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, 20102012
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 ifwhether the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.
Dominion Resources, Inc. Yes x No ¨ Virginia Electric and Power Company Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Dominion Resources, Inc. Yes ¨ No x Virginia Electric and Power Company Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Dominion Resources, Inc. Yes x No ¨ Virginia Electric and Power Company Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Dominion Resources, Inc. Yes x No ¨ Virginia Electric and Power Company Yes ¨x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Dominion Resources, Inc. ¨x Virginia Electric and Power Company x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Dominion Resources, Inc.
Large accelerated filer x | Accelerated filer ¨ | Non-accelerated filer ¨ | Smaller reporting company ¨ |
Virginia Electric and Power Company
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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.
Virginia Electric and Power Company
Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer x | Smaller reporting company ¨ | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).
Dominion Resources, Inc. Yes ¨ No x Virginia Electric and Power Company Yes ¨ No x
The aggregate market value of Dominion Resources, Inc. common stock held by non-affiliates of Dominion was approximately $30.0 billion based on the closing price of Dominion’s common stock as reported on the New York Stock Exchange as of the last day of Dominion’s most recently completed second fiscal quarter. Dominion is the sole holder of Virginia Electric and Power Company common stock. As of January 31, 2013, Dominion had 576,309,631 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding.
DOCUMENT INCORPORATED BY REFERENCE.
Portions of Dominion’s 2013 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.
Virginia Electric and Power Company
Item Number |
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1 | 1 | |||||||||||
1. | 5 | 5 | ||||||||||
1A. | 22 | 20 | ||||||||||
1B. | 26 | 24 | ||||||||||
2. | 26 | 24 | ||||||||||
3. | 29 | 27 | ||||||||||
4. | 29 | 27 | ||||||||||
30 | 28 | |||||||||||
5. | 31 | 29 | ||||||||||
6. | 32 | 30 | ||||||||||
7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 33 | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 31 | ||||||||
7A. | 50 | 50 | ||||||||||
8. | 53 | 52 | ||||||||||
9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 124 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 124 | ||||||||
9A. | 124 | 124 | ||||||||||
9B. | 127 | 127 | ||||||||||
10. | 127 | 127 | ||||||||||
11. | 128 | 128 | ||||||||||
12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 150 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 151 | ||||||||
13. | Certain Relationships and Related Transactions, and Director Independence | 150 | Certain Relationships and Related Transactions, and Director Independence | 151 | ||||||||
14. | 151 | 152 | ||||||||||
15. | 152 | 153 |
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 | |
2013 Proxy Statement | Dominion 2013 Proxy Statement, File No. 001-08489 | |
ABO | Accumulated benefit obligation | |
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AFUDC | Allowance for funds used during construction | |
AIP | Annual Incentive Plan | |
AMI | Advanced Metering Infrastructure | |
AMR | Automated meter reading program deployed by East Ohio | |
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AROs | Asset retirement obligations | |
ARP | Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the CAA | |
ASA |
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ASLB | Atomic Safety and Licensing Board | |
ATEX line | Appalachia to Texas Express ethane line | |
bcf | Billion cubic feet | |
Bear Garden | A | |
Biennial Review Order | Order issued by the Virginia Commission in November 2011 concluding the 2009 - 2010 biennial review of Virginia Power’s base rates, terms and conditions | |
Blue Racer | Blue Racer Midstream, LLC | |
BOEM | Bureau of Ocean Energy Management | |
BP | BP Wind Energy North America Inc. | |
Brayton Point | Brayton Point power station | |
BREDL | Blue Ridge Environmental Defense League | |
Bremo | Bremo power station | |
BRP | Dominion Retirement Benefit Restoration Plan | |
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CAA | Clean Air Act | |
Caiman | Caiman Energy II, LLC | |
CAIR | Clean Air Interstate | |
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CAO | Chief Accounting Officer | |
Carson-to-Suffolk line | Virginia Power | |
CD&A | Compensation Discussion and Analysis | |
CDO | Collateralized debt obligation | |
CEO | Chief Executive Officer | |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act of 1980 | |
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CFTC | Commodity Futures Trading Commission | |
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CGN Committee | Compensation, Governance and Nominating Committee of Dominion’s Board of Directors | |
Chesapeake | Chesapeake power station | |
CNG | Consolidated Natural Gas Company | |
CNO | Chief Nuclear Officer | |
CO2 | Carbon dioxide | |
COL | Combined Construction Permit and Operating License | |
Companies | Dominion and Virginia Power, collectively | |
CONSOL | CONSOL Energy, Inc. | |
COO | Chief Operating Officer | |
Cooling degree days | Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day | |
Cove Point | Dominion Cove Point LNG, LP | |
CSAPR | Cross State Air Pollution Rule | |
CWA | Clean Water Act | |
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DCI | Dominion Capital, Inc. | |
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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 |
1 |
Glossary of Terms, continued
Abbreviation or Acronym | Definition | |
Dominion Direct® | A dividend reinvestment and open enrollment direct stock purchase plan | |
Dooms-to-Bremo line | Virginia Power project to rebuild approximately 43 miles of existing 115 kV to 230 kV lines, between the Dooms and Bremo substations | |
Dooms-to-Lexington line | Virginia Power project to rebuild approximately 39 miles of an existing 500 kV line, between the Dooms and Lexington substations | |
DPP |
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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 | |
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Elwood | Elwood power station | |||
Enterprise |
Glossary of Terms, continued
Enterprise Product Partners, L.P.
