lower merchant generation margins and gas transmission operations, and a favorable impact from changes in customer receivables as a result of lower fuel and gas prices. The increase wasrefunds related to the 2009 Virginia Power base rate case settlement, partially offset
by cash outflows related tolower income tax payments, lower margin collateral requirements and higher income tax payments as a resultthe favorable impact of higher estimated taxable income, which included a projected taxable gain from the planned sale of Peoplesweather and Hope that was expected to close in 2009.rate adjustment clauses on electric utility operations.
In 2009,2010, net cash provided by Virginia Power’s operating activities increaseddecreased by $735$561 million, primarily due to higherlower deferred fuel cost recoveries in its Virginia jurisdiction, refunds related to the 2009 Virginia base rate case settlement, and a favorable change in customer receivables,contributions to Dominion’s pension plans; partially offset by higherthe favorable impact of weather and rate adjustment clauses, and cash received for income tax payments.benefits in 2010, as compared to income taxes paid in 2009.
Dominion’s lower income tax payments and Virginia Power’s realization of income tax benefits in 2010 resulted in part from the bonus depreciation provisions of the tax legislation recently enacted by the U.S. Congress, discussed in Note 6 to the Consolidated Financial Statements.
Dominion believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In 2011, Dominion’s board of directors adopted a new dividend policy that raised its target payout ratio. The Board established an annual dividend rate of $1.97 per share of common stock, a 7.7% increase over the 2010 rate. Quarterly dividends are subject to declaration by the Board. Virginia Power believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and provide dividends to Dominion.
The Companies’ operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows which are discussed in Item 1A. Risk Factors.
CREDIT RISK
Dominion’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion’s credit exposure as of December 31, 20092010 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights.
Gross Credit Exposure | Credit Collateral | Net Credit Exposure | Gross Credit Exposure | Credit Collateral | Net Credit Exposure | ||||||||||||||||
(millions) | |||||||||||||||||||||
Investment grade(1) | $ | 585 | $ | 103 | $ | 482 | $ | 426 | $ | 26 | $ | 400 | |||||||||
Non-investment grade(2) | 7 | — | 7 | 10 | 3 | 7 | |||||||||||||||
No external ratings: | |||||||||||||||||||||
Internally rated—investment grade(3) | 130 | — | 130 | ||||||||||||||||||
Internally rated—non-investment grade(4) | 31 | — | 31 | ||||||||||||||||||
Internally rated-investment grade(3) | 102 | — | 102 | ||||||||||||||||||
Internally rated-non-investment grade(4) | 82 | — | 82 | ||||||||||||||||||
Total | $ | 753 | $ | 103 | $ | 650 | $ | 620 | $ | 29 | $ | 591 |
(1) | Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately |
(2) | The five largest counterparty exposures, combined, for this category represented approximately 1% of the total net credit exposure. |
(3) | The five largest counterparty exposures, combined, for this category represented approximately |
(4) | The five largest counterparty exposures, combined, for this category represented approximately |
44 |
Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Presented belowcustomers and is a summary of Virginia Power’s gross credit exposure as ofnot considered material at December 31, 2009, for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights.2010.
Gross Credit Exposure | Credit Collateral | Net Credit Exposure | |||||||
(millions) | |||||||||
Investment grade(1) | $ | 28 | $ | 11 | $ | 17 | |||
Non-investment grade(2) | 5 | — | 5 | ||||||
No external ratings: | |||||||||
Internally rated—investment grade(3) | 6 | — | 6 | ||||||
Internally rated—non-investment grade | — | — | — | ||||||
Total | $ | 39 | $ | 11 | $ | 28 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Investing Cash Flows
In 2009,2010, net cash provided by Dominion’s investing activities was $419 million as compared to net cash used in Dominion’s investing activities increased by $205 millionof $3.7 billion in 2009. This change is primarily due to an increasethe proceeds received from the sale of substantially all of Dominion’s Appalachian E&P operations in capital expenditures related to its electric utility operationsApril 2010 and the absencesale of Peoples in February 2010. While taxes and other costs of the sales are reflected in cash flow from operations, the gross proceeds from the assignment of natural gas drilling rights, partially offset by reduced investmentssales are reported in and a distributioncash flow from its Fowler Ridge wind farm investment in connection with non-recourse project financing proceeds received in September 2009.investing activities.
In 2009,2010, net cash used in Virginia Power’s investing activities increaseddecreased by $565$143 million, primarily reflectingdue to lower capital expenditures, partially offset by an increase in capital expenditures for generation and transmission construction projects, including the Virginia City Hybrid Energy Center.restricted cash equivalents designated to finance certain qualifying facilities.
Financing Cash Flows and Liquidity
Dominion and Virginia Power rely on banks and capital markets as significant sources of funding for capital requirements not satisfied by cash provided by their operations. As discussed inCredit Ratings, the Companies’ ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances and, in the case of Virginia Power, approval by the Virginia Commission.
Each of the Companies currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows the Companies to use automatic shelf registration statements to register any offering of securities, other than those for business combination transactions.
In 2009,2010, net cash used in Dominion’s financing activities was $112 millionincreased by $2.1 billion, primarily due to net debt repayments in 2010 as compared to net cash provided by financing activities of $598 million in 2008. This change is primarily due to higher dividend payments, and lower net debt issuances in 2009, and net repurchases of common stock in 2010 as a resultcompared to issuances of higher cash inflows from its operating activities, partially offset by increasedcommon stock in 2009. This reflects the use of proceeds from common stock issuances.the sales of Dominion’s Appalachian E&P operations and Peoples.
In 2009,2010, net cash provided by Virginia Power’s financing activities decreasedincreased by $156$412 million, primarily due to lowerhigher net debt issuances in 2010 as compared to 2009, as a result of higherlower cash flow from operations.
CREDIT FACILITIESAND SHORT-TERM DEBT
Dominion and Virginia Power use short-term debt to fund working capital requirements and as a bridge to long-term debt financing and as bridge financing for acquisitions, if applicable.financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements under its commodities hedging program.requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit qualityratings and the credit quality of Dominion’sits counterparties.
Virginia Power’s short-term financing is supported by a five-year joint revolving credit facility in which it participates with Dominion. This credit facility is being used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes. Dominion has two other facilities as detailed in the following table.
Commercial paper, bank loans, and letters of credit outstanding, as well as capacity available under credit facilities as of December 31, 2009 were as follows:
Facility Limit | Outstanding Commercial Paper | Outstanding Bank Loans | Outstanding Letters of Credit | Facility Capacity Available | |||||||||||
(millions) | |||||||||||||||
Five-year joint revolving credit facility(1) | $ | 2,872 | $ | 442 | $ | — | $ | 153 | $ | 2,277 | |||||
Five-year Dominion credit facility(2) | 1,700 | 353 | 500 | 19 | 828 | ||||||||||
Five-year Dominion bilateral facility(3) | 200 | — | — | 32 | 168 | ||||||||||
Totals | $ | 4,772 | $ | 795 | $ | 500 | $ | 204 | $ | 3,273 |
In addition to the credit facility commitments disclosed above, Virginia Power also has a five-year $120 million credit facility that terminates in February 2011, which supports certain of its tax-exempt financings.
Dominion and Virginia Power plan to replacereplaced certain of their existing credit facilities during the second or third quarter of 2010. They expect to operate with credit facilities ranging from $3.0 to $3.5 billion. The Companies do not expect the reduction in the size of their credit facilities to negatively impact their ability to fund their operations.September 2010, as noted below.
In connection with commodity hedging activities, the Companies are required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, the Companies may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, the Companies vary the form of collateral provided to counterparties after weighing the costs and benefits of various factors associated with the different forms of collateral. These factors include short-term borrowing and short-term investment rates, the spread over these short-term rates at which the Companies can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives.
In FebruaryDOMINION
Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities were as follows:
At December 31, 2010 | Facility Limit | Outstanding Commercial Paper | Outstanding Letters of Credit | Facility Capacity Available | ||||||||||||
(millions) | ||||||||||||||||
Three-year joint revolving credit facility(1) | $ | 3,000 | $ | 1,386 | $ | 101 | $ | 1,513 | ||||||||
Three-year joint revolving credit facility(2) | 500 | — | 35 | 465 | ||||||||||||
Total | $ | 3,500 | $ | 1,386 | (3) | $ | 136 | $ | 1,978 |
(1) | This credit facility was entered into in September 2010 and terminates in September 2013. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit. |
(2) | This credit facility was entered into in September 2010 and terminates in September 2013. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. |
(3) | The weighted-average interest rate of the outstanding commercial paper supported by Dominion’s credit facilities was 0.41% at December 31, 2010. |
VIRGINIA POWER
Virginia Power’s short-term financing is supported by two three-year joint revolving credit facilities with Dominion. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion completed the saleand Virginia Power and for other general corporate purposes.
Virginia Power’s share of Peoplescommercial paper and netted after-tax proceedsletters of approximately $542 million, which it used to reduce debt.credit outstanding, as well as its capacity available under its joint credit facilities with Dominion were as follows:
At December 31, 2010 | Facility Sub-limit | Outstanding Commercial Paper | Outstanding Letters of Credit | Facility Capacity Available | ||||||||||||
(millions) | ||||||||||||||||
Three-year joint revolving credit facility(1) | $ | 1,000 | $ | 600 | $ | 91 | $ | 309 | ||||||||
Three-year joint revolving credit facility(2) | 250 | — | — | 250 | ||||||||||||
Total | $ | 1,250 | $ | 600 | (3) | $ | 91 | $ | 559 |
(1) | This credit facility was entered into in September 2010 and terminates in September 2013. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year. |
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
(2) | This credit facility was entered into in September 2010 and terminates in September 2013. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year. |
(3) | The weighted-average interest rate of the outstanding commercial paper supported by these credit facilities was 0.41% at December 31, 2010. |
In addition to the credit facility commitments mentioned above, Virginia Power also has a three-year $120 million credit facility that was entered into in September 2010. The facility, which terminates in September 2013, supports certain tax-exempt financings of Virginia Power.
LONG-TERM DEBT
During 2009,2010, Dominion and Virginia Power issued the following long-term debt:
Type | Principal | Rate | Maturity | Issuing Company | Principal | Rate | Maturity | Issuing Company | ||||||||||||||||||
(millions) | (millions) | |||||||||||||||||||||||||
Senior notes | $ | 500 | 5.20% | 2019 | Dominion | $ | 250 | 2.25 | % | 2015 | Dominion | |||||||||||||||
Enhanced junior subordinated notes | 685 | 8.375% | 2064 | (1) | Dominion | |||||||||||||||||||||
Senior notes | 350 | 5.00% | 2019 | Virginia Power | 300 | 3.45 | % | 2022 | Virginia Power | |||||||||||||||||
Total notes issued | $ | 1,535 | $ | 550 |
Additionally, in May 2009, Dominion’s Brayton Point power stationIn November 2010, Virginia Power borrowed $50$105 million in connection with the MassachusettsIndustrial Development Finance AgencyAuthority of Wise County Solid Waste and Sewage Disposal Revenue Refunding Bonds, Series 2009,2010 A, which mature in 20422040 and bear a coupon rate of 5.75% for the first ten years, after which they will bear interest at a market rate to be determined at that time, using a remarketing process. The proceeds were used to refinance certain qualifying improvements at Brayton Point.
In May 2009, Virginia Power borrowed $40 million in connection with the Economic Development Authority of the County of Chesterfield Pollution Control Refunding Revenue Bonds, Series 2009 A, which mature in 2023 and bear a coupon rate of 5.0%. The proceeds were used to refund the principal amount of the Industrial Development Authority of the County of Chesterfield Money Market MunicipalsTM Pollution Control Revenue Bonds, Series 1985 that would otherwise have matured in October 2009.
In May 2009, Virginia Power borrowed $70 million in connection with the Economic Development Authority of York County, Virginia Pollution Control Refunding Revenue Bonds, Series 2009 A, which mature in 2033 and bear an initial coupon rate of 4.05%2.375% for the first five years, after which they will bear interest at a market rate to be determined at that time, using a remarketing process. The proceeds werewill be used to refundfinance certain qualifying facilities at the principal amount of the Industrial Development Authority of York County, Virginia Money Market MunicipalsTM Pollution Control Revenue Bonds, Series 1985 that would otherwise have matured in July 2009.City Hybrid Energy Center.
In December 2010 and September 2009, Virginia Power borrowed $100 million and $60 million, respectively, in connection with the $160 million Industrial Development Authority of Wise County Solid Waste and Sewage Disposal Revenue Bonds, Series 2009 A, which mature in 2040 and bear interest during the initial period at a variable rate. Due to unfavorable market conditions, Virginia Power acquired the $60 million in bonds upon issuance in September 2009 with the intention of remarketing them to a third partyparties at a later time. ProceedsThe proceeds will be used to finance certain qualifying facilities at the Virginia City Hybrid Energy Center. At December 31, 2009,2010, these bonds had not been remarketed and thus are eliminatednot reflected on the Consolidated Balance Sheets.
In December 2010, Virginia Power borrowed $100 million in consolidation, alongconnection with the investment.Industrial Development Authority of Halifax County, Virginia Recovery Zone Facility Revenue Bonds, Series 2010 A, which mature in 2041 and bear interest at a variable rate for the first seven years, after which they will bear interest at a market rate to be determined at that time, using a remarketing process. The proceeds will be used to finance certain qualifying facilities in Halifax County and/or Wise County.
IncludingIn December 2010, Brayton Point borrowed approximately $160 million and approximately $75 million in connection with the amounts discussed above,Massachusetts Development Finance Agency Recovery Zone Facility Bonds, Series 2010 A and the Solid Waste Disposal Revenue Bonds, Series 2010 B, respectively, which mature in 2041 and bear interest during 2009,the initial period at a variable rate. Due to unfavorable market conditions, Dominion acquired the bonds upon issuance in December 2010 with the intention of remarketing them to third parties at a later time. The proceeds
will be used to finance certain qualifying facilities at Brayton Point. At December 31, 2010, these bonds had not been remarketed and thus are not reflected on the Consolidated Balance Sheets.
During 2010, Dominion and Virginia Power repaid $447 million and $126repurchased $1.5 billion and $347 million, respectively, of long-term debt and notes payable.
ISSUANCEOF COMMON STOCK
In January 2009, Dominion entered into sales agency agreements pursuant to which it may offer from time to time up to $400 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the New York Stock Exchange at market prices or in such other transactions as are agreed upon by the Company and the sales agents and in conformance with applicable securities laws.
During 2009,2010, Dominion issued 142.3 million shares of common stock for cash proceeds of $456$74 million. Dominion issued 6.2 million shares through at-the-market issuances under its sales agency agreements and received cash proceeds of $191 million, net of fees and commissions paid of $2 million. Following these issuances, Dominion has the ability to issue up to $207 million of stock under sales agency agreements. Dominion also issued 76,000 shares of its common stock to its officers and directors under a private placement program for aggregate consideration of approximately $2 million. The remainder of the shares issued and cash proceeds received during 20092010 were through Dominion Direct®, employee savings plans and the exercise of employee stock options. Dominion anticipates a need for $400 million of external common equity in 2010. This need will be met by the issuancedoes not currently plan any market issuances of common stock in 2011 or in whole or in part by proceeds, if any in 2010, from the planned monetization of Dominion’s Marcellus Shale acreage.2012.
In February 2010, Dominion began purchasing its common stock on the open market with proceeds received through Dominion Direct® and employee savings plans, rather than issuing additional new common shares.
Additionally, in February 2009, Dominion issued approximately 1.6 million shares of common stock to an existing holder of its senior notes, in a privately negotiated transaction, in exchange for approximately $56 million of the principal of two series of its outstanding senior notes, which were retired. The transaction was exempt from registration pursuant to Section 3(a)(9) of the Securities Act and no commission or remuneration was paid in connection with the exchange.
In 2009,2010, Virginia Power issued 31,87733,013 shares of its common stock to Dominion reflectingfor approximately $1 billion. The proceeds were used to pay down short-term demand note borrowings from Dominion.
REPURCHASE OF COMMON STOCK
In March 2010, Dominion began repurchasing common shares in anticipation of proceeds from the conversionsale of $1 billionits Appalachian E&P operations. During 2010, Dominion purchased 21.4 million shares of its common stock for approximately $900 million.
On January 28, 2011, Dominion announced that it intends to repurchase between $400 million and $700 million of common stock with cash tax savings resulting from the extension of the bonus depreciation allowance discussed in Note 6 to the Consolidated Financial Statements. In the first quarter of 2011, Dominion began repurchasing shares on the open market under this program.
BORROWINGS FROM PARENT
Virginia Power has the ability to borrow funds from Dominion under both short-term and long-term borrowing arrangements and at December 31, 2010, its nonregulated subsidiaries had outstanding borrowings, net of repayments, under the Dominion money pool of $24 million. Virginia Power’s short-term demand note borrowings from Dominion to equity.were $79 million at December 31, 2010. There were no long-term borrowings from Dominion at December 31, 2010.
Credit Ratings
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Dominion and Virginia Power believe that their current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion and Virginia Power may affect their ability to access these funding sources or cause an increase in the return required by investors. Dominion’s and Virginia Power’s credit ratings may affect their liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which they are able to offer their debt securities.
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Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for Dominion and Virginia Power are most affected by each company’s financial profile, mix
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and “eventevent risk,” if applicable, such as major acquisitions or dispositions.
In December 2009, Fitch published a report that announced a global cross-sector change in its criteria for rating hybrid and other equity capital-like securities. In January 2010, Fitch lowered its credit ratings for Virginia Power’s preferred stock and Dominion’s junior subordinated debt securities and enhanced junior subordinated notes reflectingsolely due to a revision in Fitch’s ratings methodology such that it now rates these securities two notches below its credit rating for senior unsecured debt securities. In December 2010, Moody’s raised its credit ratings for Virginia Power, reflecting sustained improvements in Virginia Power’s financial performance as measured by its credit metrics and the agency’s views of a generally supportive regulatory and political environment in Virginia Power’s service territory.
Credit ratings as of February 1, 201023, 2011 follow:
Fitch | Moody’s | Standard & Poor’s | ||||||||||
Dominion | ||||||||||||
Senior unsecured debt securities | BBB+ | Baa2 | ||||||||||
Junior subordinated debt securities | Baa3 | BBB | ||||||||||
Enhanced junior subordinated notes | Baa3 | BBB | ||||||||||
Commercial paper | F2 | P-2 | A-2 | |||||||||
Virginia Power | ||||||||||||
Mortgage bonds | A | A | ||||||||||
Senior unsecured (including tax-exempt) debt securities | ||||||||||||
Junior subordinated debt securities | BBB | BBB | ||||||||||
Preferred stock | BBB | BBB | ||||||||||
Commercial paper | F2 | P-2 | A-2 |
As of February 1, 2010,23, 2011, Fitch, Moody’s and Standard & Poor’s maintained a stable outlook for their respective ratings of Dominion and Virginia Power and Moody’s maintains a stable outlook on their ratings for Dominion and a positive outlook on their ratings for Virginia Power.
A downgrade in an individual company’s credit rating would not necessarily restrict its ability to raise short-term and long-term financing as long as its credit rating remains “investmentinvestment grade,” but it would likely increase the cost of borrowing. Dominion and Virginia Power work closely with Fitch, Moody’s and Standard & Poor’s with the objective of maintaining their current credit ratings. In order to maintain current ratings, the Companies may find it necessary to modify their business plans and such changes may adversely affect growth and EPS.
Debt Covenants
As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion and Virginia Power must enter into enabling agreements. These agreements contain covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the
lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion and Virginia Power.
Some of the typical covenants include:
Ÿ | The timely payment of principal and interest; |
Ÿ | Information requirements, including submitting financial reports filed with the SEC and information about changes in Dominion’s and Virginia Power’s credit ratings to lenders; |
Ÿ | Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation, and restrictions on disposition of all or substantially all assets; |
Ÿ | Compliance with collateral minimums or requirements related to mortgage bonds; and |
Ÿ | Limitations on liens. |
Dominion and Virginia Power are required to pay annual commitment fees to maintain their credit facilities. In addition, their credit agreements contain various terms and conditions that could affect their ability to borrow under these facilities. They include maximum debt to total capital ratios and cross-default provisions.