EPA | Environmental Protection Agency | |
EPACT | Energy Policy Act of 2005 | |
EPS | Earnings per share | |
ERISA | The Employment Retirement Income Security Act of 1974 | |
ERM | Enterprise Risk Management | |
ERO | Electric Reliability Organization | |
ESRP | Dominion Executive Supplemental Retirement Plan | |
Excess Tax Benefits | Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation | |
Fairless | Fairless power station | |
FASB | Financial Accounting Standards Board | |
FCM | Futures Commission Merchant | |
FERC | Federal Energy Regulatory Commission | |
Fitch | Fitch Ratings Ltd. | |
Fowler Ridge | A wind-turbine facility joint venture with BP in Benton County, Indiana | |
Frozen Deferred Compensation Plan | Dominion Resources, Inc. Executives’ Deferred Compensation Plan | |
Frozen DSOP | Dominion Resources, Inc. Security Option Plan | |
FTRs | Financial transmission rights | |
GAAP | U.S. generally accepted accounting principles | |
GHG | Greenhouse gas | |
GWSA | Global Warming Solutions Act | |
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Hayes-to-Yorktown line | Virginia Power project to construct an approximately eight-mile | |
Heating degree days | Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day | |
Hope | Hope Gas, Inc., doing business as Dominion Hope | |
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IRS | Internal Revenue Service | |
ISO | Independent system operator | |
ISO-NE | ISO New England | |
Joint Committee | U.S. Congressional Joint Committee on Taxation | |
June 2006 hybrids | 2006 Series A Enhanced Junior Subordinated Notes due 2066 | |
June 2009 hybrids | 2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to extensions no later than 2079 | |
Juniper | Juniper Capital L.P. | |
Kewaunee | Kewaunee nuclear power station | |
Kincaid | Kincaid power station | |
kV | Kilovolt | |
kWh | Kilowatt-hour | |
LIBOR | London Interbank Offered Rate | |
LIFO | Last-in-first-out inventory method | |
LNG | Liquefied natural gas | |
LTIP | Long-term incentive program | |
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Manchester Street | Manchester Street power station |
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Abbreviation or Acronym | Definition | |
mcf | million cubic feet | |
MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
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Meadow Brook-to-Loudoun line |
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Medicare Act | The Medicare Prescription Drug, Improvement and Modernization Act of 2003 | |
Medicare Part D | Prescription drug benefit introduced in the Medicare Act | |
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MGD | Million gallons a day | |
Millstone | Millstone nuclear power station | |
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Moody’s | Moody’s Investors Service | |
Mt. Storm-to-Doubs line | Virginia Power project to rebuild approximately 96 miles of an existing | |
MW | Megawatt | |
MWh | Megawatt hour | |
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NAAQS | National Ambient Air Quality Standards | |
NAV | Net asset value | |
NCEMC | North Carolina Electric Membership Corporation | |
NedPower | A wind-turbine facility joint venture with Shell in Grant County, West Virginia | |
NEIL | Nuclear Electric Insurance Limited | |
NEOs | Named executive officers | |
NERC | North American Electric Reliability Corporation | |
NGLs | Natural gas liquids | |
NO2 | Nitrogen dioxide |
Non-Employee Directors Plan | Non-Employee Directors Compensation Plan | |
North Anna | North Anna nuclear power station | |
North Branch | North Branch power station | |
North Carolina Commission | North Carolina Utilities Commission | |
North Carolina Settlement Approval Order | Order issued by the North Carolina Commission in December 2010 approving the Stipulation and Settlement Agreement filed by Virginia Power in connection with the ending of its North Carolina base rate moratorium | |
NOX | Nitrogen oxide | |
NPDES | National Pollutant Discharge Elimination System | |
NRC | Nuclear Regulatory Commission | |
NSPS | New Source Performance Standards | |
NYMEX | New York Mercantile Exchange | |
NYSE | New York Stock Exchange | |
ODEC | Old Dominion Electric Cooperative | |
Ohio Commission | Public Utilities Commission of Ohio | |
OSHA | Occupational Safety and Health Administration | |
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Peoples | The Peoples Natural Gas Company | |
Pipeline Safety Act | The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 | |
PIPP | Percentage of Income Payment Plan | |
PIR | Pipeline Infrastructure Replacement program deployed by East Ohio | |
PJM | PJM Interconnection, LLC | |
PM&P | Pearl Meyer & Partners | |
PNG Companies LLC | An indirect subsidiary of | |
ppb | Parts-per-billion | |
Radnor Heights Project | Virginia Power project to construct three new 230 kV underground transmission lines totaling approximately 6 miles and the associated Radnor Heights substation in Arlington County, Virginia | |
RCCs | Replacement Capital Covenants | |
RCRA | Resource Conservation and Recovery Act | |
Regulation Act | Legislation effective July 1, 2007, that amended the Virginia Electric Utility Restructuring Act and fuel factor statute, which legislation is also known as the Virginia Electric Utility Regulation Act | |
REIT | Real estate investment trust | |
RGGI | Regional Greenhouse Gas Initiative | |
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Rider B | A rate adjustment clause associated with the recovery of costs related to |
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Abbreviation or Acronym | Definition | |
Rider BW | A rate adjustment clause associated with the recovery of costs related to Brunswick County | |
Rider R | A rate adjustment clause associated with the recovery of costs related to Bear Garden | |
Rider S | A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center | |
Rider T | A rate adjustment clause associated with the recovery of certain electric transmission-related expenditures | |
Rider T1 | A rate adjustment clause to recover the difference between revenues produced from current Rider T rates included in base rates, and the new revenue requirement developed for the rate year beginning September 1, 2012 | |
Rider W | A rate adjustment clause associated with the recovery of costs related to Warren County | |
Riders C1 and C2 | Rate adjustment clauses associated with the recovery of costs related to certain DSM programs | |
Riders C1A and C2A | Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in the 2011 DSM case | |
ROE | Return on equity | |
ROIC | Return on invested capital | |
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RPS | Renewable Portfolio Standard | |
RTEP | Regional transmission expansion plan | |
RTO | Regional transmission organization | |
SAFSTOR | A method of nuclear decommissioning, as defined by the NRC, in which a nuclear facility is placed and maintained in a condition that allows the facility to be safely stored and subsequently decontaminated to levels that permit release for unrestricted use | |
SAIDI |
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Salem Harbor | Salem Harbor power station | |
SEC | Securities and Exchange Commission | |
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September 2006 hybrids | 2006 Series B Enhanced Junior Subordinated Notes due 2066 | |
Shell | Shell WindEnergy, Inc. | |
SO2 | Sulfur dioxide | |
Standard & Poor’s | Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc. | |
State Line | State Line power station | |
Surry | Surry nuclear power station | |
Surry-to-Skiffes Creek-to-Whealton lines | Virginia Power project to construct a 7-mile 500 kV line from Surry to the proposed Skiffes Creek Switching Station and a 20-mile 230 kV line from the proposed Skiffes Creek Switching Station to the Whealton substation | |
TGP | Tennessee Gas Pipeline Company | |
TSR | Total shareholder return | |
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U.S. | United States of America | |
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UAO | Unilateral Administrative Order | |
UEX Rider | Uncollectible Expense Rider | |
VEBA | Voluntary Employees’ Beneficiary Association | |
VIE | Variable interest entity | |
Virginia City Hybrid Energy Center | A | |
Virginia Commission | Virginia State Corporation Commission |
Virginia Power | The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power and its consolidated subsidiaries | |
Virginia Settlement Approval Order | Order issued by the Virginia Commission in March 2010 concluding Virginia Power’s 2009 Base Rate Review | |
| A 1,329 MW combined-cycle, natural gas-fired power station under construction in Warren County, Virginia | |
Waxpool-Brambleton-BECO line | Virginia | |
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West Virginia Commission | Public Service Commission of West Virginia | |
Yorktown | Yorktown power station |
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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 27,61527,500 MW of generating capacity, 6,1006,300 miles of electric transmission lines, 56,80056,900 miles of electric distribution lines, 11,000 miles of natural gas transmission, gathering and storage pipeline and 21,800 miles of gas distribution pipeline, exclusive of service lines of two inches in diameter or less. Dominion also ownsoperates one of the nation’s largest underground natural gas storage system, operatessystems, with approximately 947 bcf of storage capacity, and serves nearly 6 million utility and retail energy customers in 1415 states.
Dominion is focused on expanding its investment in regulated electric generation, transmission and distribution and regulated natural gas transmission and distribution infrastructure within and around its existing footprint. As a result, regulated capital projects will continue to receive priority treatment in its spending plans. Dominion expects this will continue to 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 yearscontinues to expand and improve its regulated electric and natural gas businesses.businesses, in accordance with its five-year capital investment program. A substantial portion ofmajor impetus for this investment will be essentialprogram is to meet the anticipated increase in electricity demand in its electric utility service territory. Other drivers for the capital investment program include the need to constructconstruction of infrastructure to handle the expected increase in natural gas production from the Marcellus and Utica Shale formationformations; and upgrades to itsupgrade Dominion’s gas distribution and electric transmission and distribution network. Dominion also announced that it may invest upnetworks. Planned investments to an additional $2 billiongather and process natural gas production from the Utica Shale formation, in its electric generating fleeteastern Ohio and western Pennsylvania, are expected to meet potential new environmental requirements.be made by the newly-formed Blue Racer joint venture.
Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations. Dominion is in the process of transitioning to a more regulated earnings mix as evidenced by its capital investments in regulated infrastructure, as well as dispositions of certain merchant generation facilities during 2012 and its announcement that other merchant generation facilities are expected to be sold or decommissioned in 2013. Dominion’s operations are conducted through various subsidiaries, including Virginia Power.
Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina. In Virginia, Virginia Power conducts business under the name “Dominion Virginia Power.”Power” and primarily serves retail customers. In North Carolina, it conducts business under the name “Dominion North Carolina Power” and serves retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, Virginia Power sells electricity at wholesale prices to rural electric cooperatives, municipalities and into wholesale electricity markets. All of Virginia Power’s common stock is owned by Dominion.
Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.
EMPLOYEES
As of December 31, 2010,2012, Dominion had approximately 15,80015,500 full-time employees, of which approximately 5,9005,800 employees are subject to collective bargaining agreements. As of December 31, 2010,2012, Virginia Power had approximately 6,800 full-time employees, of which approximately 3,0003,100 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 divestitures by Dominion and Virginia Power during the last five years. There were no significant acquisitions by either registrant during this period.
SALEOF E&P PROPERTIES
In 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations, including its rights to associated Marcellus acreage, to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. See Note 43 to the Consolidated Financial Statements for additional information.
In 2007, Dominion completed the sale of its non-Appalachian natural gas and oil E&P operations and assets for approximately $13.9 billion.
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 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 43 to the Consolidated Financial Statements for additional information.
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ASSIGNMENTOF MARCELLUS ACREAGE
In 2008, Dominion completed a transaction with Antero Resources to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. Dominion received proceeds of approximately $347 million. Under the agreement, Dominion received a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. The overriding royalty interest was transferred to CONSOL as part of the sale of substantially all of Dominion’s Appalachian E&P operations in 2010.
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. The results of these operations were presented in discontinued operations.
SALEOF DRESDEN
In September 2007, Dominion completed the sale of Dresden to AEP Generating Company for $85 million.
SALEOFCERTAIN DCIDCI OPERATIONS
In March 2008, Dominion reached an agreement to sell its remaining interest in the subordinated notes of a third-party CDO entity held as an investment by DCI and in April 2008 received proceeds of $54 million, including accrued interest. As discussed in Note 25 to the Consolidated Financial Statements, Dominion deconsolidated the CDO entity as of March 31, 2008.
In August 2007, Dominion completed the sale of Gichner, LLC, all of the issued and outstanding shares of the capital stock of Gichner, Inc. (an affiliate of Gichner, LLC) and Dallastown for approximately $30 million.
OPERATING SEGMENTS
Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of Peoples and certain DCI operations that are expected to be or are currently discontinued, which areis discussed in Notes 4 and 25Note 3 to the Consolidated Financial Statements, respectively.Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit
measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by Dominion and Virginia Power and their respective legal subsidiaries.
A description of the operations included in the Companies’ primary operating segments is as follows:
Primary Operating Segment | Description of Operations | Dominion | Virginia Power | |||||||
DVP | Regulated electric distribution | X | X | |||||||
Regulated electric transmission | X | X | ||||||||
Nonregulated retail energy marketing (electric and gas) | X | |||||||||
Dominion Generation | Regulated electric fleet | X | X | |||||||
Merchant electric fleet | X | |||||||||
Dominion Energy | Gas transmission and storage | X | ||||||||
Gas distribution and storage | X | |||||||||
LNG import and storage | X | |||||||||
Producer services | X |
For additional financial information on operating segments, including revenues from external customers, see Note 2725 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 54 to the Consolidated Financial Statements.Statements, which information is incorporated herein by reference.
DVP
The DVP Operating Segment of Virginia Power includes Virginia Power’s regulated electric transmission and distribution (including customer service) operations, which serve approximately 2.5 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.
In December 2010, Virginia PowerDVP has announced its five-year investment plan, which includes spending approximately $4$4.5 billion from 2013 through 2017 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 populationcustomer growth and increases in electricity consumption by the typical consumer. In addition, data centers continue to contribute to anticipated demand growth, with an expected load of approximately 715 MW by the end of 2013.
Revenue provided by electric distribution operations is based primarily on rates established by state regulatory authorities and state law. ChangesVariability in revenue areearnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation. Variabilityconservation, in earnings results from changes in rates, weather, the economy, customer growth andaddition to operating and maintenance expenditures. Operationally, electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. As a result, electric
service reliability and customer service have improved. SAIDI, excluding major storm events, has also steadily improved. The three-year average SAIDI has improved from 135125 minutes at the end of 20052007 to 114105 minutes at the end of 2010.2012. Likewise, ASA has also shown significant improvement. The three-year average ASA has improved from 7357 seconds at the end of 20052007 to 4238 seconds at the end of 2010.2012. Customer service options are also beingcontinue to be enhanced and expanded through the use of technology. Customers now have the ability to use the Internet for routine billing and payment transactions, connecting and disconnecting service, reporting outages and obtaining outage updates. AsAdditionally, customers can follow progress of electric distribution moves forward,service restoration efforts following major outages by accessing Facebook or Twitter. In the future, safety, electric service reliability and customer service will remain key focal areas.areas for electric distribution.
Revenue provided by Virginia Power’s electric transmission operations is based primarily on rates approved by FERC. The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings primarily results from changes in rates and the timing of property additions, retirements and depreciation.
Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to NERC by EPACT, Virginia Power’s electric transmission operations are committed to meeting NERC standards, modernizing theirits infrastructure and maintaining superior system reliability. Virginia Power’s electric transmission operations will continue to focus on
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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 continued to experience customer growth during the past few years.markets. The retail business requires limited capital investment and currently employs approximately 160190 people. The retail customer base includes 2.1 million customer accounts and is diversified across three product lines—naturallines-natural gas, electricity and home warrantyenergy-related products and services. In natural gas, Dominion has a heavy concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice. In electricity, Dominion pursues customers in electricity markets where utilities have divested of generation assets and where customers are permitted and have opted to purchase from the market. Major growth drivers are net customer additions, new markets, productsmarket penetration, product development and expanded sales channels and supply optimization.
COMPETITION
DVP Operating Segment—Dominion and Virginia Power
Within Virginia Power’s service territory in Virginia and North Carolina, there is no competition for electric distribution service. Additionally, since its electric transmission facilities are integrated into PJM, electric transmission services are administered by PJM and are not subject to competition in relation to transmission service provided to customers within the PJM region. Virginia Power is seeing continued growth in new customers in its transmission and distribution operations. In its Order 1000 compliance filing, PJM has proposed tariff changes that, if approved by FERC, could allow certain transmission facilities to be constructed in Virginia Power’s service territory by entities other than Virginia Power beginning in 2013.