As of December 31, 2009,2010, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:
Company | Maximum Ratio | Actual Ratio(1) | Maximum Allowed Ratio | Actual Ratio(1) | ||||||||||
Dominion | 65 | % | 56 | % | 65 | % | 54 | % | ||||||
Virginia Power | 65 | % | 48 | % | 65 | % | 46 | % |
(1) | Indebtedness as defined by the bank agreements excludes junior subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets. |
These provisions apply separately to Dominion and Virginia Power. If Dominion or Virginia Power or any of either company’s material subsidiaries failfails to make payment on various debt obligations in excess of $35$100 million, the lenders could require that company to accelerate its repayment of any outstanding borrowings under the credit facility and the lenders could terminate their commitment to lend funds to that company. Accordingly, any default by Dominion will not affect the lenders’ commitment to Virginia Power. However, any default by Virginia Power would affect the lenders’ commitment to Dominion under the joint credit agreement.agreements.
Dominion executed Replacement Capital Covenants (RCCs)RCCs in connection with its issuance of the following hybrid securities:
Ÿ |
|
Ÿ |
|
Ÿ |
|
Under the terms of the RCCs, Dominion promises and covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to the respective RCC termination date,such activity, Dominion has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids
47 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
at that time, as more fully described in the RCCs. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.
At December 31, 2009,2010, the termination dates and covered debt under the RCCs associated with Dominion’s hybrids are as follows:
Hybrid | RCC Termination Date | Designated Covered Debt Under | ||||
June 2006 hybrids | 6/30/2036 | September 2006 hybrids | ||||
September 2006 hybrids | 9/30/2036 | June 2006 hybrids | ||||
June 2009 hybrids | 6/15/2034 | (1) | 2008 Series B Senior Notes, 7.0% due 2038 |
(1) | Automatically extended, as set forth in the RCC, for additional quarterly periods, to the extent the maturity date is extended. |
Dominion and Virginia Power monitor the debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2009,2010, there have been no events of default under or changes to Dominion’s debt covenants.
Dividend Restrictions
The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2009,2010, the Virginia Commission had not restricted the payment of dividends by Virginia Power.
Certain agreements associated with Dominion’s and Virginia Power’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion or Virginia Power’s ability to pay dividends or receive dividends from their subsidiaries at December 31, 2009.2010.
See Note 18 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes.
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
CONTRACTUAL OBLIGATIONS
Dominion and Virginia Power are party to numerous contracts and arrangements obligating them to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion and Virginia Power are parties as of December 31, 2009.2010. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in the Consolidated Balance Sheets, other than current maturities of long-term debt, interest payable and certain derivative instruments. The majority of Dominion’s and Virginia Power’s current liabilities will be paid in cash in 2010.
2011.
DOMINION | 2010 | 2011 - 2012 | 2013 - 2014 | 2015 and thereafter | Total | ||||||||||
(millions) | |||||||||||||||
Long-term debt(1) | $ | 1,135 | $ | 1,980 | $ | 1,381 | $ | 12,129 | $ | 16,625 | |||||
Interest payments(2) | 989 | 1,850 | 1,611 | 13,575 | 18,025 | ||||||||||
Leases | 143 | 253 | 127 | 147 | 670 | ||||||||||
Purchase obligations(3): | |||||||||||||||
Purchased electric capacity for utility operations | 345 | 694 | 712 | 1,126 | 2,877 | ||||||||||
Fuel commitments for utility operations | 957 | 933 | 382 | 280 | 2,552 | ||||||||||
Fuel commitments for nonregulated operations | 466 | 300 | 149 | 243 | 1,158 | ||||||||||
Pipeline transportation and storage | 155 | 175 | 72 | 70 | 472 | ||||||||||
Energy commodity purchases for resale(4) | 407 | 32 | 5 | — | 444 | ||||||||||
Other(5) | 209 | 42 | 8 | 4 | 263 | ||||||||||
Other long-term liabilities(6): | |||||||||||||||
Financial derivative-commodities(4) | 70 | 9 | — | — | 79 | ||||||||||
Other contractual obligations(7) | 7 | 9 | 13 | 9 | 38 | ||||||||||
Total cash payments | $ | 4,883 | $ | 6,277 | $ | 4,460 | $ | 27,583 | $ | 43,203 |
Dominion | 2011 | 2012- 2013 | 2014- 2015 | 2016 and thereafter | Total | |||||||||||||||
(millions) | ||||||||||||||||||||
Long-term debt(1) | $ | 497 | $ | 2,184 | $ | 1,666 | $ | 11,882 | $ | 16,229 | ||||||||||
Interest payments(2) | 932 | 1,786 | 1,592 | 12,996 | 17,306 | |||||||||||||||
Leases(3) | 184 | 312 | 108 | 193 | 797 | |||||||||||||||
Purchase obligations(4): | ||||||||||||||||||||
Purchased electric capacity for utility operations | 342 | 698 | 696 | 779 | 2,515 | |||||||||||||||
Fuel commitments for utility operations | 959 | 932 | 491 | 241 | 2,623 | |||||||||||||||
Fuel commitments for nonregulated operations | 446 | 264 | 198 | 162 | 1,070 | |||||||||||||||
Pipeline transportation and storage | 134 | 142 | 49 | 64 | 389 | |||||||||||||||
Energy commodity purchases for resale(5) | 495 | 57 | 10 | 76 | 638 | |||||||||||||||
Other(6) | 253 | 54 | 12 | 12 | 331 | |||||||||||||||
Other long-term liabilities(7): | ||||||||||||||||||||
Financial derivative-commodities(5) | 28 | 49 | 12 | 2 | 91 | |||||||||||||||
Other contractual obligations(8) | 5 | 10 | 11 | 1 | 27 | |||||||||||||||
Total cash payments | $ | 4,275 | $ | 6,488 | $ | 4,845 | $ | 26,408 | $ | 42,016 |
(1) | Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders. |
(2) | Does not reflect Dominion’s ability to defer interest payments on junior subordinated notes. |
(3) | Primarily consists of operating leases. |
(4) | Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined. |
Represents the summation of settlement amounts, by contracts, due from Dominion if all physical or financial transactions among its counterparties and Dominion were liquidated and terminated. |
Includes capital, operations and maintenance commitments. |
Excludes regulatory liabilities, AROs and employee benefit plan obligations, which are not contractually fixed as to timing and amount. See Notes 13, 15 and 22 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, |
Includes interest rate swap agreements. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
VIRGINIA POWER | 2010 | 2011- 2012 | 2013- 2014 | 2015 and thereafter | Total | ||||||||||
(millions) | |||||||||||||||
Long-term debt(1) | $ | 246 | $ | 631 | $ | 435 | $ | 5,149 | $ | 6,461 | |||||
Interest payments | 376 | 731 | 640 | 4,512 | 6,259 | ||||||||||
Leases | 35 | 53 | 24 | 23 | 135 | ||||||||||
Purchase obligations(2): | |||||||||||||||
Purchased electric capacity for utility operations | 345 | 694 | 712 | 1,126 | 2,877 | ||||||||||
Fuel commitments for utility operations | 957 | 933 | 382 | 280 | 2,552 | ||||||||||
Transportation and storage | 20 | 27 | 17 | 36 | 100 | ||||||||||
Other | 118 | 27 | 3 | — | 148 | ||||||||||
Other long-term liabilities(3) | 4 | — | — | — | 4 | ||||||||||
Total cash payments | $ | 2,101 | $ | 3,096 | $ | 2,213 | $ | 11,126 | $ | 18,536 |
Virginia Power | 2011 | 2012- 2013 | 2014- 2015 | 2016 and thereafter | Total | |||||||||||||||
(millions) | ||||||||||||||||||||
Long-term debt(1) | $ | 15 | $ | 1,034 | $ | 236 | $ | 5,436 | $ | 6,721 | ||||||||||
Interest payments | 369 | 721 | 653 | 4,418 | 6,161 | |||||||||||||||
Leases(2) | 36 | 45 | 26 | 23 | 130 | |||||||||||||||
Purchase obligations(3): | ||||||||||||||||||||
Purchased electric capacity for utility operations | 342 | 698 | 696 | 779 | 2,515 | |||||||||||||||
Fuel commitments for utility operations | 959 | 932 | 491 | 241 | 2,623 | |||||||||||||||
Transportation and storage | 19 | 29 | 21 | 32 | 101 | |||||||||||||||
Other | 113 | 21 | 8 | 8 | 150 | |||||||||||||||
Total cash payments(4) | $ | 1,853 | $ | 3,480 | $ | 2,131 | $ | 10,937 | $ | 18,401 |
(1) | Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders. |
48 |
(2) | Primarily consists of operating leases. |
(3) | Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined. |
Excludes regulatory liabilities, AROs and employee benefit plan contributions that are not contractually fixed as to timing and amount. See Notes 13, 15 and 22 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, |
PLANNED CAPITAL EXPENDITURES
Dominion’s planned capital expenditures are expected to total approximately $3.9 billion, $3.8$4.7 billion and $4.2$4.4 billion in 2010, 2011, 2012 and 2012,2013, respectively. Dominion’s expenditures are expected to include construction and expansion of electric generation and natural gas transmission and storage facilities, environmental upgrades, construction improvements and expansion of electric transmission and distribution assets and purchases of nuclear fuel and expenditures to explore for and develop natural gas and oil properties.fuel.
Virginia Power’s planned capital expenditures are expected to total approximately $2.5 billion, $2.2 billion, $3.0 billion and $2.4$3.3 billion in 2010, 2011, 2012 and 2012,2013, respectively. Virginia Power’s expenditures are expected to include construction and expansion of electric generation facilities, environmental upgrades, and construction improvements and expansion of electric transmission and distribution assets.assets and purchases of nuclear fuel.
Dominion and Virginia Power expect to fund their capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the Board of Directors.
Based on available generation capacity and current estimates of growth in customer demand, Virginia Power will need additional generation in the future. SeeDominion Generation-Properties in Item 1. Business for a discussion of Virginia Power’s expansion plans.
These estimates are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. The Companies may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.
Use of Off-Balance Sheet Arrangements
GUARANTEES
Dominion primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others.
At December 31, 2009,2010, Dominion had issued $261$131 million of guarantees, primarily to support third parties and equity method investees,investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2010, Dominion’s exposure under these guarantees was $54 million, primarily reflecting guarantees issuedrelated to support the NedPower and Fowler Ridge wind farm joint ventures. See Note 23 to the Consolidated Financial Statements for further discussion of these guarantees.certain reserve requirements associated with non-recourse financing.
LEASING ARRANGEMENT
Dominion leases Fairless in Pennsylvania, which began commercial operations in June 2004. During construction, Dominion
acted as the construction agent for the lessor, controlled the design and construction of the facility and has since been reimbursed for all project costs ($898 million) advanced to the lessor. Dominion makes annual lease payments of $53 million. The lease expires in 2013 and at that time, Dominion may renew the lease at negotiated amounts based on original project costs and current market conditions, subject to lessor approval; purchase Fairless at its original construction cost plus 51% of any appraised value in excess of original construction cost; or sell Fairless, on behalf of the lessor, to an independent third party. If Fairless is sold and the proceeds from the sale are less than its original construction cost, Dominion would be required to make a payment to the lessor in an amount up to 70.75% of original project costs adjusted for certain other costs as specified in the lease. The lease agreement does not contain any provisions that involve credit rating or stock price trigger events.
Benefits of this arrangement include:
Ÿ | Certain tax benefits as Dominion is considered the owner of the leased property for tax purposes. As a result, Dominion is entitled to tax deductions for depreciation not recognized for financial accounting purposes; and |
Ÿ | As an operating lease for financial accounting purposes, the asset and related borrowings used to finance the construction of the asset are not included in the Consolidated Balance Sheets. Although this improves measures of leverage calculated using amounts reported in the Consolidated Financial Statements, credit rating agencies view lease obligations as debt equivalents in evaluating Dominion’s credit profile. |
FUTURE ISSUESAND OTHER MATTERS
See Item 1. Business, Item 3. Legal Proceedings, and Notes 14 and 23 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other matters that may impact future results of operations and/or financial condition.
Environmental Matters
Dominion and Virginia Power are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They
can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
ENVIRONMENTAL PROTECTIONAND MONITORING EXPENDITURES
Dominion incurred approximately $228 million, $252 million $205 million, and $181$205 million of expenses (including depreciation) during 2010, 2009, 2008, and 20072008 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $268$231 million and $274$251 million in 20102011 and 2011,2012, respectively. In addition, capital expenditures related to environmental controls were $351 million, $266 million, and $254 million for 2010, 2009 and $293 million for 2009, 2008, and 2007, respectively. These expenditures are expected to be approximately $383$398 million and $322$553 million for 20102011 and 2011,2012, respectively.
49 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Virginia Power incurred approximately $144 million, $134 million $125 million, and $121$125 million of expenses (including depreciation) during 2010, 2009 2008, and 2007,2008, respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $153$142 million and $150$156 million in 20102011 and 2011,2012, respectively. In addition, capital expenditures related to environmental controls were $101 million, $109 million and $116 million for 2010, 2009 and $189 million for 2009, 2008, and 2007, respectively. These expenditures are expected to be approximately $102$72 million and $54$341 million for 20102011 and 2011,2012, respectively.
FUTURE ENVIRONMENTAL REGULATIONS
There hashave already been federal and state legislative proposals and regulatory action regarding the regulation of GHG emissions. Dominion and Virginia Power expect that there may be federal legislation and/or regulatory action regarding compliance with more stringent air emission standards, regarding coal combustion byproducts,by-products, and regarding regulation of cooling water intake structures and discharges in the future. With respect to GHG emissions, in December 2010, the outcome in terms of specific requirementsEPA announced a schedule for when they will propose regulations which would establish GHG performance standards for new, modified and timing is uncertain but may include aexisting fossil-fired electric generating units. Regulations are expected to be proposed by July 2011 and finalized by May 2012.This means that Dominion’s new, modified, and existing fossil-fired electric generating units will become subject to GHG emissions cap-and-trade programperformance standards, if these rules are finalized. The EPA has not provided any detail yet on what the performance standard might be or a carbon tax for electric generators and natural gas businesses or regulation of GHGs underwhat measures facilities might have to make to reach the CAA.standard. With respect to emission reductions of SO2, NOx, mercury and HAPs (in addition to mercury), specific requirements will depend on how the EPA and/or states replace CAMR and the outcome of the EPA’s response to the CAIR remand. following:
Ÿ | Final outcome of the EPA’s scheduled rulemaking for developing MACT standards for mercury and other HAPs to replace the CAMR vacated by a federal court in 2008; |
Ÿ | The final outcome of the EPA’s Transport Rule proposed in July 2010 in response to a federal court remand of the CAIR as well as future state regulations implementing requirements to address the EPA’s promulgation of revised NAAQS for SO2 and NO2; and |
Ÿ | EPA’s impending rulemaking to revise the ozone NAAQS. |
With respect to cooling water intakes and discharges, the Companies expect future federal regulation on cooling water intake structures and the quality of water discharges, and more focus by the EPA and state regulatory authorities on thermal discharge issues. With respect to coal combustion byproducts,by-products, Dominion and Virginia Power expect federal regulation of coal combustion byproductby-product handling and disposal practices. If any of these new proposals are adopted, additional significant expenditures may be required.
Dodd-Frank Act
The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The Dodd-Frank Act includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can be exempted from these clearing and exchange trading requirements. In addi-
tion, the Dodd-Frank Act allows the CFTC and SEC to impose initial and variation margin requirements on entities who execute swaps. End users were not expressly exempt from these requirements for non-cleared swaps; however, key legislators indicated in a public letter that it was their intention to exclude commercial hedging transactions by end users from these requirements. Final rules for the over-the-counter derivative-related provisions of the Dodd-Frank Act, including the clearing, exchange trading and margin requirements, will be established through the CFTC’s and SEC’s rulemaking process, which is required to be completed by July 2011. If, as a result of the rulemaking process, Dominion’s or Virginia Power’s derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs for their derivative activities, including from higher margin requirements. In addition, implementation of, and compliance with, the over-the-counter derivative provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in increased costs related to the Companies’ derivative activities. Due to the ongoing rulemaking process, the Companies are currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on their financial condition, results of operations or cash flows.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact Dominion and Virginia Power.
MARKET RISK SENSITIVE INSTRUMENTSAND RISK MANAGEMENT
Dominion’s and Virginia Power’s financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in Dominion’s and Virginia Power’s electric operations, Dominion’s gas production and procurement operations, and Dominion’s energy marketing and trading operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt. In addition, they are exposed to investment price risk through various portfolios of equity and debt securities.
The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% unfavorable change in commodity prices andor interest rates.
Commodity Price Risk
To manage price risk, Dominion and Virginia Power primarily hold commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of electricity,elec-
50 |
tricity, natural gas and other energy-related products. As part of its strategy to market energy and to manage related risks, Dominion also holds commodity-based financial derivative instruments for trading purposes.
The derivatives used to manage commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based financial derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on observable market prices.
A hypothetical 10% unfavorable change in market prices of Dominion’s non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $150$183 million and $236$150 million as of December 31, 2010 and 2009, and 2008, respectively. The decline largely reflects settlements of commodity derivative positions existing as of the beginning of 2009. A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $11$5 million and $5$11 million in the fair value of Dominion’s commodity-based financial derivative instruments held for trading purposes as of December 31, 2010 and 2009, and 2008, respectively. The increase largely reflects a decrease in commodity prices as well as increased commodity derivative activity.
A hypothetical 10% unfavorable change in commodity prices would not have resulted in a decrease of approximately $3 million and $23 millionmaterial change in the fair value of Virginia Power’s non-trading commodity-based financial derivatives as of December 31, 2009 and 2008, respectively. The decline largely reflects settlements of
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
commodity derivative positions existing as of the beginning of2010 or 2009.
The impact of a change in energy commodity prices on Dominion’s and Virginia Power’s non-trading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when suchthe contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.
Interest Rate Risk
Dominion and Virginia Power manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments designated under fair value hedging and outstanding for Dominion at December 31, 2009 and 2008,Virginia Power, a hypothetical 10% increase in market interest rates would not have resulted in a decreasematerial change in annual earnings of approximately $2 million and $4 million, respectively. For financial instruments outstanding for Virginia Power at December 31, 2009 and 2008, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of less than $1 million and approximately $2 million, respectively.2010 or 2009.
Additionally, Dominion and Virginia Power may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. At December 31, 2009, Dominion and Virginia Power had $1.7 billion and $850 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. At December 31, 2009, a hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $62 million and $33 million in the fair value of these interest rate derivatives held by Dominion and Virginia Power, respectively. Subsequent to June 30, 2010, all forward-starting
interest rate swap contracts were terminated; therefore, Dominion and Virginia Power did not have a significant amount ofno sensitivity to changes in interest rates related to these interest rate derivatives outstanding at December 31, 2008.swaps.
The impact of a change in market interest rates on these anticipatory hedges at a point in time is not necessarily representative of the results that will be realized when such contracts are settled. Net gains and/or losses from interest rate derivatives used for anticipatory hedging purposes, to the extent realized, will generally be amortized over the life of the respective debt issuance being hedged.
Investment Price Risk
Dominion and Virginia Power are subject to investment price risk due to securities held as investments in decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value.
Following the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations in April 2007, gains or losses on those decommissioning trust investments are deferred as regulatory liabilities.
Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $29$95 million and $25 million in 2009. Dominion recognized net realized losses (net of
investment income) on nuclear decommissioning trust investments of $192 million in 2008. Net realized gains2010 and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2009, Dominion recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $349 million. In 2008, Dominion recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $451 million.