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 wholesale electric transmission rates, tariffs and terms of service are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. SeeState Regulations andFederal Regulations inRegulation and Note 13 to the Consolidated Financial Statements for additional information.
The Virginia General Assembly enacted legislation in April 2007 that institutedinformation, including 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.2011 Biennial Review Order.
PROPERTIES
Virginia Power has approximately 6,1006,300 miles of electric transmission lines of 69 kV or more located in the states of North Carolina, Virginia and West Virginia. Portions of Virginia Power’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.
Each year, as part of PJM’s RTEP process, reliability projects are authorized. In December 2012, Virginia Power is involved in twocompleted construction of the major construction projectsHayes-to-Yorktown line at a total project cost of $79 million. This previously authorized in 2006, which arePJM project was designed to improve the reliability of service to customers and the region—Meadow Brook-to-Loudoun and Carson-to-Suffolk.
In October 2008,region. Previously approved PJM-authorized reliability projects such as the Virginia Commission authorized construction ofWaxpool-Brambleton-BECO line ($49 million), the Meadow Brook-to-LoudounHarrisonburg-to-Endless Caverns line and affirmed($66 million) the 65-mile route proposed for the line which is adjacent to, or within, existing transmission line 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 2009Radnor Heights Project ($81 million), and the Pennsylvania Commission granted approval in December 2008. On appeal by the ECCP, the Pennsylvania Commonwealth Court affirmed in May 2010 the Pennsylvania Commission’s approvalDooms-to-Bremo line ($65 million) continue to progress and subsequently denied a request for reargument by the ECCP in June 2010. The Meadow
Brook-to-Loudoun line is expected to cost approximately $255 million and 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 isare expected to be completed in June 2011.on time.
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 the Hayes-to-Yorktown line along the proposed eight-mile route utilizing existing easements and property previously acquired for the transmission line 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 ($350 million) in December 2010 and certain associated facilities are approaching the end of their expected service lives and require replacement with new facilitiesSurry-to-Skiffes Creek-to-Whealton lines ($155 million) in 2012. Also approved as a reliability project in 2012 was the Dooms-to-Lexington line ($112 million). See Note 13 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 regulatory approvals, Virginia Power’s portion of the rebuild project is expected to cost approximately $300 million and is expected to be completed by June 2015.Consolidated Financial Statements for additional information regarding electric transmission projects.
In addition, Virginia Power’s electric distribution network includes approximately 56,80056,900 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent ownerowners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.
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. DVP’sThe supply of gas to serve itsDominion’s retail energy marketing 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, the impact of storms and other cata-
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strophic weather events, and the availability of alternative sources for heating on demand by residential and commercial customers.
Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree-daysdegree days for DVP’s electric utilityelectric-utility related operations does not produce the same increase in revenue as an increase in cooling degree-days,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. Revenue is based primarily on rates established by state regulatory authorities and state law. Approximately 80% of revenue comes from serving Virginia jurisdictional customers. Rates for the Virginia jurisdiction are set using a modified cost-of-service rate model, subject to base rate caps that were in effect through December 31, 2008.model. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. Variability in earnings for Virginia Power’s generation operations results from changes in rates, the demand for services, which is primarily weather dependent, and labor and benefit costs, as well as the timing, duration and costs of scheduled and unscheduled outages. SeeRegulation—State RegulationsElectric Regulation in Virginia underRegulation and Note 13 to the Consolidated Financial Statements for additional information, including a discussion of Virginia Power’s 2009 base rate case settlement with the Virginia Commission.information.
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. The Generation
operating segment of Dominion derives its earnings primarily from the sale of electricity generated by Virginia Power’s utility and Dominion’s merchant generation assets, as well as from associated capacity from Dominion’s merchant generation assets.and ancillary services.
Variability in earnings provided by Dominion’s merchant fleet relates to changes in market-based prices received for electricity and capacity. Market-based prices for electricity are largely dependent on commodity prices, primarily natural gas, and the demand for electricity, which is primarily dependent upon weather. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion manages electric and capacity price volatility of its merchant fleet by hedging a substantial portion of its expected near-term sales with
derivative instruments and also entering into long-term power sales agreements. However, earnings have been adversely impacted due to a sustained decline in commodity prices. This sustained decline in power prices in conjunction with Dominion’s regular strategic review of its portfolio of assets has led to its decision to pursue the sale or retirement of certain merchant generation assets, which is discussed in more detail below. Variability also results from changes in the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages.
COMPETITION
Dominion Generation Operating Segment—Dominion and Virginia Power
Virginia Power’s generation operations are not subject to significant competition as only a limited number of its Virginia jurisdictional electric utility customers have retail choice. SeeRegulation—State Regulations—ElectricRegulation-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 fromthe majority of which expire between December 31, 2012 to Augustand December 31, 2017,2013, and is therefore largely unaffected by price competition during the termterms of these contracts. Following expirationIt was announced during the third quarter of 2012 that Dominion would pursue the sale of these contracts, earnings couldMidwest assets, excluding its wind facilities. In the fourth quarter of 2012, Dominion announced that Kewaunee is expected to be adversely impacted if prevailing prices for energy, capacity and ancillary services are lower than the levels currently received under these contracts.decommissioned beginning in 2013.
Dominion Generation’s other merchant assets also operate within functioning RTOs and primarily compete on the basis of price. Competitors include other generating assets bidding to operate within the RTOs. These RTOs have clearly identified
market rules that ensure the competitive wholesale market is functioning properly. Dominion Generation’s merchant units have a variety of short- and medium-term contracts, and also compete in the spot market with other generators to sell a variety of products including energy, capacity and ancillary services. It is difficult to compare various types of generation given the wide range of fuels, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, Dominion applies its expertise in operations, dispatch and risk management to maximize the degree to which its merchant fleet is competitive compared to similar assets within the region.
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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
The generation capacity of Virginia Power’s electric utility fleet totals 17,708 MW. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro and renewables. Virginia Power’s generation facilities are located in Virginia, West Virginia and North Carolina and serve load in Virginia and northeastern North Carolina.
Based on available generation capacity and current estimates of growth in customer demand in its utility service area, Virginia Power will need additional generation capacity over the next decade. Virginia Power has announced a comprehensive generation growth program, referred to 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. Significant projects under construction or development include:are set forth below:
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Ÿ | Virginia Power is converting three coal-fired Virginia generating stations to biomass, a renewable energy source. The |
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conditional use permit has been approved to allow for construction of the plant. Brunswick County would offset the expected reduction in capacity caused by the planned retirement of coal-fired units at Chesapeake and Yorktown by 2015 primarily due to the cost of compliance with MATS. |
Ÿ | Subject to the necessary regulatory approvals, Virginia Power plans to convert Bremo Units 3 and 4 from coal to natural gas. This project would preserve the 227 MW of capacity from the units and is expected to cost approximately $53 million, excluding financing costs. The conversion process is expected to be complete in 2014 in compliance with the Virginia City Hybrid Energy Center air permit. |
The Virginia City Hybrid Energy Center located in Wise County, Virginia started commercial operations in July 2012. The summer capacity of this clean coal generating facility is approximately 600 MW. The project cost was approximately $1.8 billion, excluding financing and supplemental costs.