Virginia Power recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $3 million and $57 million in 2009 and 2008, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2010 and 2009, Dominion recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $182 million and $360 million, respectively.
Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $44 million in 2010. Virginia Power recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $3 million in 2009. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2010 and 2009, Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $67 million and $149 million. In 2008, Virginia Power recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $233 million.million, respectively.
Dominion sponsors pension and other postretirement benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power employees participate in these plans. Aggregate actual returns for Dominion’s pension and other postretirement plan assets were $624 million in 2010 and $777 million in 2009, and negative $1.4 billion in 2008, versus expected returns of $462$479 million and $484$462 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts such as those experienced during 2008, will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. As of December 31, 20092010 and 2008,2009, a hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion’s plan assets would result in an increase in net periodic cost of approximately $12$13 million for pension benefits and $2$3 million for other postretirement benefits.
Risk Management Policies
Dominion and Virginia Power have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies
51 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
of all subsidiaries, including Virginia Power. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based
on these credit policies and Dominion’s and Virginia Power’s December 31, 20092010 provision for credit losses, management believes that it is unlikely that a material adverse effect on Dominion’s or Virginia Power’s financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
Item 8. Financial Statements and Supplementary Data
Page No. | ||||
Dominion Resources, Inc. | ||||
Consolidated Statements of Income for the years ended December 31, 2010, 2009 | ||||
Consolidated Balance Sheets at December 31, | ||||
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 | ||||
Virginia Electric and Power Company | ||||
Consolidated Statements of Income for the years ended December 31, 2010, 2009 | ||||
Consolidated Balance Sheets at December 31, | ||||
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 | ||||
REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 20092010 and 2008,2009, and the related consolidated statements of income, common shareholders’ equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009.2010. These financial statements are the responsibility of Dominion’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Resources, Inc. and subsidiaries as of December 31, 20092010 and 2008,2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009,2010, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, in 2009 Dominion changed its methods of accounting to adopt a new accounting standardsstandard for the impairment framework for oil and gas properties in 2009 and fair value measurements in 2008.properties.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Dominion’s internal control over financial reporting as of December 31, 2009,2010, based on the criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 201025, 2011 expressed an unqualified opinion on Dominion’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 26, 201025, 2011
Consolidated Statements of Income
Year Ended December 31, | 2009 | 2008 | 2007 | ||||||||
(millions, except per share amounts) | |||||||||||
Operating Revenue | $ | 15,131 | $ | 16,290 | $ | 14,816 | |||||
Operating Expenses | |||||||||||
Electric fuel and other energy-related purchases | 4,285 | 4,023 | 3,623 | ||||||||
Purchased electric capacity | 411 | 411 | 439 | ||||||||
Purchased gas | 2,381 | 3,398 | 2,775 | ||||||||
Other operations and maintenance | 3,795 | 3,257 | 4,125 | ||||||||
Gain on sale of U.S. non-Appalachian E&P business | — | 42 | (3,635 | ) | |||||||
Depreciation, depletion and amortization | 1,139 | 1,034 | 1,368 | ||||||||
Other taxes | 491 | 499 | 552 | ||||||||
Total operating expenses | 12,502 | 12,664 | 9,247 | ||||||||
Income from operations | 2,629 | 3,626 | 5,569 | ||||||||
Other income (loss) | 181 | (58 | ) | 102 | |||||||
Interest and related charges | 894 | 837 | 1,161 | ||||||||
Income from continuing operations including noncontrolling interests before income taxes and extraordinary item | 1,916 | 2,731 | 4,510 | ||||||||
Income tax expense | 612 | 879 | 1,783 | ||||||||
Income from continuing operations including noncontrolling interests before extraordinary item | 1,304 | 1,852 | 2,727 | ||||||||
Loss from discontinued operations(1) | — | (2 | ) | (8 | ) | ||||||
Extraordinary item(2) | — | — | (158 | ) | |||||||
Net income including noncontrolling interests | 1,304 | 1,850 | 2,561 | ||||||||
Noncontrolling interests | 17 | 16 | 22 | ||||||||
Net income attributable to Dominion | 1,287 | 1,834 | 2,539 | ||||||||
Amounts attributable to Dominion: | |||||||||||
Income from continuing operations, net of tax | 1,287 | 1,836 | 2,705 | ||||||||
Loss from discontinued operations, net of tax | — | (2 | ) | (8 | ) | ||||||
Extraordinary item, net of tax | — | — | (158 | ) | |||||||
Net income | 1,287 | 1,834 | 2,539 | ||||||||
Earnings Per Common Share—Basic: | |||||||||||
Income from continuing operations before extraordinary item | $ | 2.17 | $ | 3.17 | $ | 4.15 | |||||
Loss from discontinued operations | — | — | (0.01 | ) | |||||||
Extraordinary item | — | — | (0.24 | ) | |||||||
Net income | $ | 2.17 | $ | 3.17 | $ | 3.90 | |||||
Earnings Per Common Share—Diluted: | |||||||||||
Income from continuing operations before extraordinary item | $ | 2.17 | $ | 3.16 | $ | 4.13 | |||||
Loss from discontinued operations | — | — | (0.01 | ) | |||||||
Extraordinary item | — | — | (0.24 | ) | |||||||
Net income | $ | 2.17 | $ | 3.16 | $ | 3.88 | |||||
Dividends paid per common share | $ | 1.75 | $ | 1.58 | $ | 1.46 |
Year Ended December 31, | 2010 | 2009(1) | 2008(1) | |||||||||
(millions, except per share amounts) | ||||||||||||
Operating Revenue | $ | 15,197 | $ | 14,798 | $ | 15,895 | ||||||
Operating Expenses | ||||||||||||
Electric fuel and other energy-related purchases | 4,150 | 4,285 | 4,023 | |||||||||
Purchased electric capacity | 453 | 411 | 411 | |||||||||
Purchased gas | 2,050 | 2,200 | 3,166 | |||||||||
Other operations and maintenance | 3,724 | 3,712 | 3,284 | |||||||||
Depreciation, depletion and amortization | 1,055 | 1,138 | 1,034 | |||||||||
Other taxes | 532 | 483 | 493 | |||||||||
Total operating expenses | 11,964 | 12,229 | 12,411 | |||||||||
Gain on sale of Appalachian E&P operations | 2,467 | — | — | |||||||||
Income from operations | 5,700 | 2,569 | 3,484 | |||||||||
Other income (loss) | 169 | 194 | (42 | ) | ||||||||
Interest and related charges | 832 | 889 | 829 | |||||||||
Income from continuing operations including noncontrolling interests before income taxes | 5,037 | 1,874 | 2,613 | |||||||||
Income tax expense | 2,057 | 596 | 953 | |||||||||
Income from continuing operations including noncontrolling interests | 2,980 | 1,278 | 1,660 | |||||||||
Income (loss) from discontinued operations(2) | (155 | ) | 26 | 190 | ||||||||
Net income including noncontrolling interests | 2,825 | 1,304 | 1,850 | |||||||||
Noncontrolling interests | 17 | 17 | 16 | |||||||||
Net income attributable to Dominion | 2,808 | 1,287 | 1,834 | |||||||||
Amounts attributable to Dominion: | ||||||||||||
Income from continuing operations, net of tax | 2,963 | 1,261 | 1,644 | |||||||||
Income (loss) from discontinued operations, net of tax | (155 | ) | 26 | 190 | ||||||||
Net income | 2,808 | 1,287 | 1,834 | |||||||||
Earnings Per Common Share—Basic: | ||||||||||||
Income from continuing operations | $ | 5.03 | $ | 2.13 | $ | 2.84 | ||||||
Income (loss) from discontinued operations | (0.26 | ) | 0.04 | 0.33 | ||||||||
Net income | $ | 4.77 | $ | 2.17 | $ | 3.17 | ||||||
Earnings Per Common Share—Diluted: | ||||||||||||
Income from continuing operations | $ | 5.02 | $ | 2.13 | $ | 2.83 | ||||||
Income (loss) from discontinued operations | (0.26 | ) | 0.04 | 0.33 | ||||||||
Net income | $ | 4.76 | $ | 2.17 | $ | 3.16 | ||||||
Dividends paid per common share | $ | 1.83 | $ | 1.75 | $ | 1.58 |
(1) |
(2) |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
At December 31, | 2009 | 2008 | ||||||
(millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 48 | $ | 66 | ||||
Customer receivables (less allowance for doubtful accounts of $31 and $32) | 2,050 | 2,354 | ||||||
Other receivables (less allowance for doubtful accounts of $14 and $7) | 130 | 205 | ||||||
Inventories: | ||||||||
Materials and supplies | 590 | 509 | ||||||
Fossil fuel | 408 | 328 | ||||||
Gas stored | 187 | 329 | ||||||
Derivative assets | 1,128 | 1,497 | ||||||
Assets held for sale | 1,018 | 1,416 | ||||||
Prepayments | 405 | 163 | ||||||
Other | 853 | 794 | ||||||
Total current assets | 6,817 | 7,661 | ||||||
Investments | ||||||||
Nuclear decommissioning trust funds | 2,625 | 2,246 | ||||||
Investment in equity method affiliates | 595 | 726 | ||||||
Other | 272 | 285 | ||||||
Total investments | 3,492 | 3,257 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 39,036 | 35,448 | ||||||
Accumulated depreciation, depletion and amortization | (13,444 | ) | (12,174 | ) | ||||
Total property, plant and equipment, net | 25,592 | 23,274 | ||||||
Deferred Charges and Other Assets | ||||||||
Goodwill | 3,354 | 3,503 | ||||||
Pension and other postretirement benefit assets | 702 | 514 | ||||||
Intangible assets | 693 | 712 | ||||||
Regulatory assets | 1,390 | 2,226 | ||||||
Other | 514 | 906 | ||||||
Total deferred charges and other assets | 6,653 | 7,861 | ||||||
Total assets | $ | 42,554 | $ | 42,053 |
At December 31, | 2009 | 2008 | ||||||
(millions) | ||||||||
LIABILITIESAND SHAREHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
Securities due within one year | $ | 1,137 | $ | 444 | ||||
Short-term debt | 1,295 | 2,030 | ||||||
Accounts payable | 1,401 | 1,499 | ||||||
Accrued interest, payroll and taxes | 676 | 754 | ||||||
Derivative liabilities | 679 | 1,100 | ||||||
Liabilities held for sale | 428 | 570 | ||||||
Margin deposit liabilities | 114 | 406 | ||||||
Accrued dividends | — | 260 | ||||||
Regulatory liabilities | 536 | 20 | ||||||
Other | 567 | 711 | ||||||
Total current liabilities | 6,833 | 7,794 | ||||||
Long-Term Debt | ||||||||
Long-term debt | 13,730 | 13,890 | ||||||
Junior subordinated notes payable to affiliates | 268 | 268 | ||||||
Enhanced junior subordinated notes | 1,483 | 798 | ||||||
Total long-term debt | 15,481 | 14,956 | ||||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes and investment tax credits | 4,244 | 4,137 | ||||||
Asset retirement obligations | 1,605 | 1,802 | ||||||
Pension and other postretirement benefit liabilities | 1,260 | 1,525 | ||||||
Regulatory liabilities | 1,215 | 944 | ||||||
Other | 474 | 561 | ||||||
Total deferred credits and other liabilities | 8,798 | 8,969 | ||||||
Total liabilities | 31,112 | 31,719 | ||||||
Commitments and Contingencies (see Note 23) | ||||||||
Subsidiary Preferred Stock Not Subject To Mandatory Redemption | 257 | 257 | ||||||
Common Shareholders’ Equity | ||||||||
Common stock—no par(1) | 6,525 | 5,994 | ||||||
Other paid-in capital | 185 | 182 | ||||||
Retained earnings | 4,686 | 4,170 | ||||||
Accumulated other comprehensive loss | (211 | ) | (269 | ) | ||||
Total common shareholders’ equity | 11,185 | 10,077 | ||||||
Total liabilities and shareholders’ equity | $ | 42,554 | $ | 42,053 |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
At December 31, | 2010 | 2009 | ||||||
(millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 62 | $ | 48 | ||||
Customer receivables (less allowance for doubtful accounts of $26 and $31) | 2,158 | 2,050 | ||||||
Other receivables (less allowance for doubtful accounts of $9 and $14) | 88 | 130 | ||||||
Inventories: | ||||||||
Materials and supplies | 609 | 590 | ||||||
Fossil fuel | 354 | 408 | ||||||
Gas stored | 200 | 187 | ||||||
Derivative assets | 739 | 1,128 | ||||||
Assets held for sale | — | 1,018 | ||||||
Regulatory assets | 407 | 170 | ||||||
Prepayments | 277 | 405 | ||||||
Other | 506 | 683 | ||||||
Total current assets | 5,400 | 6,817 | ||||||
Investments | ||||||||
Nuclear decommissioning trust funds | 2,897 | 2,625 | ||||||
Investment in equity method affiliates | 571 | 595 | ||||||
Restricted cash equivalents | 400 | — | ||||||
Other | 283 | 272 | ||||||
Total investments | 4,151 | 3,492 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 39,855 | 39,036 | ||||||
Accumulated depreciation, depletion and amortization | (13,142 | ) | (13,444 | ) | ||||
Total property, plant and equipment, net | 26,713 | 25,592 | ||||||
Deferred Charges and Other Assets | ||||||||
Goodwill | 3,141 | 3,354 | ||||||
Pension and other postretirement benefit assets | 712 | 702 | ||||||
Intangible assets | 642 | 693 | ||||||
Regulatory assets | 1,446 | 1,390 | ||||||
Other | 612 | 514 | ||||||
Total deferred charges and other assets | 6,553 | 6,653 | ||||||
Total assets | $ | 42,817 | $ | 42,554 |
56 |
At December 31, | 2010 | 2009 | ||||||
(millions) | ||||||||
LIABILITIESAND SHAREHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
Securities due within one year | $ | 497 | $ | 1,137 | ||||
Short-term debt | 1,386 | 1,295 | ||||||
Accounts payable | 1,562 | 1,401 | ||||||
Accrued interest, payroll and taxes | 849 | 676 | ||||||
Derivative liabilities | 633 | 679 | ||||||
Liabilities held for sale | — | 428 | ||||||
Regulatory liabilities | 135 | 536 | ||||||
Accrued severance | 132 | 4 | ||||||
Other | 579 | 677 | ||||||
Total current liabilities | 5,773 | 6,833 | ||||||
Long-Term Debt | ||||||||
Long-term debt | 14,023 | 13,730 | ||||||
Junior subordinated notes payable to affiliates | 268 | 268 | ||||||
Enhanced junior subordinated notes | 1,467 | 1,483 | ||||||
Total long-term debt | 15,758 | 15,481 | ||||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes and investment tax credits | 4,708 | 4,244 | ||||||
Asset retirement obligations | 1,577 | 1,605 | ||||||
Pension and other postretirement benefit liabilities | 765 | 1,260 | ||||||
Regulatory liabilities | 1,392 | 1,215 | ||||||
Other | 590 | 474 | ||||||
Total deferred credits and other liabilities | 9,032 | 8,798 | ||||||
Total liabilities | 30,563 | 31,112 | ||||||
Commitments and Contingencies (see Note 23) | ||||||||
Subsidiary Preferred Stock Not Subject To Mandatory Redemption | 257 | 257 | ||||||
Common Shareholders’ Equity | ||||||||
Common stock—no par(1) | 5,715 | 6,525 | ||||||
Other paid-in capital | 194 | 185 | ||||||
Retained earnings | 6,418 | 4,686 | ||||||
Accumulated other comprehensive loss | (330 | ) | (211 | ) | ||||
Total common shareholders’ equity | 11,997 | 11,185 | ||||||
Total liabilities and shareholders’ equity | $ | 42,817 | $ | 42,554 |
(1) | 1 billion shares authorized; 581 million shares and 599 million shares outstanding at December 31, 2010 and 2009, respectively. |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
57 |
Consolidated Statements of Common Shareholders’ Equity
Common Stock | Dominion Shareholders | Total | ||||||||||||||||||||||||
Shares | Amount | Other Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling interest | |||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||
Balance at December 31, 2006 | 698 | $ | 11,250 | $ | 128 | $ | 1,960 | $ | (425 | ) | $ | 23 | $ | 12,936 | ||||||||||||
Net income including noncontrolling interests | 2,555 | (1) | 6 | 2,561 | ||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 8 | 251 | 251 | |||||||||||||||||||||||
Stock repurchase and retirement | (129 | ) | (5,768 | ) | (5,768 | ) | ||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 46 | 46 | ||||||||||||||||||||||||
Cumulative effect of change in accounting principle(3) | (58 | ) | (58 | ) | ||||||||||||||||||||||
Dividends and other adjustments | 1 | (947 | ) | (946 | ) | |||||||||||||||||||||
Other comprehensive income, net of tax | 413 | 413 | ||||||||||||||||||||||||
Balance at December 31, 2007 | 577 | 5,733 | 175 | 3,510 | (12 | ) | 29 | 9,435 | ||||||||||||||||||
Net income including noncontrolling interests | 1,851 | (1) | (1 | ) | 1,850 | |||||||||||||||||||||
Issuance of stock—employee and direct stock purchase plans | 4 | 196 | 196 | |||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 2 | 65 | 65 | |||||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 7 | 7 | ||||||||||||||||||||||||
Cumulative effect of change in accounting principle(3) | (2 | ) | (2 | ) | ||||||||||||||||||||||
Deconsolidation of noncontrolling interest | (28 | ) | (28 | ) | ||||||||||||||||||||||
Dividends | (1,189 | )(2) | (1,189 | ) | ||||||||||||||||||||||
Other comprehensive loss, net of tax | (257 | ) | (257 | ) | ||||||||||||||||||||||
Balance at December 31, 2008 | 583 | 5,994 | 182 | 4,170 | (269 | ) | — | 10,077 | ||||||||||||||||||
Net income including noncontrolling interests | 1,304 | (1) | 1,304 | |||||||||||||||||||||||
Issuance of stock—employee and direct stock purchase plans | 6 | 212 | 212 | |||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 2 | 70 | 70 | |||||||||||||||||||||||
Other stock issuances(4) | 8 | 249 | 249 | |||||||||||||||||||||||
Tax benefit from stock awards and stock options exercised (net) | 3 | 3 | ||||||||||||||||||||||||
Cumulative effect of change in accounting principle(3) | �� | 12 | (12 | ) | — | |||||||||||||||||||||
Dividends | (800 | ) | (800 | ) | ||||||||||||||||||||||
Other comprehensive income, net of tax | 70 | 70 | ||||||||||||||||||||||||
Balance at December 31, 2009 | 599 | $ | 6,525 | $ | 185 | $ | 4,686 | $ | (211 | ) | $ | — | $ | 11,185 |
Common Stock | Dominion Shareholders | |||||||||||||||||||||||||||
Shares | Amount | Other Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling interest | Total | ||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||
Balance at December 31, 2007 | 577 | $ | 5,733 | $ | 175 | $ | 3,510 | $ | (12 | ) | $ | 29 | $ | 9,435 | ||||||||||||||
Net income including noncontrolling interests | 1,851 | (1 | ) | 1,850 | ||||||||||||||||||||||||
Issuance of stock—employee and direct stock purchase plans | 4 | 196 | 196 | |||||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 2 | 65 | 65 | |||||||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | — | 7 | 7 | |||||||||||||||||||||||||
Cumulative effect of change in accounting principle(1) | (2 | ) | (2 | ) | ||||||||||||||||||||||||
Deconsolidation of noncontrolling interest | (28 | ) | (28 | ) | ||||||||||||||||||||||||
Dividends(2) | (1,189 | )(3) | (1,189 | ) | ||||||||||||||||||||||||
Other comprehensive loss, net of tax | (257 | ) | (257 | ) | ||||||||||||||||||||||||
Balance at December 31, 2008 | 583 | 5,994 | 182 | 4,170 | (269 | ) | — | 10,077 | ||||||||||||||||||||
Net income including noncontrolling interests | 1,304 | 1,304 | ||||||||||||||||||||||||||
Issuance of stock—employee and direct stock purchase plans | 6 | 212 | 212 | |||||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 2 | 70 | 70 | |||||||||||||||||||||||||
Other stock issuances(4) | 8 | 249 | 249 | |||||||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 3 | 3 | ||||||||||||||||||||||||||
Cumulative effect of change in accounting principle(1) | 12 | (12 | ) | — | ||||||||||||||||||||||||
Dividends(2) | (800 | ) | (800 | ) | ||||||||||||||||||||||||
Other comprehensive income, net of tax | 70 | 70 | ||||||||||||||||||||||||||
Balance at December 31, 2009 | 599 | 6,525 | 185 | 4,686 | (211 | ) | — | 11,185 | ||||||||||||||||||||
Net income including noncontrolling interests | 2,825 | 2,825 | ||||||||||||||||||||||||||
Issuance of stock—employee and direct stock purchase plans | 1 | 10 | 10 | |||||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 2 | 80 | 80 | |||||||||||||||||||||||||
Stock repurchases | (21 | ) | (900 | ) | (900 | ) | ||||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 9 | 9 | ||||||||||||||||||||||||||
Dividends(2) | (1,093 | ) | (1,093 | ) | ||||||||||||||||||||||||
Other comprehensive loss, net of tax | (119 | ) | (119 | ) | ||||||||||||||||||||||||
Balance at December 31, 2010 | 581 | $ | 5,715 | $ | 194 | $ | 6,418 | $ | (330 | ) | — | $ | 11,997 |
(1) |
(2) | Includes subsidiary preferred dividends related to noncontrolling interests of $17 million, $17 million and $16 million in 2010, 2009 and 2008, respectively. |
(3) | Includes $256 million of accrued dividends due to the early declaration of the first quarter 2009 common dividend in December 2008. |
(4) | Includes at-the-market issuances and a |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Consolidated Statements of Comprehensive Income
Year Ended December 31, | 2009(1) | 2008 | 2007 | |||||||||
(millions) | ||||||||||||
Net income including noncontrolling interests | $ | 1,304 | $ | 1,850 | $ | 2,561 | ||||||
Other comprehensive income (loss), net of taxes: | ||||||||||||
Net deferred gains (losses) on derivatives—hedging activities, net of $(195), $(308) and $140 tax | 323 | 497 | (223 | ) | ||||||||
Changes in unrealized net gains (losses) on investment securities, net of $(86), $175 and $75 tax | 134 | (264 | ) | (110 | ) | |||||||
Changes in net unrecognized pension and other postretirement benefit costs, net of $(99), $421 and $(80) tax | 136 | (662 | ) | 164 | ||||||||
Amounts reclassified to net income: | ||||||||||||
Net derivative (gains) losses—hedging activities, net of $336, $(33) and $(376) tax | (549 | ) | 52 | 603 | ||||||||
Net realized losses on investment securities, net of $(1), $(77) and $(4) tax | 2 | 111 | 8 | |||||||||
Net pension and other postretirement benefit costs, net of $(19), $(8) and $(10) tax | 24 | 9 | 21 | |||||||||
Recognition of foreign currency translation gains upon sale of subsidiary | — | — | (50 | ) | ||||||||
Total other comprehensive income (loss) | 70 | (257 | ) | 413 | ||||||||
Comprehensive income including noncontrolling interests | 1,374 | 1,593 | 2,974 | |||||||||
Comprehensive income attributable to noncontrolling interests | 17 | 16 | 22 | |||||||||
Comprehensive income attributable to Dominion | $ | 1,357 | $ | 1,577 | $ | 2,952 |
Year Ended December 31, | 2010 | 2009(1) | 2008 | |||||||||
(millions) | ||||||||||||
Net income including noncontrolling interests | $ | 2,825 | $ | 1,304 | $ | 1,850 | ||||||
Other comprehensive income (loss), net of taxes: | ||||||||||||
Net deferred gains on derivatives-hedging activities, net of $(52), $(195) and $(308) tax | 84 | 323 | 497 | |||||||||
Changes in unrealized net gains (losses) on investment securities, net of $(54), $(86) and $175 tax | 89 | 134 | (264 | ) | ||||||||
Changes in net unrecognized pension and other postretirement benefit costs, net of $40, $(99) and $421 tax | (18 | ) | 136 | (662 | ) | |||||||
Amounts reclassified to net income: | ||||||||||||
Net derivative (gains) losses-hedging activities, net of $193, $336 and $(33) tax | (314 | ) | (549 | ) | 52 | |||||||
Net realized (gains) losses on investment securities, net of $9, $(1) and $(77) tax | (14 | ) | 2 | 111 | ||||||||
Net pension and other postretirement benefit costs, net of $(38), $(19) and $(8) tax | 54 | 24 | 9 | |||||||||
Total other comprehensive income (loss) | (119 | ) | 70 | (257 | ) | |||||||
Comprehensive income including noncontrolling interests | 2,706 | 1,374 | 1,593 | |||||||||
Comprehensive income attributable to noncontrolling interests | 17 | 17 | 16 | |||||||||
Comprehensive income attributable to Dominion | $ | 2,689 | $ | 1,357 | $ | 1,577 |
(1) | Other comprehensive income for the year ended December 31, 2009 excludes a $20 million ($12 million after-tax) adjustment to AOCI representing the cumulative effect of the change in accounting principle related to the recognition and presentation of other-than-temporary impairments. |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Consolidated Statements of Cash Flows
Year Ended December 31, | 2009 | 2008 | 2007 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net income including noncontrolling interests(1) | $ | 1,304 | $ | 1,850 | $ | 2,561 | ||||||
Adjustments to reconcile net income to net cash from operating activities: | ||||||||||||
Impairment of merchant generation assets | — | — | 387 | |||||||||
Impairment of gas and oil properties | 455 | — | — | |||||||||
Proposed rate settlement | 794 | — | — | |||||||||
Revision to asset retirement obligation | (103 | ) | — | — | ||||||||
Costs associated with early retirement of debt | — | — | 242 | |||||||||
Gain on sale of non-Appalachian E&P business | — | 42 | (3,826 | ) | ||||||||
Extraordinary item, net of income taxes | — | — | 158 | |||||||||
Charges related to termination of VPP agreements | — | — | 139 | |||||||||
Net change in realized and unrealized derivative (gains) losses | 14 | 169 | (245 | ) | ||||||||
Depreciation, depletion and amortization | 1,319 | 1,191 | 1,533 | |||||||||
Deferred income taxes and investment tax credits, net | (494 | ) | 269 | (1,285 | ) | |||||||
Other adjustments | (34 | ) | 132 | 85 | ||||||||
Changes in: | ||||||||||||
Accounts receivable | 458 | (222 | ) | 294 | ||||||||
Inventories | (10 | ) | (116 | ) | 52 | |||||||
Prepayments | (234 | ) | 222 | (142 | ) | |||||||
Deferred fuel and purchased gas costs, net | 802 | (532 | ) | (349 | ) | |||||||
Accounts payable | (156 | ) | (268 | ) | (190 | ) | ||||||
Accrued interest, payroll and taxes | (81 | ) | (177 | ) | 159 | |||||||
Margin deposit assets and liabilities | (273 | ) | 210 | 63 | ||||||||
Other operating assets and liabilities | 25 | (94 | ) | 134 | ||||||||
Net cash provided by (used in) operating activities | 3,786 | 2,676 | (230 | ) | ||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions | (3,665 | ) | (3,315 | ) | (2,177 | ) | ||||||
Additions to gas and oil properties, including acquisitions | (172 | ) | (239 | ) | (1,795 | ) | ||||||
Proceeds from assignment of natural gas drilling rights | — | 343 | — | |||||||||
Proceeds from sale of merchant generation peaking facilities | — | — | 339 | |||||||||
Proceeds from sale of non-Appalachian E&P business | — | (21 | ) | 13,877 | ||||||||
Proceeds from sales of securities and loan receivable collections and payoffs | 1,478 | 1,394 | 1,285 | |||||||||
Purchases of securities and loan receivable originations | (1,511 | ) | (1,355 | ) | (1,355 | ) | ||||||
Investment in affiliates and partnerships | (43 | ) | (376 | ) | (72 | ) | ||||||
Distributions from affiliates and partnerships | 174 | 18 | 31 | |||||||||
Other | 44 | 61 | 59 | |||||||||
Net cash provided by (used in) investing activities | (3,695 | ) | (3,490 | ) | 10,192 | |||||||
Financing Activities | ||||||||||||
Issuance (repayment) of short-term debt, net | (735 | ) | 273 | (575 | ) | |||||||
Issuance of long-term debt | 1,695 | 3,290 | 2,675 | |||||||||
Repayment of long-term debt, including redemption premiums | (447 | ) | (1,842 | ) | (5,012 | ) | ||||||
Repayment of affiliated notes payable | — | (412 | ) | (440 | ) | |||||||
Issuance of common stock | 456 | 240 | 226 | |||||||||
Repurchase of common stock | — | — | (5,768 | ) | ||||||||
Common dividend payments | (1,039 | ) | (916 | ) | (931 | ) | ||||||
Subsidiary preferred dividend payments(1) | (17 | ) | (17 | ) | (16 | ) | ||||||
Other | (25 | ) | (18 | ) | 24 | |||||||
Net cash provided by (used in) financing activities | (112 | ) | 598 | (9,817 | ) | |||||||
Increase (decrease) in cash and cash equivalents | (21 | ) | (216 | ) | 145 | |||||||
Cash and cash equivalents at beginning of year | 71 | 287 | 142 | |||||||||
Cash and cash equivalents at end of year(2) | $ | 50 | $ | 71 | $ | 287 | ||||||
Supplemental Cash Flow Information: | ||||||||||||
Cash paid during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts(1) | $ | 890 | $ | 841 | $ | 1,005 | ||||||
Income taxes | 1,480 | 413 | 3,155 | |||||||||
Significant noncash investing and financing activities: | ||||||||||||
Accrued capital expenditures | 240 | 194 | 58 | |||||||||
Debt for equity exchange | 56 | — | — | |||||||||
Accrued common and preferred dividends | — | 260 | — |
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net income including noncontrolling interests | $ | 2,825 | $ | 1,304 | $ | 1,850 | ||||||
Adjustments to reconcile net income including noncontrolling interests to net cash from operating activities: | ||||||||||||
Gain from sale of Appalachian E&P operations | (2,467 | ) | — | — | ||||||||
Loss from sale of Peoples | 113 | — | — | |||||||||
Charges related to workforce reduction program | 229 | — | — | |||||||||
Impairment of merchant generation assets | 194 | — | — | |||||||||
Impairment of gas and oil properties | 21 | 455 | — | |||||||||
Reserve for rate refunds | — | 794 | — | |||||||||
Rate refunds | (500 | ) | — | — | ||||||||
Contributions to qualified pension plans | (650 | ) | — | — | ||||||||
Depreciation, depletion and amortization (including nuclear fuel) | 1,258 | 1,319 | 1,191 | |||||||||
Deferred income taxes and investment tax credits, net | 682 | (494 | ) | 269 | ||||||||
Other adjustments | (61 | ) | (137 | ) | 174 | |||||||
Changes in: | ||||||||||||
Accounts receivable | (60 | ) | 458 | (222 | ) | |||||||
Inventories | 35 | (10 | ) | (116 | ) | |||||||
Prepayments | 139 | (234 | ) | 222 | ||||||||
Deferred fuel and purchased gas costs, net | (246 | ) | 802 | (532 | ) | |||||||
Accounts payable | 119 | (156 | ) | (268 | ) | |||||||
Accrued interest, payroll and taxes | 166 | (81 | ) | (177 | ) | |||||||
Margin deposit assets and liabilities | (147 | ) | (273 | ) | 210 | |||||||
Other operating assets and liabilities | 175 | 39 | 75 | |||||||||
Net cash provided by operating activities | 1,825 | 3,786 | 2,676 | |||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions | (3,384 | ) | (3,665 | ) | (3,315 | ) | ||||||
Additions to gas and oil properties, including acquisitions | (38 | ) | (172 | ) | (239 | ) | ||||||
Proceeds from assignment of natural gas drilling rights | — | — | 343 | |||||||||
Proceeds from sale of Appalachian E&P operations | 3,450 | — | — | |||||||||
Proceeds from sale of Peoples | 741 | — | — | |||||||||
Proceeds from sales of securities and loan receivable collections and payoffs | 2,814 | 1,478 | 1,394 | |||||||||
Purchases of securities and loan receivable originations | (2,851 | ) | (1,511 | ) | (1,355 | ) | ||||||
Investment in affiliates and partnerships | (2 | ) | (43 | ) | (376 | ) | ||||||
Distributions from affiliates and partnerships | 47 | 174 | 18 | |||||||||
Restricted cash equivalents | (396 | ) | 1 | 9 | ||||||||
Other | 38 | 43 | 31 | |||||||||
Net cash provided by (used in) investing activities | 419 | (3,695 | ) | (3,490 | ) | |||||||
Financing Activities | ||||||||||||
Issuance (repayment) of short-term debt, net | 91 | (735 | ) | 273 | ||||||||
Issuance of long-term debt | 1,090 | 1,695 | 3,290 | |||||||||
Repayment and repurchase of long-term debt | (1,492 | ) | (447 | ) | (1,842 | ) | ||||||
Repayment of affiliated notes payable | — | — | (412 | ) | ||||||||
Issuance of common stock | 74 | 456 | 240 | |||||||||
Repurchase of common stock | (900 | ) | — | — | ||||||||
Common dividend payments | (1,076 | ) | (1,039 | ) | (916 | ) | ||||||
Subsidiary preferred dividend payments | (17 | ) | (17 | ) | (17 | ) | ||||||
Other | (2 | ) | (25 | ) | (18 | ) | ||||||
Net cash provided by (used in) financing activities | (2,232 | ) | (112 | ) | 598 | |||||||
Increase (decrease) in cash and cash equivalents | 12 | (21 | ) | (216 | ) | |||||||
Cash and cash equivalents at beginning of year | 50 | 71 | 287 | |||||||||
Cash and cash equivalents at end of year(1) | $ | 62 | $ | 50 | $ | 71 | ||||||
Supplemental Cash Flow Information | ||||||||||||
Cash paid during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts | $ | 894 | $ | 890 | $ | 841 | ||||||
Income taxes | 991 | 1,480 | 413 | |||||||||
Significant noncash investing and financing activities: | ||||||||||||
Accrued capital expenditures | 240 | 240 | 194 | |||||||||
Debt for equity exchange | — | 56 | — | |||||||||
Accrued common and preferred dividends | — | — | 260 |
(1) |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Virginia Electric and Power Company
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (“Virginia Power”) as of December 31, 20092010 and 2008,2009, and the related consolidated statements of income, common shareholder’s equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009.2010. These financial statements are the responsibility of Virginia Power’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Virginia Power’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company and subsidiaries as of December 31, 20092010 and 2008,2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009,2010, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, Virginia Power changed its methods of accounting to adopt a new accounting standard for fair value measurements in 2008.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 26, 201025, 2011
[THIS PAGE INTENTIONALLY LEFT BLANK]
62 |
Virginia Electric and Power Company
Consolidated Statements of Income
Year Ended December 31, | 2009 | 2008 | 2007 | |||||||
(millions) | ||||||||||
Operating Revenue | $ | 6,584 | $ | 6,934 | $ | 6,181 | ||||
Operating Expenses | ||||||||||
Electric fuel and other energy-related purchases | 2,972 | 2,707 | 2,388 | |||||||
Purchased electric capacity | 409 | 410 | 429 | |||||||
Other operations and maintenance: | ||||||||||
Affiliated suppliers | 324 | 399 | 345 | |||||||
Other | 1,299 | 1,006 | 1,052 | |||||||
Depreciation and amortization | 641 | 608 | 568 | |||||||
Other taxes | 191 | 183 | 173 | |||||||
Total operating expenses | 5,836 | 5,313 | 4,955 | |||||||
Income from operations | 748 | 1,621 | 1,226 | |||||||
Other income | 104 | 52 | 55 | |||||||
Interest and related charges | 349 | 309 | 304 | |||||||
Income from operations before income tax expense and extraordinary item | 503 | 1,364 | 977 | |||||||
Income tax expense | 147 | 500 | 371 | |||||||
Income from operations before extraordinary item | 356 | 864 | 606 | |||||||
Extraordinary item(1) | — | — | (158 | ) | ||||||
Net Income | 356 | 864 | 448 | |||||||
Preferred dividends | 17 | 17 | 16 | |||||||
Balance available for common stock | $ | 339 | $ | 847 | $ | 432 |
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||||
(millions) | ||||||||||||
Operating Revenue | $ | 7,219 | $ | 6,584 | $ | 6,934 | ||||||
Operating Expenses | ||||||||||||
Electric fuel and other energy-related purchases | 2,495 | 2,972 | 2,707 | |||||||||
Purchased electric capacity | 449 | 409 | 410 | |||||||||
Other operations and maintenance: | ||||||||||||
Affiliated suppliers | 384 | 324 | 399 | |||||||||
Other | 1,361 | 1,299 | 1,006 | |||||||||
Depreciation and amortization | 671 | 641 | 608 | |||||||||
Other taxes | 218 | 191 | 183 | |||||||||
Total operating expenses | 5,578 | 5,836 | 5,313 | |||||||||
Income from operations | 1,641 | 748 | 1,621 | |||||||||
Other income | 100 | 104 | 52 | |||||||||
Interest and related charges | 347 | 349 | 309 | |||||||||
Income from operations before income tax expense | 1,394 | 503 | 1,364 | |||||||||
Income tax expense | 542 | 147 | 500 | |||||||||
Net Income | 852 | 356 | 864 | |||||||||
Preferred dividends | 17 | 17 | 17 | |||||||||
Balance available for common stock | $ | 835 | $ | 339 | $ | 847 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
63 |
Virginia Electric and Power Company
Consolidated Balance Sheets
At December 31, | 2009 | 2008 | ||||||
(millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 19 | $ | 27 | ||||
Customer receivables (less allowance for doubtful accounts of $12 and $8) | 880 | 940 | ||||||
Other receivables (less allowance for doubtful accounts of $6 and $7) | 72 | 82 | ||||||
Inventories (average cost method): | ||||||||
Materials and supplies | 306 | 275 | ||||||
Fossil fuel | 308 | 272 | ||||||
Derivative assets | 110 | 37 | ||||||
Prepayments | 52 | 28 | ||||||
Deferred income taxes | 222 | — | ||||||
Regulatory assets | 116 | 212 | ||||||
Other | 11 | 38 | ||||||
Total current assets | 2,096 | 1,911 | ||||||
Investments | ||||||||
Nuclear decommissioning trust funds | 1,204 | 1,053 | ||||||
Other | 4 | 3 | ||||||
Total investments | 1,208 | 1,056 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 25,643 | 23,476 | ||||||
Accumulated depreciation and amortization | (9,314 | ) | (8,915 | ) | ||||
Total property, plant and equipment, net | 16,329 | 14,561 | ||||||
Deferred Charges and Other Assets | ||||||||
Intangible assets | 217 | 210 | ||||||
Regulatory assets | 200 | 921 | ||||||
Other | 68 | 143 | ||||||
Total deferred charges and other assets | 485 | 1,274 | ||||||
Total assets | $ | 20,118 | $ | 18,802 |
At December 31, | 2010 | 2009 | ||||||
(millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 5 | $ | 19 | ||||
Customer receivables (less allowance for doubtful accounts of $11 and $12) | 905 | 880 | ||||||
Other receivables (less allowance for doubtful accounts of $6 at both dates) | 54 | 72 | ||||||
Inventories (average cost method): | ||||||||
Materials and supplies | 314 | 306 | ||||||
Fossil fuel | 283 | 308 | ||||||
Derivative assets | 27 | 110 | ||||||
Prepayments | 65 | 52 | ||||||
Deferred income taxes | — | 222 | ||||||
Regulatory assets | 318 | 116 | ||||||
Other | 10 | 11 | ||||||
Total current assets | 1,981 | 2,096 | ||||||
Investments | ||||||||
Nuclear decommissioning trust funds | 1,319 | 1,204 | ||||||