In addition to the 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 May 2010, Virginia Power announced its decision to replace the reactor design previously 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 the DOE terminated their cooperative agreement to share equally the cost of developing a COL. The agreement references the technology previously selected by Virginia Power. DOE funding is not available under the agreement for activities relatedSee Note 13 to the US-APWR technology. During the third and fourth quarters of 2010, Virginia Power filed several applicationsConsolidated Financial Statements for environmental permits that would be needed to support future construction and operation of a third nuclear unit at North Anna.
Virginia Power has not yet committed to building a new nuclear 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 ASLB of the NRC permitted BREDL to intervene in the proceeding. All of BREDL’s previous contentions inmore information on this proceeding have been dismissed. In October 2010, BREDL submitted two new contentions that it seeks to litigate that Virginia Power has opposed. No other persons sought to intervene in the proceeding. Absent additional admitted contentions, the mandatory NRC hearing will be uncontested with respect to other issues.project.
In April 2008, Virginia Power announced a joint effort with BP to evaluate wind energy projects in Virginia. In December 2010, Virginia Power and BP terminated their joint development agreement for wind energy projects. As a result of the termination, Virginia Power has acquired a sole development interest in several wind energy development projects in Virginia. Virginia 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
Dominion is a 50% owner with BP of the first phase of Fowler Ridge. Phase one has generatingThe generation capacity of 300Dominion’s merchant fleet totals 7,880 MW, and is in full commercial operation. In December 2009, Dominion closed on an agreement with BP to split the 350including 3,954 MW of developmentannounced planned facility divestitures and decommissionings. The remaining generation mix is diversified and includes nuclear, gas, and renewables. Merchant generation facilities are located in Connecticut, Indiana, Pennsylvania, Rhode Island and West Virginia with a majority of that capacity concentrated in New England.
Dominion continually reviews its portfolio of assets associatedto determine which assets fit strategically and support its objectives to improve ROIC and shareholder value. In connection with the second phase of Fowler Ridge, withthese efforts, previously Dominion retaining 150 MW of these development assets. In December 2010, Dominion reached an agreementhad announced its intention to sell its 150 MW share of the development assets of the second phase to BP. Closing is subject to the approvals of FERCretire State Line and the Indiana Utility Regulatory Commission, which are expected bySalem Harbor. During the second quarter of 2011.2012, Dominion will receive approximately $6 millionsold State Line, which ceased operations in March 2012, and in August 2012, Dominion completed the sale of proceeds fromSalem Harbor. In the sale.third quarter of 2012, Dominion announced its intention to pursue the sale of its coal-fired merchant power stations, Brayton Point and Kincaid, and its 50% equity method investment in Elwood. In April 2011, Dominion announced the decision to pursue the sale of Kewaunee. In the fourth quarter of 2012, Dominion announced plans to close and decommission Kewaunee after the company was unable to find a buyer for the nuclear facility. Kewaunee is expected to cease power production in the second quarter of 2013 and commence decommissioning activities.
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 Expendituresin Item 7. MD&A.
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Nuclear Fuel—Fuel—Dominion Generation primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.
Fossil Fuel—Fuel—Dominion Generation primarily utilizes coal oil and natural gas in its fossil fuel plants.
Dominion Generation’s coal supply is obtained through long-term contracts and short-term spot agreements from both domestic and international suppliers.
Dominion Generation’s natural gas and oil supply is obtained from various sources including: purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, purchases from local producers in the Appalachian area, purchases from gas marketers and withdrawals from underground storage fields owned by Dominion or third parties.
Dominion Generation manages a portfolio of natural gas transportation contracts (capacity) that allows flexibility in delivering natural gas to its gas turbine fleet, while minimizing costs.
Purchased Power—Power—Dominion Generation purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for utility system load requirements.
Dominion Generation also occasionally purchases electricity from the PJM, ISO-NE and MISO spot markets to satisfy physical forward sale requirements as part of its merchant generation operations.
Dominion Generation Operating Segment—Virginia Power
Presented below is a summary of Virginia Power’s actual system output by energy source:
2010 Source | 2009 Source | 2008 Source | ||||||||||||||||||||||
Coal(1) | 31 | % | 33 | % | 33 | % | ||||||||||||||||||
Source | 2012 | 2011 | 2010 | |||||||||||||||||||||
Nuclear(1) | 33 | % | 28 | % | 28 | % | ||||||||||||||||||
Purchased power, net | 29 | 25 | 29 | 27 | 33 | 29 | ||||||||||||||||||
Nuclear(2) | 28 | 32 | 31 | |||||||||||||||||||||
Coal(2) | 22 | 26 | 31 | |||||||||||||||||||||
Natural gas | 10 | 9 | 6 | 17 | 12 | 10 | ||||||||||||||||||
Other(3) | 2 | 1 | 1 | 1 | 1 | 2 | ||||||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
(1) | Excludes ODEC’s 11.6% ownership interest in North Anna. |
(2) | Excludes ODEC’s 50.0% ownership interest in the Clover power station. The average cost of coal for |
(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-daysdegree days does not produce the same increase in revenue as an increase in cooling degree-days,degree days, due to seasonal pricing differentials at Virginia Power and because alternative heating sources are more readily available.
NUCLEAR DECOMMISSIONING
In June 2011, the NRC amended its regulations to improve decommissioning planning. As applied to the operators of nuclear power plants, these amendments require licensees to conduct operations in a manner minimizing introduction of residual radioactivity into the site, perform additional surveys, and maintain records of their results. In addition, the amendments make minor changes to financial assurance methods and require additional information on decommissioning and spent fuel management costs after a plant permanently ceases operations. The revised regulations became effective in December 2012 and did not significantly affect the decommissioning cost estimates or funding for Dominion’s or Virginia Power’s units.
Dominion Generation Operating Segment—Dominion and Virginia Power
Virginia Power has a total of four licensed, operating nuclear reactors at Surry and North Anna in Virginia.
Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers 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’sNRC 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 billionreflected in 2010 dollarsthe table below and is primarily based upon site-specific studies completed in 2009. These cost studies are generally completed every four years. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Virginia Power expects to decommission the Surry and North Anna units during the period 2032 to 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. In October 2012, Dominion announced that it plans to cease operations at Kewaunee in 2013 and commence decommissioning activities using the SAFSTOR methodology. The planned decommissioning completion date is 2073, which is within the NRC allowed 60 year window.
As part of Dominion’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunee’s trust after decommissioningdecom-
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missioning 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 minimumNRC financial assurance requirement,requirements, which may include, if needed, 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 $4.6 billionreflected in 2010 dollarsthe table below and is primarily based upon site-specific studies completed in 2009.2009, with the exception of Kewaunee for which a site-specific study was initiated in 2012 and subsequently finalized in early 2013. 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 serviceSAFSTOR decommissioning status 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 following the permanent cessation of operations of Millstone Unit 3 during the period 2045 to 2069.
In August 2008, Dominion filed an application with the NRC to renew the Kewaunee operating license. In February 2011, the NRC renewed the operating license, extending Kewaunee’s operation an additional 20 years through 2033. Full decommissioning of Kewaunee is expected during the period 2033 to 2065.