Restricted cash equivalents | 169 | — | ||||||
Other | 4 | 4 | ||||||
Total investments | 1,492 | 1,208 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 27,607 | 25,643 | ||||||
Accumulated depreciation and amortization | (9,712 | ) | (9,314 | ) | ||||
Total property, plant and equipment, net | 17,895 | 16,329 | ||||||
Deferred Charges and Other Assets | ||||||||
Intangible assets | 212 | 217 | ||||||
Regulatory assets | �� | 370 | 200 | |||||
Other | 312 | 68 | ||||||
Total deferred charges and other assets | 894 | 485 | ||||||
Total assets | $ | 22,262 | $ | 20,118 |
64 |
At December 31, | 2009 | 2008 | 2010 | 2009 | ||||||||||
(millions) | ||||||||||||||
LIABILITIESAND SHAREHOLDER’S EQUITY | ||||||||||||||
Current Liabilities | ||||||||||||||
Securities due within one year | $ | 245 | $ | 125 | $ | 15 | $ | 245 | ||||||
Short-term debt | 442 | 297 | 600 | 442 | ||||||||||
Accounts payable | 390 | 436 | 499 | 390 | ||||||||||
Payables to affiliates | 67 | 132 | 76 | 67 | ||||||||||
Affiliated current borrowings | 2 | 417 | 103 | 2 | ||||||||||
Accrued interest, payroll and taxes | 213 | 236 | 214 | 213 | ||||||||||
Customer deposits | 117 | 116 | 116 | 117 | ||||||||||
Regulatory liabilities | 491 | 20 | 109 | 491 | ||||||||||
Deferred income taxes | 83 | — | ||||||||||||
Accrued severance | 58 | — | ||||||||||||
Other | 241 | 250 | 205 | 241 | ||||||||||
Total current liabilities | 2,208 | 2,029 | 2,078 | 2,208 | ||||||||||
Long-Term Debt | 6,213 | 6,000 | 6,702 | 6,213 | ||||||||||
Deferred Credits and Other Liabilities | ||||||||||||||
Deferred income taxes and investment tax credits | 2,359 | 2,485 | 2,672 | 2,359 | ||||||||||
Asset retirement obligations | 636 | 715 | 669 | 636 | ||||||||||
Regulatory liabilities | 995 | 760 | 1,174 | 995 | ||||||||||
Other | 277 | 282 | 203 | 277 | ||||||||||
Total deferred credits and other liabilities | 4,267 | 4,242 | 4,718 | 4,267 | ||||||||||
Total liabilities | 12,688 | 12,271 | 13,498 | 12,688 | ||||||||||
Commitments and Contingencies (see Note 23) | ||||||||||||||
Preferred Stock Not Subject to Mandatory Redemption | 257 | 257 | 257 | 257 | ||||||||||
Common Shareholder’s Equity | ||||||||||||||
Common stock—no par(1) | 4,738 | 3,738 | 5,738 | 4,738 | ||||||||||
Other paid-in capital | 1,110 | 1,110 | 1,111 | 1,110 | ||||||||||
Retained earnings | 1,299 | 1,421 | 1,634 | 1,299 | ||||||||||
Accumulated other comprehensive income | 26 | 5 | 24 | 26 | ||||||||||
Total common shareholder’s equity | 7,173 | 6,274 | 8,507 | 7,173 | ||||||||||
Total liabilities and shareholder’s equity | $ | 20,118 | $ | 18,802 | $ | 22,262 | $ | 20,118 |
(1) | 300,000 shares authorized; |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
65 |
Virginia Electric and Power Company
Consolidated Statements of Common Shareholder’s Equity
Common Stock | Other Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||
Shares | Amount | |||||||||||||||||||
(millions, except for shares) | (thousands) | |||||||||||||||||||
Balance at December 31, 2006 | 198 | $ | 3,388 | $ | 887 | $ | 955 | $ | 162 | $ | 5,392 | |||||||||
Net income | 448 | 448 | ||||||||||||||||||
Equity contribution by Dominion | 220 | 220 | ||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 2 | 2 | ||||||||||||||||||
Dividends | (393 | ) | (393 | ) | ||||||||||||||||
Cumulative effect of change in accounting principle(1) | 5 | 5 | ||||||||||||||||||
Other comprehensive loss, net of tax | (133 | ) | (133 | ) | ||||||||||||||||
Balance at December 31, 2007 | 198 | 3,388 | 1,109 | 1,015 | 29 | 5,541 | ||||||||||||||
Net income | 864 | 864 | ||||||||||||||||||
Issuance of stock to Dominion | 12 | 350 | 350 | |||||||||||||||||
Tax benefit from stock awards and stock options exercised | 1 | 1 | ||||||||||||||||||
Dividends | (458 | ) | (458 | ) | ||||||||||||||||
Other comprehensive loss, net of tax | (24 | ) | (24 | ) | ||||||||||||||||
Balance at December 31, 2008 | 210 | 3,738 | 1,110 | 1,421 | 5 | 6,274 | ||||||||||||||
Net income | 356 | 356 | ||||||||||||||||||
Issuance of stock to Dominion | 32 | 1,000 | 1,000 | |||||||||||||||||
Dividends | (480 | ) | (480 | ) | ||||||||||||||||
Cumulative effect of change in accounting principle(1) | 2 | (2 | ) | — | ||||||||||||||||
Other comprehensive income, net of tax | 23 | 23 | ||||||||||||||||||
Balance at December 31, 2009 | 242 | $ | 4,738 | $ | 1,110 | $ | 1,299 | $ | 26 | $ | 7,173 |
Common Stock | �� | Other Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | |||||||||||||||||||
Shares | Amount | |||||||||||||||||||||||
(millions, except for shares) | (thousands) | |||||||||||||||||||||||
Balance at December 31, 2007 | 198 | $ | 3,388 | $ | 1,109 | $ | 1,015 | $ | 29 | $ | 5,541 | |||||||||||||
Net income | 864 | 864 | ||||||||||||||||||||||
Issuance of stock to Dominion | 12 | 350 | 350 | |||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 1 | 1 | ||||||||||||||||||||||
Dividends | (458 | ) | (458 | ) | ||||||||||||||||||||
Other comprehensive loss, net of tax | (24 | ) | (24 | ) | ||||||||||||||||||||
Balance at December 31, 2008 | 210 | 3,738 | 1,110 | 1,421 | 5 | 6,274 | ||||||||||||||||||
Net income | 356 | 356 | ||||||||||||||||||||||
Issuance of stock to Dominion | 32 | 1,000 | 1,000 | |||||||||||||||||||||
Dividends | (480 | ) | (480 | ) | ||||||||||||||||||||
Cumulative effect of change in accounting principle(1) | 2 | (2 | ) | — | ||||||||||||||||||||
Other comprehensive income, net of tax | 23 | 23 | ||||||||||||||||||||||
Balance at December 31, 2009 | 242 | 4,738 | 1,110 | 1,299 | 26 | 7,173 | ||||||||||||||||||
Net income | 852 | 852 | ||||||||||||||||||||||
Issuance of stock to Dominion | 33 | 1,000 | 1,000 | |||||||||||||||||||||
Dividends | (517 | ) | (517 | ) | ||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 1 | 1 | ||||||||||||||||||||||
Other comprehensive loss, net of tax | (2 | ) | (2 | ) | ||||||||||||||||||||
Balance at December 31, 2010 | 275 | $ | 5,738 | $ | 1,111 | $ | 1,634 | $ | 24 | $ | 8,507 |
(1) | See Note 3 for additional information. |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
66 |
Virginia Electric and Power Company
Consolidated Statements of Comprehensive Income
Year Ended December 31, | 2009(1) | 2008 | 2007 | ||||||||
(millions) | |||||||||||
Net income | $ | 356 | $ | 864 | $ | 448 | |||||
Other comprehensive income (loss), net of taxes: | |||||||||||
Net deferred gains (losses) on derivatives—hedging activities, net of $(4), $1 and $1 tax | 8 | (2 | ) | (1 | ) | ||||||
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of $(8), $17 and $80 tax | 12 | (29 | ) | (125 | ) | ||||||
Amounts reclassified to net income: | |||||||||||
Net realized (gains) losses on nuclear decommissioning trust funds, net of $(1), $(5) and $2 tax | 2 | 8 | (3 | ) | |||||||
Net derivative (gains) losses—hedging activities, net of $(1), $1 and $2 tax | 1 | (1 | ) | (4 | ) | ||||||
Other comprehensive income (loss) | 23 | (24 | ) | (133 | ) | ||||||
Comprehensive income | $ | 379 | $ | 840 | $ | 315 |
Year Ended December 31, | 2010 | 2009(1) | 2008 | |||||||||
(millions) | ||||||||||||
Net income | $ | 852 | $ | 356 | $ | 864 | ||||||
Other comprehensive income (loss), net of taxes: | ||||||||||||
Net deferred gains (losses) on derivatives-hedging activities, net of $1, $(4) and $1 tax | (1 | ) | 8 | (2 | ) | |||||||
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of $(6), $(8) and $17 tax | 9 | 12 | (29 | ) | ||||||||
Amounts reclassified to net income: | ||||||||||||
Net realized (gains) losses on nuclear decommissioning trust funds, net of $2, $(1) and $(5) tax | (2 | ) | 2 | 8 | ||||||||
Net derivative (gains) losses-hedging activities, net of $4, $(1) and $1 tax | (8 | ) | 1 | (1 | ) | |||||||
Other comprehensive income (loss) | (2 | ) | 23 | (24 | ) | |||||||
Comprehensive income | $ | 850 | $ | 379 | $ | 840 |
(1) | Other comprehensive income for the year ended December 31, 2009 excludes a $3 million ($2 million after-tax) adjustment to AOCI representing the cumulative effect of the change in accounting principle related to the recognition and presentation of other-than-temporary impairments. |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
67 |
Virginia Electric and Power Company
Consolidated Statements of Cash Flows
Year Ended December 31, | 2009 | 2008 | 2007 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net income | $ | 356 | $ | 864 | $ | 448 | ||||||
Adjustments to reconcile net income to net cash from operating activities: | ||||||||||||
Net change in realized and unrealized derivative (gains) losses | 17 | 10 | (67 | ) | ||||||||
Depreciation and amortization | 747 | 702 | 654 | |||||||||
Deferred income taxes and investment tax credits, net | (409 | ) | 304 | 256 | ||||||||
Proposed rate settlement | 782 | — | — | |||||||||
Extraordinary item, net of income taxes | — | — | 158 | |||||||||
Other adjustments | (58 | ) | (46 | ) | (58 | ) | ||||||
Changes in: | ||||||||||||
Accounts receivable | 58 | (205 | ) | (77 | ) | |||||||
Affiliated accounts receivable and payable | (13 | ) | 51 | (17 | ) | |||||||
Deferred fuel expenses, net | 639 | (423 | ) | (315 | ) | |||||||
Inventories | (67 | ) | (27 | ) | (15 | ) | ||||||
Prepayments | (24 | ) | 137 | (35 | ) | |||||||
Accounts payable | (58 | ) | (131 | ) | 165 | |||||||
Accrued interest, payroll and taxes | (24 | ) | 2 | 7 | ||||||||
Other operating assets and liabilities | 24 | (3 | ) | 112 | ||||||||
Net cash provided by operating activities | 1,970 | 1,235 | 1,216 | |||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions | (2,338 | ) | (1,902 | ) | (1,184 | ) | ||||||
Purchases of nuclear fuel | (150 | ) | (135 | ) | (111 | ) | ||||||
Purchases of securities | (731 | ) | (455 | ) | (551 | ) | ||||||
Proceeds from sales of securities | 715 | 410 | 520 | |||||||||
Proceeds from sales of emissions allowances held for consumption | 4 | 45 | 9 | |||||||||
Other | (68 | ) | 34 | 11 | ||||||||
Net cash used in investing activities | (2,568 | ) | (2,003 | ) | (1,306 | ) | ||||||
Financing Activities | ||||||||||||
Issuance (repayment) of short-term debt, net | 145 | 40 | (361 | ) | ||||||||
Issuance (repayment) of affiliated current borrowings, net | 585 | 653 | (26 | ) | ||||||||
Issuance of long-term debt | 460 | 1,490 | 2,250 | |||||||||
Repayment of long-term debt | (126 | ) | (553 | ) | (1,335 | ) | ||||||
Repayment of affiliated notes payable | — | (412 | ) | — | ||||||||
Common dividend payments | (463 | ) | (441 | ) | (377 | ) | ||||||
Preferred dividend payments | (17 | ) | (17 | ) | (16 | ) | ||||||
Other | 6 | (14 | ) | (14 | ) | |||||||
Net cash provided by financing activities | 590 | 746 | 121 | |||||||||
Increase (decrease) in cash and cash equivalents | (8 | ) | (22 | ) | 31 | |||||||
Cash and cash equivalents at beginning of year | 27 | 49 | 18 | |||||||||
Cash and cash equivalents at end of year | $ | 19 | $ | 27 | $ | 49 | ||||||
Supplemental Cash Flow Information | ||||||||||||
Cash paid during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts | $ | 353 | $ | 320 | $ | 305 | ||||||
Income taxes | 630 | 48 | 211 | |||||||||
Significant noncash investing and financing activities: | ||||||||||||
Accrued capital expenditures | 133 | 114 | — | |||||||||
Conversion of short-term and long-term borrowings payable to Dominion to equity | 1,000 | 350 | 220 |
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net income | $ | 852 | $ | 356 | $ | 864 | ||||||
Adjustments to reconcile net income to net cash from operating activities: | ||||||||||||
Depreciation and amortization (including nuclear fuel) | 782 | 747 | 702 | |||||||||
Deferred income taxes and investment tax credits, net | 609 | (409 | ) | 304 | ||||||||
Reserve for rate refunds | — | 782 | — | |||||||||
Rate refunds | (500 | ) | — | — | ||||||||
Contributions to qualified pension plans | (302 | ) | — | — | ||||||||
Charges related to workforce reduction program | 98 | — | — | |||||||||
Other adjustments | (40 | ) | (58 | ) | (46 | ) | ||||||
Changes in: | ||||||||||||
Accounts receivable | (9 | ) | 58 | (205 | ) | |||||||
Affiliated accounts receivable and payable | 11 | (13 | ) | 51 | ||||||||
Deferred fuel expenses, net | (213 | ) | 639 | (423 | ) | |||||||
Inventories | 17 | (67 | ) | (27 | ) | |||||||
Prepayments | (10 | ) | (24 | ) | 137 | |||||||
Accounts payable | 108 | (58 | ) | (131 | ) | |||||||
Accrued interest, payroll and taxes | 1 | (24 | ) | 2 | ||||||||
Other operating assets and liabilities | 5 | 41 | 7 | |||||||||
Net cash provided by operating activities | 1,409 | 1,970 | 1,235 | |||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions | (2,113 | ) | (2,338 | ) | (1,902 | ) | ||||||
Purchases of nuclear fuel | (121 | ) | (150 | ) | (135 | ) | ||||||
Purchases of securities | (1,211 | ) | (731 | ) | (455 | ) | ||||||
Proceeds from sales of securities | 1,192 | 715 | 410 | |||||||||
Restricted cash equivalents | (165 | ) | 1 | 9 | ||||||||
Other | (7 | ) | (65 | ) | 70 | |||||||
Net cash used in investing activities | (2,425 | ) | (2,568 | ) | (2,003 | ) | ||||||
Financing Activities | ||||||||||||
Issuance of short-term debt, net | 158 | 145 | 40 | |||||||||
Issuance of affiliated current borrowings, net | 1,101 | 585 | 653 | |||||||||
Issuance of long-term debt | 605 | 460 | 1,490 | |||||||||
Repayment and repurchase of long-term debt | (347 | ) | (126 | ) | (553 | ) | ||||||
Repayment of affiliated notes payable | — | — | (412 | ) | ||||||||
Common dividend payments | (500 | ) | (463 | ) | (441 | ) | ||||||
Preferred dividend payments | (17 | ) | (17 | ) | (17 | ) | ||||||
Other | 2 | 6 | (14 | ) | ||||||||
Net cash provided by financing activities | 1,002 | 590 | 746 | |||||||||
Decrease in cash and cash equivalents | (14 | ) | (8 | ) | (22 | ) | ||||||
Cash and cash equivalents at beginning of year | 19 | 27 | 49 | |||||||||
Cash and cash equivalents at end of year | $ | 5 | $ | 19 | $ | 27 | ||||||
Supplemental Cash Flow Information | ||||||||||||
Cash paid (received) during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts | $ | 349 | $ | 353 | $ | 320 | ||||||
Income taxes | (101 | ) | 630 | 48 | ||||||||
Significant noncash investing and financing activities: | ||||||||||||
Accrued capital expenditures | 136 | 133 | 114 | |||||||||
Settlement of debt and issuance of common stock to Dominion | 1,000 | 1,000 | 350 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
68 |
Combined Notes to Consolidated Financial Statements
NOTE 1. NATUREOF OPERATIONS
Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion’s operations are conducted through various subsidiaries, including Virginia Power, a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s common stock is owned by Dominion. Dominion’s operations also include a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, an LNG import and storage facility in Maryland and regulated gas transportation and distribution operations in Ohio Pennsylvania and West Virginia. As discussed in Note 4, Dominion completed the sale of substantially all of its Appalachian E&P operations in April 2010. In addition, Dominion completed the sale of its Pennsylvania gas distribution operations in February 2010.2010, which are reported as discontinued operations. Certain 2009 and 2008 amounts have been recast to reflect Peoples as discontinued operations. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations and natural gas and oil exploration and production in the Appalachian basin of the U.S.operations.
Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. In addition, Dominion also reports a Corporate and Other segment, thatwhich includes its corporate, service company and other functions (including unallocated debt) and the net impact of Peoples and certain DCI operations, disposed of or to be disposed of, which are discussed in Note 4.Notes 4 and 25, respectively. In addition, 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 in 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. See Note 27 for further discussion of Dominion’s and Virginia Power’s operating segments.
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.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
General
Dominion and Virginia Power make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.
Dominion’s and Virginia Power’s Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of their respective majority-owned subsidiaries.
Dominion and Virginia Power report certain contracts, instruments and instrumentsinvestments at fair value. See Note 7 for further information on fair value measurements.
Dominion maintains pension and other postretirement benefit plans. Virginia Power participates in certain of these plans. See Note 22 for further information on these plans.
Certain amounts in the 20082009 and 20072008 Consolidated Financial Statements and footnotes have been recastreclassified to conform to the 2009 presentation.2010 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, shareholders’ equity or cash flows.
Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.
Accounting for the Effects of Certain Types of Regulation
In March 1999, Virginia Power discontinued the application of accounting guidance for cost-based regulation for the majority of its generation operations upon the enactment of deregulation legislation in Virginia. Virginia Power’s electric utility transmission and distribution operations continued to apply this guidance since they remained subject to cost-of-service rate regulation.
In April 2007, the Virginia General Assembly passed legislation that returned the Virginia jurisdiction of Virginia Power’s generation operations to cost-of-service rate regulation. As a result, Virginia Power reapplied accounting guidance for cost-based regulation to those operations in April 2007, when the legislation was enacted. In connection with the reapplication of this guidance to these operations, Virginia Power prospectively changed certain of its accounting policies to those used by cost-of-service rate-regulated entities. Other than the items discussed below, the overall impact of these changes was not material to Virginia Power’s results of operations or financial condition in 2007. These policy changes are discussed further inDerivative Instruments,Investments, Property, Plant and Equipment andAsset Retirement Obligations.
Operating Revenue
Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. The Companies collect sales, consumption and consumer utility taxes; however, these amounts are excluded from revenue. Dominion’s customer receivables at December 31, 2010 and 2009 and 2008 included $409$466 million and $401$409 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity or natural gas delivered but not yet
billed to its utility customers. Virginia Power’s customer receivables at December 31, 2010 and 2009 and 2008 included $355$397 million and $341$355 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers.
The primary types of sales and service activities reported as operating revenue for Dominion are as follows:
Ÿ | Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; |
Ÿ | Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity; |
Ÿ | Regulated gas sales consist primarily of state-regulated retail natural gas sales and related distribution services; |
Ÿ | Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties. |
Ÿ | Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services and associated derivative activity. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; and |
Ÿ | Other revenue consists primarily of sales of oil and NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes miscellaneous service revenue from electric and gas distribution operations, and gas processing and handling revenue. |
69 |
Combined Notes to Consolidated Financial Statements, Continued
The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:
Ÿ | Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and |
Ÿ | Other revenue consists primarily of excess generation sold at market-based rates, miscellaneous service revenue from electric distribution operations and other miscellaneous revenue. |
Electric Fuel, Purchased Energy and Purchased Gas—Deferred Costs
Where permitted by regulatory authorities, the differences between Virginia Power’s actual electric fuel and purchased energy expenses and Dominion’s purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.
For electric fuel and purchased energy expenses, effective January 1, 2004, the fuel factor provisions for Virginia Power’s Virginia retail customers were fixed until July 1, 2007. Beginning July 1, 2007, the fuel factor has been adjusted annually as dis - -
cussed underElectric Regulation in Virginiain Note 14. Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 84% is currently subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.
Income Taxes
A consolidated federal income tax return is filed for Dominion and its subsidiaries, including Virginia Power. In addition, where applicable, combined income tax returns for Dominion and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed. Dominion also filed federal and provincial income tax returns for certain former subsidiaries in Canada. Virginia Power participates in an intercompany tax sharing agreement with Dominion and its subsidiaries and its current income taxes are based on its taxable income or loss, determined on a separate company basis.
Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.
Dominion and Virginia Power recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.
If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. For the majoritya substantial amount of Dominion’s and Virginia Power’s unrecognized tax benefits, the ultimate deductibility is highly certain, butcertain; however, there is uncertainty about the timing of such deductibility. Unrecognized tax benefits may also include amounts for which uncertainty exists as to whether such amounts are deductible as ordinary deductions or capital losses. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax
refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the consolidated balance sheets and current payables are included in accrued interest, payroll and taxes on the consolidated balance sheets, except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities.
Dominion and Virginia Power recognize changes in estimated interest payable on net underpayments and overpayments of income taxes in interest expense and estimated penalties that may result from the settlement of some uncertain tax positions in other income. In its Consolidated Statements of Income for 2010, 2009 2008 and 2007,2008, Dominion recognized a reduction in interest expense of
Combined Notes to Consolidated Financial Statements, Continued
$19 $18 million and a reduction in penalties of less than $1 million, a reduction in interest expense of $19 million and a reduction in penalties of $2 million and less than $1 million of interest expense and no penalties, and a reduction in interest expense of $19 million and no penalties, respectively. Dominion had accrued interest receivable of $27 million and interest and penalties payable of less than $1 million at December 31, 2010, and interest receivable of $26 million and interest and penalties payable of $4 million at December 31, 2009, and interest receivable of $2 million and interest and penalties payable of $5 million at December 31, 2008.2009.
Virginia Power’s interest and penalties were immaterial in 2010, 2009 2008 and 2007.2008.
At December 31, 2010, Virginia Power’s Consolidated Balance Sheet included $46 million of prepaid federal and state income taxes and $102 million of noncurrent federal and state income taxes payable. At December 31, 2009, Virginia Power’s Consolidated Balance Sheet included $21 million of prepaid federal income taxes, $3 million of current state income taxes payable and $45 million of noncurrent federal and state income taxes payable. At December 31, 2008, Virginia Power’s Consolidated Balance Sheet included $3 million of prepaid state income taxes, $6 million of current federal and state income taxes payable, and $106 million of noncurrent federal and state income taxes payable.
Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.
Cash and Cash Equivalents
Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 20092010 and 2008,2009, Dominion’s accounts payable included $55$56 million and $60$55 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 20092010 and 2008,2009, Virginia Power’s accounts payable included $22$28 million and $23$22 million, respectively, of checks outstanding but not yet presented for payment. For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.
Derivative Instruments
Dominion and Virginia Power use derivative instruments such as futures, swaps, forwards, options and FTRs to manage the commodity, currency exchange and financial market risks of their business operations.
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All derivatives, exceptother than those for which an exception applies, are reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting—accounting, normal purchases and normal sales—sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.
Dominion and Virginia Power do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion had margin assets of $149
$244 million and margin liabilities of $114 million, and Virginia Power had margin assets of $4 million and did not have any margin liabilities associated with cash collateral at December 31, 2009. Dominion had margin assets of $168 million and margin liabilities of $406 million, and Virginia Power had margin assets of $18 million and margin liabilities of $4$149 million associated with cash collateral at December 31, 2008.2010 and 2009, respectively. Dominion had margin liabilities of $62 million and $114 million associated with cash collateral at December 31, 2010 and 2009, respectively. Virginia Power’s margin assets and liabilities associated with cash collateral were not material at December 31, 2010 and 2009.
To manage price risk, Dominion and Virginia Power hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. As part of Dominion’s strategy to market energy and manage related risks, it also manages a portfolio of commodity-based financial derivative instruments held for trading purposes. Dominion uses established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and uses various derivative instruments to reduce risk by creating offsetting market positions.
Statement of Income Presentation:
Ÿ | Derivatives Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis. |
Ÿ | Derivatives Not Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses or interest and related charges based on the nature of the underlying risk. |
Following the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction ofIn Virginia Power’s generation operations, for jurisdictions subject to cost-based regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities.liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.
DERIVATIVE INSTRUMENTS DESIGNATED ASAS HEDGING INSTRUMENTS
Dominion and Virginia Power designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, Dominion and Virginia Power formally document the relationshiprelation-
ship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using the hedging instrument. The Companies assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges.
Cash Flow Hedges—A portionmajority of Dominion’s and Virginia Power’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and other energy-related products. A portion of Virginia Power’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase of electricity, natural gas and other energy-related products. The Companies also use foreign currency forward and option contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which Dominion and Virginia Power are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.
Fair Value Hedges—Dominion and Virginia Power also use fair value hedges to mitigate the fixed price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, they have designated interest rate swaps as fair value hedges on certain fixed-rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Derivative gains and losses from the hedged item are reclassified to earnings when the hedged item is included in earnings, or earlier, if the hedged item no longer qualifies for hedge accounting. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting.
See Note 7 for further information about fair value measurements and associated valuation methods for derivatives. See Note 8 for further information on derivatives.
Property, Plant and Equipment
Property, plant and equipment, including additions and replacements is recorded at original cost, consisting of labor and materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as it is incurred.
In 2010, 2009 2008 and 2007,2008, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $102 million, $76 million $88 million, and $102$88 million, respectively. In 2010, 2009 and
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Combined Notes to Consolidated Financial Statements, Continued
2008, and 2007, Virginia Power capitalized interest costs and AFUDC to property, plant and equipment of $61 million, $47 million and $21 million, and $27 million, respectively. Upon reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of its generation operations in April 2007, Virginia Power discontinued capitalizing interest on generation-related construction projects since the Virginia Commission previously allowed for current recovery of construction financing costs. Under current Virginia legislation, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2010, 2009 2008 and 2007,2008, Virginia Power recorded $34
$13 million, $18$34 million and $1$18 million of AFUDC related to these projects, respectively.
For Virginia Power property subject to cost-of-service rate regulation, including electric distribution, electric transmission, and generation property effective April 2007, and for certain Dominion natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement, with gains and losses recorded on the sales of property. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities.
For Dominion and Virginia Power property that is not subject to cost-of-service rate regulation, including nonutility property, and utility generation property prior to the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations in April 2007, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.
Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. Dominion’s and Virginia Power’s depreciation rates on utility property, plant and equipment are as follows:
Year Ended December 31, | 2009 | 2008 | 2007 | |||
(percent) | ||||||
Dominion | ||||||
Generation (1) | 2.62 | 2.60 | 2.24 | |||
Transmission | 2.27 | 2.22 | 2.26 | |||
Distribution | 3.21 | 3.22 | 3.21 | |||
Storage | 2.83 | 2.87 | 2.78 | |||
Gas gathering and processing | 2.18 | 2.13 | 2.09 | |||
General and other | 4.33 | 4.35 | 4.92 | |||
Virginia Power | ||||||
Generation(1) | 2.62 | 2.60 | 2.24 | |||
Transmission | 1.92 | 2.03 | 1.98 | |||
Distribution | 3.33 | 3.37 | 3.38 | |||
General and other | 3.95 | 3.97 | 4.57 |
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||||
(percent) | ||||||||||||
Dominion | ||||||||||||
Generation | 2.59 | 2.62 | 2.60 | |||||||||
Transmission | 2.24 | 2.27 | 2.22 | |||||||||
Distribution | 3.20 | 3.21 | 3.22 | |||||||||
Storage | 2.75 | 2.83 | 2.87 | |||||||||
Gas gathering and processing | 2.39 | 2.18 | 2.13 | |||||||||
General and other | 4.60 | 4.33 | 4.35 | |||||||||
Virginia Power | ||||||||||||
Generation | 2.59 | 2.62 | 2.60 | |||||||||
Transmission | 1.94 | 1.92 | 2.03 | |||||||||
Distribution | 3.33 | 3.33 | 3.37 | |||||||||
General and other | 4.28 | 3.95 | 3.97 |
Dominion’s nonutility property, plant and equipment, excluding E&P properties, is depreciated using the straight-line method over the following estimated useful lives:
Asset | Estimated Useful Lives | |||
Merchant generation—nuclear | 29–44 years | |||
Merchant generation—other | ||||
General and other | 3–25 years |
Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.
Combined Notes to Consolidated Financial Statements, Continued
Dominion follows the full cost method of accounting for its 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. Thesewhich subjects capitalized costs areto a
quarterly ceiling test using hedge-adjusted prices. Due to the April 2010 sale of substantially all of its Appalachian E&P operations, as of December 31, 2010, Dominion no longer has any significant gas and oil properties subject to a quarterly ceiling test. Under the ceiling test amounts capitalized are limitedcalculation.
At March 31, 2010, Dominion recorded a ceiling test impairment charge of $21 million ($13 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income primarily due to a decline in hedge-adjusted prices reflecting the present valuediscontinuance of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, discounted at 10%, using trailing twelve month average natural gas and oil prices adjustedhedge accounting for certain cash flow hedges, as discussed in place. Prior to adoption of the SEC’s Final Rule,Modernization of Oil and Gas Reporting effective December 31, 2009, period-end gas and oil prices were used when performing the full cost ceiling test calculation; however, subsequent commodity price increases could be utilized to reduce or eliminate any impairment in accordance with SEC guidelines. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. Approximately 3% of Dominion’s anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Using trailing twelve month average prices, adjusted for cash flow hedges in place, there was no ceiling test impairment at December 31, 2009. Excluding the effects of hedge-adjusted prices in calculating the ceiling test limitation would have resulted in an approximately $41 million ($25 million after-tax) ceiling test impairment.Note 4.
In 2009, Dominion recorded a ceiling test impairment charge of $455 million ($281 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income. Excluding the effects of hedge-adjusted prices in calculating the ceiling limitation, the impairment would have been $631 million ($387 million after-tax). Future cash flows associated with settling AROs that have been accrued in Dominion’s Consolidated Balance Sheets are excluded from Dominion’s calculations under the full cost ceiling test. Decreases in commodity prices, as well as changes in production levels, reserve estimates, future development costs, and lifting costs and other factors could result in future ceiling test impairments.
Depletion of Dominion’s gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the depletable base of costs subject to depletion also includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The costs of investments in unproved properties including associated exploration-related costs are initially excludedIn 2010, Dominion recognized a gain from the depletable base. Until the properties are evaluated, a ratable portionsale of the capitalized costs is periodically reclassified to the depletable base, determined on a property by property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depletable base. 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. In 2007, Dominion recognized gains from the salessubstantially all of its Canadian and U.S. non-AppalachianAppalachian E&P businessesoperations as discussed in Note 4.
Emissions Allowances
Emissions allowances permit the holder of the allowance to emit certain gaseous by-products of fossil fuel combustion, including SO2, NOX and CO2. SO2 and NOX emissions allowances are issued to Dominion and Virginia Power by the EPA.EPA and may also be purchased and sold via third party contracts. CO2 emissions allowances are available for purchase by Dominion through quarterly auctions held by participating RGGI states. The first RGGI auctions of CO2 allowances were conducted in 2008 to be used for the compliance period beginning in 2009 and extending through 2011. Compliance with the RGGI requirements only applies to certain of Dominion’s merchant power stations located in the Northeast.
Allowances held may be transacted with third parties or consumed as these emissions are generated. Allowances allocated to or acquired by the Companies’ generation operations are held primarily for consumption.
Allowances held for consumption are classified as intangible assets in the Consolidated Balance Sheets. Carrying amounts are based on the cost to acquire the allowances or, in the case of a business combination, on the fair values assigned to them in the allocation of the purchase price of the acquired business. AllowancesA portion of Dominion’s and Virginia Power’s SO2 and NOX allowances are issued directly to Dominion or Virginia Power by the EPA are carried at zero cost.
These allowances are amortized in the periods the emissions are generated, with the amortization reflected in DD&A in the Consolidated Statements of Income. Purchases and sales of these allowances are reported as investing activities in the Consolidated Statements of Cash Flows and gains or losses resulting from sales are reported in other operations and maintenance expense in the Consolidated Statements of Income.
Long-Lived and Intangible Assets
Dominion and Virginia Power perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.
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Intangible assets with finite lives are amortized over their estimated useful lives or as consumed.lives. See Note 7 for a discussion of impairments related to certain long-lived assets.
Regulatory Assets and Liabilities
The accounting for Dominion’s regulated gas and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs are deferred as regulatory assets that otherwise would be expensed by nonregulated companies.companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.
Asset Retirement Obligations
Dominion and Virginia Power recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed. These amounts are capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. With the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of its generation operations in April 2007, Virginia Power now reports accretion of the AROs associated with nuclear decommissioning of its nuclear power stations due to the passage of time as an adjustment to the related regulatory liability for certain jurisdictions, consistent with the practice for its other cost-of-service rate regulated operations. Previously, Virginia Power reported such expense in other operations and maintenance expense in the Consolidated Statements of Income. Dominion and Virginia Power report accretion of all other AROs in other operations and maintenance expense in the Consolidated Statements of Income.
Amortization of Debt Issuance Costs
Dominion and Virginia Power defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation have also been deferred and are amortized over the lives of the new issuances.
Investments
MARKETABLE EQUITYAND DEBT SECURITIES
Dominion accounts for and classifies investments in marketable equity and debt securities as trading or available-for-sale securities. Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities.
Ÿ | Trading securitiesinclude marketable equity and debt securities held by Dominion in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair |
value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income. |
Ÿ | Available-for-sale securitiesinclude all other marketable equity and debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. |
included in other income and unrealized gains and losses are reported as a component of AOCI, net of tax. |
In determining realized gains and losses for marketable equity and debt securities, the cost basis of the security is based on the specific identification method.
NON-MARKETABLE INVESTMENTS
Dominion and Virginia Power account for illiquid and privately held securities for which market prices or quotations are not readily available under either the equity or cost method. Non-marketable investments include:
Ÿ | Equity method investmentswhen Dominion and Virginia Power have the ability to exercise significant influence, but not control, over the investee. Dominion’s investments are included in investments in equity method affiliates and Virginia Power’s investments are included in other investments in their Consolidated Balance Sheets. Dominion and Virginia Power record equity method adjustments in other income in the Consolidated Statements of Income including: their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method. |
Ÿ | Cost method investments when Dominion and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion’s and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds. |
OTHER-THAN-TEMPORARY IMPAIRMENT
Dominion and Virginia Power periodically review their investments to determine whether a decline in fair value should be considered other than temporary. If a decline in fair value of any security is determined to be other than temporary, the security is written down to its fair value at the end of the reporting period.
Decommissioning and Rabbi Trust Investments—Special Considerations
Ÿ | Debt Securities—The FASB amended its guidance for the recognition and presentation of other-than-temporary impairments, which Dominion and Virginia Power adopted effective April 1, 2009. The recognition provisions of this |
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Combined Notes to Consolidated Financial Statements, Continued
guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities. Prior to the adoption of this guidance, Dominion and Virginia Power considered all debt securities held by their nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired as they did not have the ability to ensure the investments were held through the anticipated recovery period. |
Effective with the adoption of this guidance, using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell
Combined Notes to Consolidated Financial Statements, Continued
the debt security before recovery of its fair value up to its cost basis. For anyIf that is the case, but the debt security that is deemed to have experienced a credit loss, the Companies record the credit loss in earnings and any remaining portion of the unrealized loss in other comprehensive income. They evaluate creditCredit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors. For investments in Virginia Power’s nuclear decommissioning trusts, net realized and unrealized gains and losses on debt securities (including any other-than-temporary impairments) continue to be recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation.
Ÿ | Equity securities and other |
Inventories
Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory used in Dominion’s localOhio gas distribution operations is valued using the LIFO method. Under the LIFO method, those inventories werestored gas inventory was valued at $30$48 million and $8$30 million at December 31, 2010 and 2009, and 2008, respectively. The increase in inventory from 2008 to 2009 reflects the reclassification of Hope’s inventory from assets held for sale due to Dominion’s decision to retain this subsidiary. Based on the average price of gas purchased during 20092010 and 2008,2009, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $172$107 million and $208$172 million, respectively. Stored gas inventory held by certain nonregulated gas operations is valued using the weighted-average cost method.
Gas Imbalances
TRANSPORTATION
Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion values these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities.
Imbalances are primarily settled in-kind. Imbalances due to Dominion from other parties are reported in other current assets and imbalances that Dominion owes to other parties are reported in other current liabilities in the Consolidated Balance Sheets.
PRODUCTION
Dominion uses the sales method of accounting for gas imbalances related to natural gas production. An imbalance is created when
Company volumes of gas sold pertaining to a property do not equate to the volumes to which Dominion is entitled based on its interest in the property. A liability is recognized when Dominion’s excess sales over entitled volumes exceeds its net remaining property reserves.
Goodwill
Dominion evaluates goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.
NOTE 3. NEWLY ADOPTED ACCOUNTING STANDARDS
2009
NONCONTROLLING INTERESTSIN CONSOLIDATED FINANCIAL STATEMENTS
Effective January 1, 2009, Dominion adopted new accounting guidance for noncontrolling interests that requires retrospective application of presentation and disclosure changes including that noncontrolling interests be reported as a component of equity and that net income attributable to the parent and noncontrolling interests be separately identified in the income statement.
As discussed in Note 25, Dominion previously consolidated an investment in the subordinated notes of a third-party CDO entity held by DCI, which was deconsolidated as of March 31, 2008. The noncontrolling interest income from the CDO entity was previously reported in minority interest in Dominion’s Consolidated Statements of Income and in operating activities in its Consolidated Statements of Cash Flows. Dominion’s subsidiary preferred dividends were previously included in interest and related charges in its Consolidated Statements of Income and in operating activities in its Consolidated Statements of Cash Flows. Due to the application of new accounting guidance for noncontrolling interests, Dominion now reflects its interest in the previously held CDO entity’s income and its subsidiary preferred dividends as an adjustment (noncontrolling interests) to arrive at net income attributable to Dominion in its Consolidated Statements of Income and reflects its subsidiary preferred dividends in financing activities in its Consolidated Statements of Cash Flows. Since Dominion’s subsidiary preferred stock does not qualify as permanent equity, Dominion continues to report these amounts as mezzanine equity in its Consolidated Balance Sheets.