The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion and Virginia Power are shown in the following table.table:
NRC license expiration year | Most recent cost estimate (2010 dollars) | Funds in trusts at December 31, 2010 | 2010 contributions to trusts | NRC license expiration year | Most recent cost estimate (2012 dollars)(1) | Funds in trusts at December 31, 2012 | 2012 contributions to trusts | |||||||||||||||||||||||||
(dollars in millions) | ||||||||||||||||||||||||||||||||
Surry | ||||||||||||||||||||||||||||||||
Unit 1 | 2032 | $ | 541 | $ | 373 | $ | 1.1 | 2032 | $ | 496 | $ | 429 | $ | 0.6 | ||||||||||||||||||
Unit 2 | 2033 | 562 | 368 | 1.2 | 2033 | 520 | 422 | 0.6 | ||||||||||||||||||||||||
North Anna | ||||||||||||||||||||||||||||||||
Unit 1 | 2038 | 550 | 298 | 0.8 | 2038 | 432 | 342 | 0.4 | ||||||||||||||||||||||||
Unit 2 | 2040 | 564 | 280 | 0.8 | 2040 | 443 | 322 | 0.3 | ||||||||||||||||||||||||
Total (Virginia Power) | 2,217 | 1,319 | 3.9 | 1,891 | 1,515 | 1.9 | ||||||||||||||||||||||||||
Millstone | ||||||||||||||||||||||||||||||||
Unit 1 | n/a | 424 | 317 | — | n/a | 455 | 356 | — | ||||||||||||||||||||||||
Unit 2 | 2035 | 651 | 385 | — | 2035 | 568 | 444 | — | ||||||||||||||||||||||||
Unit 3 | 2045 | 680 | 374 | — | 2045 | 671 | 437 | — | ||||||||||||||||||||||||
Kewaunee | — | — | ||||||||||||||||||||||||||||||
Unit 1 | 2013 | 658 | 502 | — | 2033 | 666 | 578 | — | ||||||||||||||||||||||||
Total (Dominion) | $ | 4,630 | $ | 2,897 | $ | 3.9 | $ | 4,251 | $ | 3,330 | $ | 1.9 |
(1) | The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on the Companies’ contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Dominion’s and Virginia Power’s nuclear decommissioning AROs. |
(2) | North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect |
Unit 1 permanently ceased operations in 1998, before Dominion’s acquisition of Millstone. |
Millstone Unit 3 is jointly owned by Dominion Nuclear Connecticut, with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and |
Also see Note 14 and Note 22 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively.
Dominion Energy
Dominion Energy includes Dominion’s regulated natural gas distribution companies, regulated gas transmission pipeline and storage operations, natural gas gathering and by-products extraction activities, and regulated LNG operations.operations and its investment in the Blue Racer joint venture. Dominion Energy also includes producer services, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates.
The gas transmission pipeline and storage business serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in Dominion’s gas transmission pipeline and storage business is its gas gathering and extraction activity, which sells extracted products at market rates. Dominion’s LNG operations involve the import and storage of LNG at Cove Point and the transportation of regasified LNG to the interstate pipeline grid and mid-Atlantic and Northeast markets. In connection with the recent increase in Eastern U.S. natural gas production, including from the Marcellus and Utica Shale formations, Dominion has requested regulatory authority to operate Cove Point as a bi-directional facility, able to import LNG, and vaporize it as natural gas, and liquefy natural gas and export it as LNG. SeeFuture Issues and Other Matters in MD&A for more information. The Blue Racer joint venture will concentrate on building new gathering, processing, fractionation and NGL transportation assets as the development of the Utica Shale formation increases. Dominion will contribute to the joint venture a network of wet gas gathering assets, the Natrium extraction plant and other assets.
Revenue provided by Dominion’s regulated gas transmission and storage and LNG operations is based primarily on rates established by FERC. Additionally, Dominion receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain gas transportation, gas storage, LNG storage and regasification services. Dominion’s gas distribution operations serve residential, commercial and industrial gas sales, transportation and transportationgathering service customers. Revenue provided by its gas distribution operations is based primarily on rates established by the Ohio and West Virginia Commissions. The profitability of these businesses is dependent on Dominion’s ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from operating and maintenance expenditures, as well as changes in rates and the
demand for services, which are dependent on weather, changes in commodity prices and the economy.
In October 2008, East Ohio implemented a rate case settlement which began a transition toprovided for a straight-fixed-variable rate design.design for a majority of its customers. Under this rate design, East Ohio recovers a larger portion of its fixed operating costs through a flat monthly charge accompanied by a reduced volumetric base delivery rate. Accordingly, East Ohio’s revenue is less impacted by weather-related fluctuations in natural gas consumption than under the traditional rate design.
Revenue from Dominion’s gas transportation, gas storage and LNG storage and regasification services are largely based on firm, fee-based contractual arrangements.
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Earnings from Dominion Energy’s nonregulatedproducer services business producer services,are unregulated, and are subject to variability associated with changes in commodity prices. Producer services uses physical and financial arrangements to hedge this price risk.
COMPETITION
Dominion Energy’s gas transmission operations compete with domestic and Canadian pipeline companies. Dominion also competes with gas marketers seeking to provide or arrange transportation, storage and other services. Alternative energy sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain long-line pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enable Dominion to tailor its services to meet the needs of individual customers.
Retail competition for gas supply exists to varying degrees in the two states in which Dominion’s gas distribution subsidiaries operate. In Ohio, there has been no legislation enacted to require supplier choice for residential and commercial natural gas consumers. However, Dominion has offered an Energy Choice program to residential and commercial customers in cooperation withsince October 2000. In January 2013, the Ohio Commission.Commission granted East Ohio’s motion to fully exit the merchant function for its nonresidential customers, beginning in April 2013, which will require those customers to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2012, approximately 1 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice Program. West Virginia does not require customer choicecustomers to choose their provider in its retail natural gas markets at this time. SeeRegulation—State Regulations—GasRegulation-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 21,800 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 ownerowners of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with
results that range from reimbursed relocation to revocation of permission to operate.
Dominion Energy has approximately 11,000 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy operates gas processing and fractionation facilities in West Virginia with a total processing capacity of
267,000 mcf per day and fractionation capacity of 582,000 gallons per day. Dominion Energy also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with almost 2,000 storage wells and approximately 262,000349,000 acres of operated leaseholds.
The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 947 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy. The capacity of those fields owned by Dominion’s partners totals about 242 bcf. Dominion Energy also has about 15 bcf of above-ground storage capacity at Cove Point. Dominion Energy has about 123133 compressor stations with more than 768,000832,000 installed compressor horsepower.
In July 2008, East Ohio launched the PIR program to replace approximately 20% of its 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 copper pipe over a 25-year period. As part of this program, East Ohio will assume ownership of curb-to-meter service lines and will be responsible for line repairs or replacement. In October 2008, the Ohio Commission approved cost recovery for an initial five-year period of the PIR program.