RECOGNITIONAND PRESENTATIONOF OTHER-THAN-TEMPORARY IMPAIRMENTS
The FASB amended its guidance for the recognition and presentation of other-than-temporary impairments, which Dominion and Virginia Power adopted effective April 1, 2009. The recognition provisions of this guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities. Prior to the adoption of this guidance, as described in Note 2, the Companies considered all debt securities held by their nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired as they did not have the ability to ensure the investments were held through the anticipated recovery period.
Upon the adoption of this guidance for debt investments held at April 1, 2009, Dominion recorded a $20 million ($12 million after-tax) and Virginia Power recorded a $3 million ($2 million after-tax) cumulative effect of a change in accounting principle to reclassify the non-credit related portion of previously recognized other-than-temporary impairments from retained earnings to AOCI, reflecting the fixed-income investment managers’ intent and ability to hold the debt securities until the amortizedrecovery of their fair values up to their cost bases are recovered.bases.
SEC FINAL RULE,MODERNIZATIONOF OILAND GAS REPORTING
Effective December 31, 2009, Dominion adopted the SEC Final Rule,Modernization of Oil and Gas Reporting, which revised the existing Regulation S-K and Regulation S-X reporting requirements. Under the new requirements, the ceiling test is calculated using an average price based on the prior 12-month period rather than period-end prices. Going forward,Due to the April 2010 sale of substantially all of its Appalachian E&P operations, as of December 31, 2010 Dominion will be less likely to experience a ceiling test impairment based solely on a sudden decrease inno longer has any significant gas and oil prices.properties subject to the ceiling test calculation.
2008
FAIR VALUE MEASUREMENTS
Dominion and Virginia Power adopted new FASB guidance effective January 1, 2008, which defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. The guidance applies broadly to financial and non-financial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances.
Generally, the provisions of this guidance were applied prospectively. Certain situations, however, required retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application was required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses. Retrospective application resulted in an immaterial amount recognized through a cumulative effect of accounting change adjustment to retained earnings as of January 1, 2008 for Dominion and no adjustment for Virginia Power.
In February 2008, the FASB amended the fair value measurements guidance to exclude leasing transactions. However, the exclusion does not apply to fair value measurements of assets and liabilities recorded as a result of a lease transaction but measured pursuant to other pronouncements within the scope of the fair value measurements guidance.
See Note 7 for further information on fair value measurements.
ENDORSEMENT SPLIT-D-OLLARDOLLAR LIFE INSURANCE ARRANGEMENTS
Effective January 1, 2008, Dominion adopted new accounting guidance for deferred compensation and postretirement benefit aspects of endorsement split-dollar life insurance arrangements. This guidance specifies that if an employer provides a benefit to an employee under the endorsement split-dollar life insurance arrangement that extends to post-retirement periods, it should
recognize a liability for future benefits based on the substantive agreement with the employee. Dominion’s adoption of this guidanceguid-
ance resulted in an immaterial amount recognized through a cumulative effect of accounting change adjustment to retained earnings as of January 1, 2008.
2007
ACCOUNTINGFOR UNCERTAINTYIN INCOME TAXES
Effective January 1, 2007, Dominion and Virginia Power adopted new FASB guidance for accounting for uncertainty in income taxes. As a result of the implementation of this guidance, Dominion recorded a $58 million charge and Virginia Power recorded a $5 million benefit to beginning retained earnings, representing the cumulative effect of the change in accounting principle. At January 1, 2007, Dominion and Virginia Power had unrecognized tax benefits of $625 million and $225 million, respectively. For the majority of unrecognized tax benefits, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility.
NOTE 4. DISPOSITIONS
Sale of Non-Appalachian Natural Gas and OilAppalachian E&P Operations and Assets
In 2007,April 2010, Dominion completed the sale of substantially all of its non-AppalachianAppalachian E&P operations to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. The transaction includes the mineral rights to approximately 491,000 acres in the Marcellus Shale formation. Dominion retained certain oil and natural gas wells located on or near its natural gas storage fields. The transaction generated after-tax proceeds of approximately $2.2 billion and oil E&P operations and receivedresulted in an after-tax gain of approximately $13.3$1.4 billion, for its U.S. non-Appalachian E&P operations and approximately $624which includes a $134 million for its Canadian E&P operations.
Due towrite-off of goodwill. Proceeds from the sale have been or will be used to pay taxes on the gain, offset all of Dominion’s entire Canadian cost pool,equity needs for 2010 and its expected market equity issuance needs for 2011, repurchase common stock, fund contributions to Dominion’s pension plans and the resultsDominion Foundation, reduce debt and offset the majority of operations for Dominion’s Canadian E&P business are reported as discontinued operations in the Consolidated Statementsimpact of Income. Virginia Power’s 2009 base rate case settlement.
The results of operations for Dominion’s U.S. non-AppalachianAppalachian E&P business wereare not reported as discontinued operations in the Consolidated Statements of Income since Dominion did not sell its entire U.S. cost pool, which includespool.
Due to the retained Appalachian assets.sale, hedge accounting was discontinued for certain cash flow hedges since it became probable that the forecasted sales of gas would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a $42 million ($25 million after-tax) benefit, recorded in operating revenue in its Consolidated Statement of Income, reflecting the reclassification of gains from AOCI to earnings for these contracts in March 2010.
Sale of Peoples
In February 2010, Dominion used mostcompleted the sale of thePeoples to PNG Companies LLC and netted after-tax proceeds from these dispositions to reduce outstanding debt and repurchase shares of its common stock.
CANADIAN OPERATIONS
approximately $542 million. The sale of Dominion’s Canadian E&P operations resulted in an after-tax gainloss of $59approximately $140 million, ($0.08 per share).including post-closing adjustments, and a $79 million write-off of goodwill. The sale also resulted in after-tax expenses of approximately $27 million, including transaction and benefit-related costs. Prior to the sale, Peoples had income from operations of $12 million after-tax during 2010.
The following table presents selected information regardingPrior to March 31, 2010, Dominion did not report Peoples as discontinued operations since it expected to have significant continuing cash flows related primarily to the sale of natural gas production from its Appalachian E&P operations to Peoples. Due to the sale of its Appalachian E&P operations, Dominion will not have significant continuing cash flows with Peoples; therefore, the results of operations of Dominion’s Canadian E&P operations, which are reported asPeoples were reclassified to discontinued operations in the Consolidated Statements of Income:Income for all periods presented. Certain 2009 and 2008 amounts have been recast to reflect Peoples as discontinued operations.
Year Ended December 31, | 2008 | 2007 | ||||||
(millions) | ||||||||
Operating revenue | $ | — | $ | 67 | ||||
Income (loss) before income taxes | (5 | )(1) | 145 | (2) |
Combined Notes to Consolidated Financial Statements, Continued
COSTS ASSOCIATEDWITH DISPOSALOF NON-APPALACHIAN E&P OPERATIONS
The sales of Dominion’s U.S. non-Appalachian E&P operations resulted in the discontinuance of hedge accounting for certain cash flow hedges since it became probable that the forecasted sales of gas and oil would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized charges, recorded in operating revenue in the Consolidated Statement of Income, predominantly reflecting the reclassification of losses from AOCI to earnings and subsequent changes in fair value of these contracts of $541 million ($342 million after-tax) in 2007. Dominion terminated these gas and oil derivatives subsequent to the disposal of the non-Appalachian E&P business. Dominion recognized a similar charge of $15 million ($9 million after-tax) in 2007 related to its Canadian operations, which is reflected in discontinued operations in the Consolidated Statement of Income.
During 2007, Dominion also recorded a charge in operating revenue in the Consolidated Statement of Income of approximately $171 million ($108 million after-tax) for the recognition of certain forward gas contracts that previously qualified for the normal purchase and sales exemption. The $171 million charge included $139 million associated with VPP agreements to which Dominion was a party. Dominion paid $250 million to terminate the VPP agreements and retained the VPP royalty interests formerly associated with these agreements.
Additionally, Dominion recognized expenses for employee severance, retention and other costs of $91 million ($56 million after-tax) in 2007, related to the sale of its U.S. non-Appalachian E&P business, which are reflected in other operations and maintenance expense in the Consolidated Statement of Income. Dominion also recognized expenses for employee severance, retention, legal, investment banking and other costs of $30 million ($18 million after-tax) in 2007 related to the sale of its Canadian E&P operations, which are reflected in discontinued operations in the Consolidated Statement of Income.
Dominion recognized a gain of approximately $3.6 billion ($2.1 billion after-tax) from the disposition of its U.S. non-Appalachian E&P operations. This gain is net of expenses related to the disposition plan for transaction costs, including audit, legal, investment banking and other costs of $48 million ($30 million after-tax), but excludes severance and retention costs and costs associated with the discontinuance of hedge accounting and recognition of forward gas contracts. In 2008, the net effect of contractual post-closing adjustments resulted in a $42 million ($26 million after-tax) reduction to the gain recognized in 2007. The total impact on net income from the sale of Dominion’s Canadian and U.S. non-Appalachian E&P operations was a benefit of $1.5 billion for 2007. This benefit is net of expenses for transaction costs, severance and retention costs, costs associated with the discontinuance of hedge accounting and recognition of forward gas contracts, and costs associated with Dominion’s debt tender offer completed in July 2007 using a portion of the proceeds received from the sale as discussed below.
Dominion completed a debt tender offer repurchasing $2.5 billion of its debt securities in July 2007. Dominion recognized charges of $242 million ($148 million after-tax) primarily in connection with the early redemption of this debt. Of this amount, $234 million ($143 million after-tax) was recorded in
interest and related charges in its Consolidated Statement of Income.
Disposition of Partially Completed Generation Facility
In September 2007, Dominion completed the sale of Dresden to AEP Generating Company for $85 million. During 2007, Dominion recorded a $387 million ($252 million after-tax) impairment charge in other operations and maintenance expense to reduce Dresden’s carrying amount to its estimated fair value based on AEP Generating Company’s purchase price.
Sale of Certain DCI Operations
In May 2007, Dominion committed to a plan to dispose of certain DCI operations including substantially all of the assets of Gichner, LLC, all of the issued and outstanding shares of the capital stock of Gichner, Inc. (an affiliate of Gichner, LLC), as well as all of the membership interests in Dallastown.
The consideration to be received indicated that the goodwill associated with these operations was impaired and Dominion recorded a goodwill impairment charge of $8 million in other operations and maintenance expense in the Consolidated Statement of Income. In August 2007, Dominion completed the sale of Gichner, LLC and Dallastown for approximately $30 million. The sale resulted in an after-tax loss of $4 million, which included $10 million of goodwill.
For the year ended December 31, 2007, operating revenue and loss before income taxes for Gichner, LLC and Dallastown were $29 million and $7 million, respectively, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income.
Sale of Merchant Generation Facilities
In 2007, Dominion sold three Peaker facilities for net cash proceeds of $254 million. The sale resulted in a $24 million after-tax loss ($0.03 per share). The Peaker facilities included:
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For the year ended December 31, 2007, operating revenue and loss before income taxes for the Peaker facilities were $5 million and $31 million, respectively, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income.
Sale of Peoples
On March 1, 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 the agreement for the sale of Peoples and Hope, primarily due to the continued delay in achieving final regulatory approval. 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. Dominion expects to recognize an after-tax loss of approximately $140 million (including $79 million of goodwill), as well as after-tax expenses of approximately $50 million, including transaction and benefit-related costs, in connection with the sale of Peoples.
The carrying amounts of the major classes of assets and liabilities classified as held for sale in Dominion’s Consolidated Balance Sheets arewere as follows:
At December 31, | 2009 | 2008 | ||||||
(millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Customer receivables | $ | 87 | $ | 172 | ||||
Other | 56 | 142 | ||||||
Total current assets | 143 | 314 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 985 | 1,204 | ||||||
Accumulated depreciation, depletion and amortization | (284 | ) | (358 | ) | ||||
Total property, plant and equipment, net | 701 | 846 | ||||||
Deferred Charges and Other Assets | ||||||||
Regulatory assets | 125 | 156 | ||||||
Other | 49 | 100 | ||||||
Total deferred charges and other assets | 174 | 256 | ||||||
Assets held for sale | $ | 1,018 | $ | 1,416 | ||||
LIABILITIES | ||||||||
Current Liabilities | $ | 133 | $ | 192 | ||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes and investment tax credits | 238 | 289 | ||||||
Other | 57 | 89 | ||||||
Total deferred credits and other liabilities | 295 | 378 | ||||||
Liabilities held for sale | $ | 428 | $ | 570 |
The results of operations of a component of an entity that has been disposed of or is classified as held for sale are required to be reported in discontinued operations if both of the following conditions are met: (a) the operations and cash flows of the components have been (or will be) eliminated from the ongoing operations of the entity as a result of the disposal transaction and (b) the entity will not have any significant continuing involvement in the operations of the component after the disposal transaction. While Dominion does not expect to have significant continuing involvement with Peoples after its disposal, it does
expect to have continuing cash flows related primarily to the sale to Peoples of natural gas production from Dominion’s Appalachian E&P operations, as well as natural gas transportation and storage services provided to Peoples by Dominion’s gas transmission operations. Due to these expected significant continuing cash flows, the results of Peoples have not been reported as discontinued operations in the Consolidated Statements of Income. Dominion will continue to assess the level of its involvement and continuing cash flows with Peoples for one year after the date of sale, and if circumstances change, Dominion may be required to reclassify the results of Peoples as discontinued operations in its Consolidated Statements of Income.
At December 31, | 2009 | |||
(millions) | ||||
ASSETS | ||||
Current Assets | ||||
Customer receivables | $ | 87 | ||
Other | 56 | |||
Total current assets | 143 | |||
Property, Plant and Equipment | ||||
Property, plant and equipment | 985 | |||
Accumulated depreciation, depletion and amortization | (284 | ) | ||
Total property, plant and equipment, net | 701 | |||
Deferred Charges and Other Assets | ||||
Regulatory assets | 125 | |||
Other | 49 | |||
Total deferred charges and other assets | 174 | |||
Assets held for sale | $ | 1,018 | ||
LIABILITIES | ||||
Current Liabilities | $ | 133 | ||
Deferred Credits and Other Liabilities | ||||
Deferred income taxes and investment tax credits | 238 | |||
Other | 57 | |||
Total deferred credits and other liabilities | 295 | |||
Liabilities held for sale | $ | 428 |
The following table presents selected information regarding the results of operations of Peoples:Peoples, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income:
Year Ended December 31, | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||
(millions) | ||||||||||||||||||||||
Operating revenue | $ | 432 | $ | 535 | $ | 470 | $ | 67 | $ | 432 | $ | 535 | ||||||||||
Income (loss) before income taxes(1) | 46 | 118 | 71 | (134 | )(2) | 42 | 119 | |||||||||||||||
(1) | The year ended December 31, 2008 includes a $47 million benefit related to the re-establishment of certain regulatory assets expected to be recovered through future rates under the terms of the sale agreement. The year ended December 31, 2009 includes the impact of a $22 million charge due to a reduction of the previously established regulatory asset. |
(2) | Includes a loss and other charges related to the sale of Peoples. |
NOTE 5. OPERATING REVENUE
Dominion’s and Virginia Power’s operating revenue consists of the following:
Year Ended December 31, | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | |||||||||||||||
(millions) | |||||||||||||||||||||
Dominion | |||||||||||||||||||||
Electric sales: | |||||||||||||||||||||
Regulated | $ | 6,477 | $ | 6,797 | $ | 6,044 | $ | 7,123 | $ | 6,477 | $ | 6,797 | |||||||||
Nonregulated | 3,802 | 3,543 | 2,873 | 3,829 | 3,802 | 3,543 | |||||||||||||||
Gas sales: | |||||||||||||||||||||
Regulated | 829 | 1,307 | 1,174 | 308 | 494 | 877 | |||||||||||||||
Nonregulated | 2,259 | 3,020 | 2,878 | 2,010 | 2,315 | 3,114 | |||||||||||||||
Gas transportation and storage | 1,328 | 1,134 | 1,031 | 1,493 | 1,268 | 1,072 | |||||||||||||||
Other | 436 | 489 | 816 | 434 | 442 | 492 | |||||||||||||||
Total operating revenue | $ | 15,131 | $ | 16,290 | $ | 14,816 | $ | 15,197 | $ | 14,798 | $ | 15,895 | |||||||||
Virginia Power | |||||||||||||||||||||
Regulated electric sales | $ | 6,477 | $ | 6,797 | $ | 6,044 | $ | 7,123 | $ | 6,477 | $ | 6,797 | |||||||||
Other | 107 | 137 | 137 | 96 | 107 | 137 | |||||||||||||||
Total operating revenue | $ | 6,584 | $ | 6,934 | $ | 6,181 | $ | 7,219 | $ | 6,584 | $ | 6,934 |
NOTE 6. 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. Dominion and Virginia Power are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.
The American RecoveryIn 2010, U.S. federal legislation was enacted that allows taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of 2011, when placed in service before 2013, and Reinvestment Actotherwise provides an extension of 2009 includes provisionsthe fifty percent bonus depreciation allowance for qualifying capital expenditures through 2012. However, there is uncertainty about the earliest date on which construction of property by or for a taxpayer could have begun in order to stimulate economic growth, includingqualify for the full deduction of qualifying capital expenditures. Clarifying guidance is expected from the U.S. Treasury Department in 2011. For Dominion and Virginia Power, income taxes payable have been reduced and deferred tax liabilities have increased in 2010 as a result of claiming these benefits.