In 2006, FERC approved the proposed expansion of Dominion’s Cove Point terminal and2012, 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 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 March 2010, Dominion commenced 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 the south berth being taken temporarily out of service to accommodate construction activities. In October 2010, Dominion requested and received FERC authorization to re-commence service from the south berth of the pier for vessels with cargo capacities of no greater than 148,000 cubic meters. When the south berth was returned to service, construction commenced on the north berth, which was taken out of service. In December 2010, Dominion
requested and received authorization to place the project in service on January 21, 2011.
DTI has announcedcompleted the Gathering Enhancement Project, a $253$200 million expansion of its natural gas gathering, processing and liquids facilities in West Virginia. The project is designed to increase the efficiency and reduce high pressures in its gathering system, thus increasing the amount of natural gas local producers can move through DTI’s West Virginia system. Construction started in 2009 and is expected to be
In September 2012, DTI completed by the fourth quarter of 2012. The cost of the project will be paid for by rates charged to producers.
DTI 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. DTI 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$575 million Appalachian Gateway Project. The project is expected to provideprovides 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,November 2012, DTI entered into a 15-year firm transportation agreement withcompleted the gas subsidiary of CONSOL.$97 million Northeast Expansion Project. The project known as the Northeast Expansion Project, is expected to provideprovides 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 2010,2012, DTI filed a certificate application with FERC seeking approval forcompleted the Northeast Expansion Project. If the project$46 million Ellisburg-to-Craigs project. The project’s capacity of approximately 150,000 dekatherms per day 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 withleased by TGP for firm capacity to move Marcellus shaleShale 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
In November 2011, DTI filed a FERC application for approval to construct the $17 million Sabinsville-to-Morrisville project, known as the Ellisburg-to-Craigs Project,a pipeline to move additional Marcellus supplies from a TGP pipeline in northeast Pennsylvania to its line in upstate New York. DTI executed a binding precedent agreement with TGP in October 2010 to provide this firm transportation service up to 92,000 dekatherms per day for a 14-year term. Construction is expected to have capacitycommence in April 2013 with an expected in service date of November 2013.
In December 2012, DTI received FERC authorization for the Allegheny Storage Project, which is expected to provide approximately 150,0007.5 bcf of incremental storage service and 125,000 dekatherms per day.day of associated year-round firm transportation service to three local distribution companies under 15-year contracts. Storage capacity for the project will be provided from storage pool enhancements at DTI and capacity leased from East Ohio. DTI intends to construct additional compression facilities and upgrade measurement and regulation in order to provide 115,000 dekatherms per day of transportation service. The remaining 10,000 dekatherms per day of transportation service will not require construction of additional facilities. The $112 million project is expected to be in service in 2014.
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In February 2011, DTI concluded a binding open season for its $67 million Tioga Area Expansion Project, which is designed to provide approximately 270,000 dekatherms per day of firm transportation service from supply interconnects in Tioga and Potter Counties in Pennsylvania to DTI’s Crayne interconnect with Texas Eastern Transmission, LP in Greene County, Pennsylvania and the Leidy interconnect with Transcontinental Gas Pipe Line Company in Clinton County, Pennsylvania. Two customers have contracted for the service under 15-year terms. DTI filed a certificate application with FERC in November 2011. Subject to the receipt of regulatory approvals, the project 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 TGPis anticipated to be in New York. DTI filed a certificate application with FERCservice 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 2012.2013.
In January 2011, Dominion announced that DTI is developingthe development of a natural gas processing and fractionation facility in Natrium, West Virginia, and in July 2011 it executed a contract for the construction of the first phase of the facility. This first phase of the project is fully contracted and is expected to be in service by March 2013. Once completed, the plant and related facilities are expected to be contributed into the Blue Racer joint venture. The Phase 1 costs for processing, fractionation, plant inlet and outlet natural gas transportation, gathering, and various modes of NGL transportation are approximately $550 million.
In May 2012, Dominion began construction of a $125 million pipeline project, which is included in the Natrium cost estimate above. The pipeline is designed to transport approximately 27,000 barrels per day of ethane from the Natrium facility to an interconnect with the ATEX line of Enterprise near New Martinsville,Follansbee, West Virginia. Dominion reachedNGL Pipelines, LLC, a subsidiary of Dominion, owns the 58-mile pipeline and associated equipment. Following the installation of the pipeline and the satisfaction of certain other conditions, Dominion NGL Pipelines, LLC is also expected to be contributed to Blue Racer. The facilities are anticipated to be available the later of January 1, 2014 or the date Enterprise commences operation of the ATEX line. Transportation services on the pipeline will be subject to FERC regulation under the Interstate Commerce Act.
In November 2012, DTI filed a FERC application for approval to construct the $42 million Natrium to Market project. The project is designed to provide 185,000 dekatherms per day of firm transportation from an agreement with PPG Industries, Inc. to purchase 56 acres atinterconnect between DTI and the Natrium site where DTI plansfacility to process natural gasDTI’s interconnect with Texas Eastern Transmission, LP in Greene County Pennsylvania. Four customers have entered into binding precedent agreements for the full project capacity under 8-year and NGLs.13-year terms. Subject to the receipt of regulatory approvals, the project is anticipated to be in service in November 2014.
In 2008, East Ohio began PIR, aimed at replacing approximately 20% of its pipeline system. The $2.7 billion, 25-year program is ongoing. See Note 13 to the Consolidated Financial Statements for further information about PIR.
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.
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,March; however implementation of the straight fixed variablestraight-fixed-variable rate design at East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipeline and storage business can also be weather sensitive. Commodity prices can be impacted by seasonal weather changes, the effects of unusual weather events on operations and the economy. Dominion’s producer services business is affected by seasonal changes in the prices of commodities that it transports, stores and actively markets and trades.
Corporate and Other
Corporate and Other Segment—Virginia Power
Virginia Power’s Corporate and Other segment primarily includes certain specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Corporate and Other Segment—Dominion
Dominion’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) and the net impact of Peoplesoperations that are expected to be and certain DCI operations,are currently discontinued, which
are is discussed in Notes 4 and 25Note 3 to the Consolidated Financial Statements, respectively.Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
ENVIRONMENTAL STRATEGY
Dominion and Virginia Power are committed to being good environmental stewards. Their ongoing objective is to provide reliable, affordable energy for their customers while being environmentally responsible. The integrated strategy to meet this objective consists of five major elements:
Ÿ | Compliance with applicable environmental laws, regulations and rules; |
Ÿ | Conservation and load management; |
Ÿ | Renewable generation development; |
Ÿ | Other generation development to maintain fuel diversity, including clean coal, advanced nuclear energy, and natural gas; and |
Ÿ | Improvements in other energy infrastructure. |
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This strategy incorporates Dominion’s and Virginia Power’s efforts to voluntarily reduce GHG emissions, which are described below. SeeGlobal Climate ChangeDominion Generation—Properties underRegulation—Environmental Regulations in this item for examplesmore information on certain of the Companies’ effortsprojects described below, as well as other projects under current development. In addition to reduce their impact on the environment.environmental strategy described above, Dominion formed the AES department in April 2009 to conduct research in the renewable and alternative energy technologies sector and to support strategic investments to advance Dominion’s degree of understanding of such technologies.
Environmental Compliance
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 obligationsmatters can be found inFuture Issues and Other Mattersin Item 7. MD&A and in Note 2322 to the Consolidated Financial Statements.