76 |
Combined Notes to Consolidated Financial Statements, Continued
incentives for increased capital investment by businesses and incentives to promote renewable energy. Under the act, Dominion and Virginia Power have claimed bonus tax depreciation in 2009 for qualifying expenditures, which reduced their income taxes payable and increased deferred tax liabilities.Continuing Operations
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
Dominion | Virginia Power | Dominion | Virginia Power | |||||||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||||||||||
Current: | ||||||||||||||||||||||||||||||||||||||||||||||||
Federal | $ | 971 | $ | 494 | $ | 2,875 | $ | 465 | $ | 158 | $ | 152 | $ | 891 | $ | 952 | $ | 502 | $ | (78 | ) | $ | 465 | $ | 158 | |||||||||||||||||||||||
State | 135 | 116 | 217 | 91 | 37 | (37 | ) | 308 | 129 | 115 | 10 | 91 | 37 | |||||||||||||||||||||||||||||||||||
Total current | 1,106 | 610 | 3,092 | 556 | 195 | 115 | 1,199 | 1,081 | 617 | (68 | ) | 556 | 195 | |||||||||||||||||||||||||||||||||||
Deferred: | ||||||||||||||||||||||||||||||||||||||||||||||||
Federal | (429 | ) | 281 | (1,283 | ) | (339 | ) | 279 | 163 | 764 | (424 | ) | 338 | 537 | (339 | ) | 279 | |||||||||||||||||||||||||||||||
State | (63 | ) | (7 | ) | (15 | ) | (69 | ) | 30 | 103 | 96 | (59 | ) | 3 | 74 | (69 | ) | 30 | ||||||||||||||||||||||||||||||
Total deferred | (492 | ) | 274 | (1,298 | ) | (408 | ) | 309 | 266 | 860 | (483 | ) | 341 | 611 | (408 | ) | 309 | |||||||||||||||||||||||||||||||
Amortization of deferred investment tax credits | (2 | ) | (5 | ) | (11 | ) | (1 | ) | (4 | ) | (10 | ) | (2 | ) | (2 | ) | (5 | ) | (1 | ) | (1 | ) | (4 | ) | ||||||||||||||||||||||||
Total income tax expense | $ | 612 | $ | 879 | $ | 1,783 | $ | 147 | $ | 500 | $ | 371 | $ | 2,057 | $ | 596 | $ | 953 | $ | 542 | $ | 147 | $ | 500 |
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to Dominion’s and Virginia Power’s effective income tax rate as follows:
Dominion | Virginia Power | Dominion | Virginia Power | |||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | ||||||||||||||||||||||||||||||
U.S. statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||||||||||||
Increases (reductions) resulting from: | ||||||||||||||||||||||||||||||||||||||||||
Goodwill—sale of U.S. non-Appalachian E&P business | — | — | 5.6 | — | — | — | ||||||||||||||||||||||||||||||||||||
Reversal of deferred taxes—stock of subsidiaries held for sale | — | (5.0 | ) | (0.2 | ) | — | — | — | ||||||||||||||||||||||||||||||||||
Goodwill—sale of U.S. Appalachian E&P business | 0.9 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Legislative change | 1.1 | 0.4 | (0.1 | ) | 1.1 | — | (0.4 | ) | ||||||||||||||||||||||||||||||||||
State taxes, net of federal benefit | 2.9 | 2.7 | 3.1 | 2.8 | 3.2 | 4.4 | 5.0 | 2.4 | 2.5 | 3.8 | 2.8 | 3.6 | ||||||||||||||||||||||||||||||
Valuation allowances | (0.4 | ) | 0.4 | (2.8 | ) | — | — | — | 0.1 | (0.4 | ) | 0.5 | — | — | — | |||||||||||||||||||||||||||
Domestic production activities deduction | (2.9 | ) | (0.5 | ) | (0.5 | ) | (4.5 | ) | (0.5 | ) | (0.2 | ) | (0.4 | ) | (2.9 | ) | (0.5 | ) | (0.3 | ) | (4.5 | ) | (0.5 | ) | ||||||||||||||||||
Investment and production tax credits | (1.4 | ) | (0.1 | ) | — | (0.2 | ) | (0.1 | ) | (0.1 | ) | (0.3 | ) | (1.5 | ) | (0.1 | ) | — | (0.2 | ) | (0.1 | ) | ||||||||||||||||||||
Amortization of investment tax credits | (0.1 | ) | (0.2 | ) | (0.2 | ) | (0.2 | ) | (0.3 | ) | (0.8 | ) | — | (0.1 | ) | (0.2 | ) | (0.1 | ) | (0.2 | ) | (0.3 | ) | |||||||||||||||||||
AFUDC – equity | (1.0 | ) | (0.3 | ) | (0.1 | ) | (3.4 | ) | (0.5 | ) | (0.5 | ) | (0.4 | ) | (1.0 | ) | (0.3 | ) | (1.1 | ) | (3.4 | ) | (0.5 | ) | ||||||||||||||||||
Employee stock ownership plan deduction | (0.8 | ) | (0.5 | ) | (0.3 | ) | — | — | — | (0.3 | ) | (0.8 | ) | (0.5 | ) | — | — | — | ||||||||||||||||||||||||
Pension and other benefits | (0.5 | ) | (0.3 | ) | (0.2 | ) | (0.6 | ) | (0.2 | ) | (0.3 | ) | — | (0.6 | ) | (0.3 | ) | — | (0.6 | ) | (0.2 | ) | ||||||||||||||||||||
Other, net | 1.1 | 1.0 | 0.1 | 0.4 | 0.1 | 0.5 | 0.1 | 1.3 | 0.5 | 0.5 | 0.4 | 0.1 | ||||||||||||||||||||||||||||||
Effective tax rate | 31.9 | % | 32.2 | % | 39.5 | % | 29.3 | % | 36.7 | % | 38.0 | % | 40.8 | % | 31.8 | % | 36.5 | % | 38.9 | % | 29.3 | % | 36.7 | % |
Dominion’s and Virginia Power’s effective tax rates in 2010 reflect reductions of deferred tax assets of $57 million and $17 million, respectively, resulting from the enactment of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act of 2010, which eliminated the employer’s deduction, beginning in 2013, for that portion of its retiree prescription drug coverage cost that is being reimbursed by the Medicare Part D subsidy. In 2008,addition, Dominion’s effective tax rate reflected the reversal of $136 million of deferred tax liabilities recognized in 2006, associated with the excess of its financial reporting basis over the tax basis in the stock of Peoples2010 includes higher state income taxes and Hope. In 2006, based on the intended form of the sale of Peoples and Hope to Equitable, Dominion recognized these deferred tax liabilities since the
difference between the financial reporting basis and its tax basis in the stock of the subsidiaries was expected to reverse upon closing of the sale. In January 2008, Dominion and Equitable agreed to terminate the agreement for the sale of Peoples and Hope. At that time, based on its expectation that the form of any future disposal of these subsidiaries would be structured so that the taxable gain would instead be determined by reference to the basis in the subsidiaries’ underlying assets, Dominion reversed the related deferred tax liabilities recognized in 2006. As discussed in Note 4, Dominion executed a new agreement in July 2008 to sell Peoples and Hope, but decided in December 2009 to sell only Peoples. Dominion will determine its taxable gain by reference to the basis in the subsidiary’s underlying assets.
In 2007, Dominion’s effective tax rate reflected the effects of the sale of its U.S. non-Appalachian E&P operations, including the impact of goodwill written off that is not deductible for tax purposes that reducedassociated with the book gain on sale. In addition, Dominion recognizedsale of the Appalachian E&P operations.
Dominion’s and Virginia Power’s effective tax rates in 2009 reflect the reduction of uncertainties regarding the calculation of the domestic production activities deduction as a tax benefit from eliminating $126 millionresult of valuation allowances on deferred tax assets that relateworking with the IRS under its Pre-Filing Program. The objective of the Pre-Filing Program is to federal and state loss carryforwards, which have been utilized to partially offset taxes otherwise payable onprovide taxpayers with greater certainty regarding a specific issue at an earlier point in time than can be attained under the gain from the sale.normal post-filing examination process.
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amountamounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
The Companies’ deferred income taxes consist of the following:
Dominion | Virginia Power | Dominion | Virginia Power | |||||||||||||||||||||||||||||
At December 31, | 2009 | 2008 | 2009 | 2008 | 2010 | 2009 | 2010 | 2009 | ||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Deferred income taxes: | ||||||||||||||||||||||||||||||||
Total deferred income tax assets | $ | 1,839 | $ | 1,746 | $ | 533 | $ | 394 | $ | 1,642 | $ | 1,839 | $ | 402 | $ | 533 | ||||||||||||||||
Total deferred income tax liabilities | 5,683 | 6,055 | 2,652 | 2,875 | 6,233 | 5,683 | 3,139 | 2,652 | ||||||||||||||||||||||||
Total net deferred income tax liabilities | $ | 3,844 | $ | 4,309 | $ | 2,119 | $ | 2,481 | $ | 4,591 | $ | 3,844 | $ | 2,737 | $ | 2,119 | ||||||||||||||||
Total deferred income taxes: | ||||||||||||||||||||||||||||||||
Depreciation method and plant basis differences | $ | 3,221 | $ | 2,861 | $ | 2,241 | $ | 2,087 | ||||||||||||||||||||||||
Gas and oil E&P related differences | 345 | 413 | — | — | ||||||||||||||||||||||||||||
Plant and equipment, primarily depreciation method and basis differences | $ | 3,027 | $ | 2,877 | $ | 2,109 | $ | 1,934 | ||||||||||||||||||||||||
Nuclear decommissioning | 749 | 689 | 343 | 307 | ||||||||||||||||||||||||||||
Deferred state income taxes | 416 | 488 | 152 | 214 | 446 | 416 | 228 | 152 | ||||||||||||||||||||||||
Deferred fuel, purchased energy and gas costs | 12 | 355 | 7 | 313 | 120 | 12 | 111 | 7 | ||||||||||||||||||||||||
Pension benefits | 351 | 262 | (49 | ) | (34 | ) | 521 | 351 | 26 | (49 | ) | |||||||||||||||||||||
Other postretirement benefits | (216 | ) | (308 | ) | (29 | ) | (25 | ) | (186 | ) | (216 | ) | (14 | ) | (29 | ) | ||||||||||||||||
Loss and credit carryforwards | (192 | ) | (235 | ) | — | — | (181 | ) | (192 | ) | — | — | ||||||||||||||||||||
Reserve for proposed rate settlement | (179 | ) | — | (179 | ) | — | ||||||||||||||||||||||||||
Reserve for rate proceedings | (56 | ) | (179 | ) | (56 | ) | (179 | ) | ||||||||||||||||||||||||
Partnership basis differences | 236 | 157 | — | — | 265 | 236 | — | — | ||||||||||||||||||||||||
Valuation allowances | 62 | 78 | — | — | 68 | 62 | — | — | ||||||||||||||||||||||||
Other | (212 | ) | 238 | (24 | ) | (74 | ) | (182 | ) | (212 | ) | (10 | ) | (24 | ) | |||||||||||||||||
Total net deferred income tax liabilities | $ | 3,844 | $ | 4,309 | $ | 2,119 | $ | 2,481 | $ | 4,591 | $ | 3,844 | $ | 2,737 | $ | 2,119 |
At December 31, 2009,2010, Dominion had the following loss and credit carryforwards:
Ÿ | Federal loss carryforwards of $38 million that expire if unutilized during the period 2014 through |
Ÿ | State loss carryforwards of |
Ÿ | State minimum tax credits of |
There were no loss or credit carryforwards for Virginia Power at December 31, 2009.2010.
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. The amount of tax return positions that are not recognized in the financial statements is disclosed as unrecognized tax benefits. These unrecognized tax benefits may impact the
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Combined Notes to Consolidated Financial Statements, Continued
financial statements by increasing income taxes payable, reducing tax refunds receivable or changing deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities.
A reconciliation of changes in the Companies’ unrecognized tax benefits follows:
Dominion | Virginia Power | Dominion | Virginia Power | |||||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||||||||||
Balance at January 1 | $ | 404 | $ | 407 | $ | 625 | $ | 180 | $ | 195 | $ | 225 | $ | 291 | $ | 404 | $ | 407 | $ | 121 | $ | 180 | $ | 195 | ||||||||||||||||||||||||
Increases—prior period positions | 51 | 42 | 64 | 11 | 20 | 20 | 34 | 51 | 42 | 4 | 11 | 20 | ||||||||||||||||||||||||||||||||||||
Decreases—prior period positions | (142 | ) | (54 | ) | (40 | ) | (71 | ) | (22 | ) | (36 | ) | (59 | ) | (142 | ) | (54 | ) | (28 | ) | (71 | ) | (22 | ) | ||||||||||||||||||||||||
Current period positions | 43 | 63 | 70 | 22 | 20 | 15 | 61 | 43 | 63 | 25 | 22 | 20 | ||||||||||||||||||||||||||||||||||||
Prior period positions becoming otherwise deductible in current period | (36 | ) | (21 | ) | (252 | ) | (9 | ) | (11 | ) | (13 | ) | (16 | ) | (36 | ) | (21 | ) | (5 | ) | (9 | ) | (11 | ) | ||||||||||||||||||||||||
Settlements with tax authorities | (13 | ) | (33 | ) | (60 | ) | (9 | ) | (22 | ) | (16 | ) | — | (13 | ) | (33 | ) | — | (9 | ) | (22 | ) | ||||||||||||||||||||||||||
Expiration of statute of limitations | (16 | ) | — | — | (3 | ) | — | — | ||||||||||||||||||||||||||||||||||||||||
Expiration of statutes of limitation | (4 | ) | (16 | ) | — | — | (3 | ) | — | |||||||||||||||||||||||||||||||||||||||
Balance at December 31 | $ | 291 | $ | 404 | $ | 407 | $ | 121 | $ | 180 | $ | 195 | $ | 307 | $ | 291 | $ | 404 | $ | 117 | $ | 121 | $ | 180 |
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits resultedmay result from claims for tax benefits, or portions thereof, that may not be realized, remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutestatutes of limitations.limitation. For Dominion and its subsidiaries, these unrecognized tax benefits were $133 million, $95 million $121 million and $101$121 million at December 31, 2010, 2009 2008 and 2007,2008, respectively. For Dominion, the change in these unrecognized tax benefits increased income tax expense by $38 million in 2010, decreased income tax expense by $26 million in 2009 and increased tax expense by $25 million in both 2008 and 2007.2008. For Virginia Power, these unrecognized tax benefits were $14 million, $21$14 million and $8$21 million at December 31, 2010, 2009 2008 and 2007,2008, respectively. For Virginia Power, the change in these unrecognized tax benefits increased income tax expense by less than $1 million in 2010, decreased income tax expense by $7 million in 2009 and increased income tax expense by $13 million and $3 million in 2008 and 2007, respectively.2008.
However, for the majorityA substantial amount of Dominion’s and Virginia Power’s unrecognized tax benefits balances at December 31, 2010 represents tax positions for which the ultimate deductibility is highly certain, butcertain; however, there is uncertainty about the timing of such deductibility. When uncertainty about the deductibility of amounts is limited to the timing of such deductibility, any tax liabilities recognized for prior periods would be subject to offset with the availability of refundable amounts from later periods when such deductions could otherwise be taken. Some prior year unrecognized tax benefits had involved uncertainty as to whether the amounts were deductible as ordinary deductions or capital losses. However, with the realization of gains from the non-Appalachian E&P sales, these prior year amounts would have become fully deductible for federal income tax purposes in 2007. Pending resolution of these uncertainties, interest is being accrued until the period in which the amounts would become deductible.
For Dominion and its subsidiaries, the U.S. federal statute of limitations has expired for years prior to 2002,2004, except that the right to pursue refunds related to certain deductions has been reserved for the years 1995 through 2001.2003.
In 2010, the IRS began its examination of Dominion’s consolidated tax returns for tax years 2006 and 2007, and Dominion began settlement negotiations with the Appellate Division of the IRS regarding adjustments proposed in the examination of its consolidated tax returns for 2004 and 2005. Other than two tax positions for which Dominion will reserve the right to litigate and pursue claims for refunds, Dominion and the IRS have agreed on the resolution of the issues for 2004 and 2005. The settlement is subject to review by the Joint Committee.
In September 2010, the Appellate Division of the IRS informed Dominion that the Joint Committee had approved the settlement of tax years 2002 and 2003 for Dominion and its consolidated subsidiaries. Dominion received a refund of $54 million in November 2010. The settlement excludes two issues, for which Dominion has reserved the right to litigate and pursue claims for refunds.
In 2009, the U.S. Congressional Joint Committee on Taxation completed its review of Dominion’s settlement with the Appellate Division of the IRS for tax years 1999 through 2001. Dominion was entitled to a $60 million refund, of which $20 million was applied as an estimated payment for 2009 taxes and $40 million was paid to Dominion in October 2009. In addition, Dominion received a $5 million refund for 1998 due to loss carryback adjustments. Virginia Power was entitled to a $39 million refund, of which $20 million was applied as an estimated payment for 2009 taxes and $19 million was paid to Virginia Power in October 2009. The refunds had no impact on earnings.
In 2007, the IRS completed its examination of Dominion’s 2002 and 2003 consolidated returns and the 2002 and 2003 returns of certain affiliated partnerships. Dominion filed protests for certain proposed adjustments with the Appellate Division of the IRS in July and October 2007, and is currently engaged in settlement negotiations regarding those adjustments. In addition, the IRS completed its audit of tax years 2004 and 2005 in June 2009. Dominion filed protests for certain proposed adjustments with the Appellate Division of the IRS in July 2009.
With Dominion’s appeals of assessments received fromDuring examinations by tax authorities including amounts subject to settlement negotiations with the Appellate Division of the IRS,in 2011, it is reasonably possible that Dominion and tax authorities could agree to apply procedures used previously to resolve similar tax return filing positions, reducing Dominion’s unrecognized tax benefits by $50 million to $70 million and Virginia Power’s unrecognized tax benefits by $30 million to $35 million. Dominion’s unrecognized tax benefits could decrease in 2010also be reduced by up to $30$15 million, including a decrease of up to $25 million for Virginia Power. In addition, Dominion’s unrecognized tax benefits could be reduced during 2010 by $18 million, including $6$5 million for Virginia Power, to recognize prior period amounts becoming otherwise deductible in the current period. Since the uncertainty for the majority of these unrecognized tax benefits involves only the timing of the deductions, Dominion anticipates that the impact on earnings will be limited2011. If such changes were to occur, other than revisions of itsthe accrual for interest on tax underpayments and overpayments.overpayments, Dominion’s earnings could increase by up to $25 million with no material impact on Virginia Power’s earnings.
Otherwise, with regard to tax2010 and prior years, 2004 through 2009, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2010.2011.
Combined Notes to Consolidated Financial Statements, Continued
For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows:
State | Earliest Open Tax Year | |||
Pennsylvania | ||||
Connecticut | ||||
Massachusetts | ||||
Virginia(1) | ||||
West Virginia |
(1) | Virginia is the only state considered major for Virginia Power’s operations. |
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Dominion and Virginia Power are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion utilizes state net operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are subject to examination.
Discontinued Operations
Income tax expense in 2010 for Dominion’s discontinued operations primarily reflects the impact of goodwill written off in the sale of Peoples that is not deductible for tax purposes and the reversal of deferred taxes for which the benefit was offset by the reversal of income tax-related regulatory assets.
Income tax expense in 2008 for Dominion’s discontinued operations reflects the reversal of $120 million of deferred tax liabilities recognized in 2006, associated with the excess of its financial reporting basis over the tax basis in the stock of Peoples. In 2006, based on the terms of a previous agreement to sell Peoples, Dominion recognized these deferred tax liabilities since the difference between the financial reporting basis and its tax basis in the stock of the subsidiaries was expected to reverse upon closing of the sale. In January 2008, Dominion agreed to terminate the agreement for the sale of Peoples and Hope. At that time, based on its expectation that the form of any future disposal of these subsidiaries would be structured so that the taxable gain would instead be determined by reference to the basis in the subsidiaries’ underlying assets, Dominion reversed the related deferred tax liabilities recognized in 2006. Dominion executed a new agreement in July 2008 to sell Peoples and Hope, but decided in December 2009 to sell only Peoples. Dominion determined its taxable gain by reference to the basis in the subsidiary’s underlying assets.
NOTE 7. FAIR VALUE MEASUREMENTS
As described in Note 3, Dominion and Virginia Power adopted new FASB guidance for fair value measurements effective January 1, 2008. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of Dominion’s and Virginia Power’s own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion and Virginia Power apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, and nuclear decommissioning trust and other investments including those held in Dominion’s rabbi, pension
and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above. These credit adjustments are currently not material to the derivative fair values.
The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, they seek price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, they consider whether the broker is willing and able to trade at the
quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases they must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect their market assumptions.
For options and contracts with option-like characteristics where observable pricing information is not available from external sources, the Companies generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. The Companies use other option models under special circumstances, including a Spread Approximation Model when contracts include different commodities or commodity locations and a Swing Option Model when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.
The inputs and assumptions used in measuring fair value include the following:
For commodity and foreign currency derivative contracts:
Ÿ | Forward commodity prices |
Ÿ | Forward foreign currency prices |
Ÿ | Price volatility |
Ÿ | Volumes |
Ÿ | Commodity location |
Ÿ | Interest rates |
Ÿ | Credit quality of counterparties and Dominion and Virginia Power |
Ÿ | Credit enhancements |
Ÿ | Time value |
For interest rate derivative contracts:
Ÿ | Interest rate curves |
Ÿ | Credit quality of counterparties and Dominion and Virginia Power |
Ÿ | Credit enhancements |
Ÿ | Time value |
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Combined Notes to Consolidated Financial Statements, Continued
For investments:
Ÿ | Quoted securities prices |
Ÿ | Securities trading information including volume and restrictions |
Ÿ | Maturity |
Ÿ | Interest rates |
Ÿ | Credit quality |
Ÿ | NAV (only for alternative investments) |
Dominion and Virginia Power regularly evaluate and validate the inputs used to estimate fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities and investments in which the Companies transact.
The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value, into three broad levels:
Level 1— Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as the majority of exchange-traded derivatives, and exchange-listed equities, mutual funds and Treasury securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion.
Level 2— Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps, interest rate swaps, foreign currency forwards and options, and commingled funds and corporate, state and municipal debt securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion.
Ÿ | Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as the majority of exchange-traded derivatives, and exchange-listed equities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion. |
Ÿ | Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps, interest rate swaps, foreign currency forwards and options, certain Treasury securities, money market funds, and corporate, state and municipal debt securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion. |