Conservation and Load Management
Conservation plays a significant role in meeting the growing demand for electricity. The Regulation Act provides incentives for energy conservation and sets a voluntary goal for Virginia to reduce electricity consumption by retail customers in 2022 by ten percent of the amount consumed in 2006 through the implementation of conservation programs. Legislation in 2009 added definitions of peak-shaving and energy efficiency programs, and allowed for a margin on operating expenses and revenue reductions related to energy efficiency programs.
Virginia Power’s DSM programs provide the firstimportant incremental 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
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, which were approved by the Virginia Commission in March 2010 and rolled out in May 2010:
Ÿ | Residential Lighting Program—an instant, in-store discount on the purchase of qualifying compact fluorescent lights; this program ended in Virginia on December 31, 2011; |
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Ÿ | Commercial |
Ÿ | Commercial Lighting Program—incentives for commercial customers to install energy-efficient lighting. |
In September 2011, Virginia Power has also proposed a redesigned distributed generationfiled an application for approval of several DSM programs and for additional funding for the approved Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs, in addition to requesting annual recovery of DSM program which was not approved in its original form bycosts. In April 2012, the Virginia Commission in 2010.approved the following programs:
Ÿ | Commercial Energy Audit Program—an on-site energy audit providing commercial customers information to evaluate potential energy cost savings options; |
Ÿ | Commercial Duct Testing & Sealing—an incentive for commercial customers to seal duct and air distribution systems to improve system efficiency; |
Ÿ | Commercial Distributed Generation—a program for customers to operate their on-site back-up generators when requested by Virginia Power during periods of peak demand; and |
Ÿ | Residential Bundle Program—a bundle of four residential programs to be available to qualifying residential customers, including the Residential Home Energy Check-up Program, Residential Duct Testing & Sealing Program, Residential Heat Pump Tune-Up Program and Residential Heat Pump Upgrade Program. |
The Virginia Commission denied additional funding for the Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs. As a result, Virginia Power plansbegan winding down these programs in the second quarter of 2012. These two programs are no longer available in Virginia.
In August 2012, Virginia Power filed an application for approval to seekextend two residential DSM programs (the Air Conditioner Cycling program and the Low Income program) beyond April 30, 2013 for periods of five years and two years, respectively. Virginia CommissionPower also filed for approval of the redesigned distributed generationupdated rate adjustment clauses for DSM program cost recovery, and several other DSM programs in 2011.for Electric Vehicle Pilot Program cost recovery. This case is pending.
In September 2010, Virginia Power filed with the North Carolina Commission an application for approval and its initial request for cost recovery of the five DSM programs listed above,initially approved in Virginia in 2010, as well as the redesigned distributed generation program. In February 2011, the North Carolina Commission approved the five DSM programs listed above.approved in Virginia, and Virginia Power subsequently launched the residential lighting program in May 2011 and the remainder of the approved Virginia DSM programs in June 2011. The Residential Lighting Program ended in North Carolina on December 31, 2011. In a separate order issued in September of 2011, the North Carolina Commission will make a decision regarding the appropriate rate making treatment for the programs in a separate proceeding.denied approval of Virginia Power’s proposed distributed generation program.
In August 2011, Virginia Power expects to launchfiled with the North Carolina Commission an application for approval and its updated request for cost recovery of the five DSM programs within itsapproved in North Carolina, service territory inas well as the second quarter ofthen-pending distributed generation program. In December 2011, subject to cost recovery approval by the North Carolina Commission.Commission approved updated cost recovery for the five DSM programs, as Virginia Power withdrew its cost recovery request for the distributed generation program. In a separate order issued in August 2012, the North Carolina Commission approved Virginia Power’s request for approval ofto suspend the redesigned distributed generation program remains pending beforeCommercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs which had been wound down and closed in Virginia.
In August 2012, Virginia Power filed with the North Carolina Commission.Commission an application for approval and its updated request for cost recovery for the five DSM programs approved in North Carolina, as well as cost recovery for projected costs of Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs on a North Carolina-only basis. In December 2012, the North Carolina Commission approved updated cost recovery for the five DSM programs, and requested an additional filing on whether the Commercial Lighting and the
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Commercial Heating, Ventilating and Air Conditioning Upgrade programs will be offered on a North Carolina-only basis. Virginia Power made this additional filing in February 2013.
Virginia Power continues to evaluate opportunities to redesign current DSM programs and develop new DSM initiatives in Virginia and North Carolina.
Virginia Power is currently evaluating the effectiveness and benefits of installing AMI meters on homes and businesses throughout Virginia. The AMI meter demonstrations test the effectiveness of AMI meters in achieving voltage conservation, remotely turning off and on electric service, power outage and restoration detection and reporting, remote daily meter readings and offering dynamic rates. The AMI meter demonstrations are an on-going project that will help Virginia Power to further evaluate the technology and verify the potential impacts to its system.
Renewable Generation
Renewable energy is also an important component of a diverse and reliable energy mix. Both Virginia and North Carolina have passed legislation setting targets for renewable power. Virginia Power is committed to meeting Virginia’s goals of 12% of base year electric energy sales from renewable power sources by 2022, and 15% by 2025, and North Carolina’s RPS of 12.5% by 2021. In May 2010, the Virginia Commission approved Virginia Power’s participation in the state’s RPS program. As a participant, Virginia Power is permitted to seek recovery, through rate adjustment clauses, of the costs of programs designed to meet RPS goals. Virginia Power plans to meet the respective RPS targets in Virginia and North Carolina by utilizing existing renewable facilities, as well as the Virginia City Hybrid Energy Center, which is expected to use at least 10% biomass.through additional renewable generation. In addition, Virginia Power intends to purchase renewable energy certificates, as permitted by each RPS program, to help meet any remaining annual requirement needs.needs, as well as to fund renewable energy research and development initiatives at Virginia institutions of higher education. Virginia Power continues to explore opportunities to develop new renewable facilities within its service territory, the energy attributes of which would potentially qualify for inclusion in the RPS programs.
In June 2010, Virginia Power announced its plansis converting three coal-fired Virginia generating power stations to develop an integrated solar and battery storage demonstration project in
Halifax County, Virginia.biomass, which will increase Dominion’s renewable generation by more than 150 MW. The proposed facility is intendedconversions are expected to manage, store, and optimize solar energy to regulate intermittency, enable peak shaving and increase grid reliability.be completed by the end of 2013. In November 2010,2012, 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 expectedvoluntary demonstration program for Company-owned solar distributed generation facilities, to be operationallocated at selected commercial, industrial and community locations throughout its Virginia service territory.
Dominion has invested in 2013.
In addition,wind energy through two joint ventures. Dominion is a 50% owner with Shell of NedPower. Dominion’s share of this project produces 132 MW of renewable energy.
Dominion is also a 50% owner with BP of the first phase of Fowler Ridge, which has a generating capacity of 300 MW. Dominion has a long-term agreement with Fowler Ridge to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In December 2010, Dominion reached an agreement
See Note 13 to sell its remaining share of the development assets of the second phase of Fowler Ridge to BP.Consolidated Financial Statements for additional information.
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 anticipated growth in demand in its core market of Virginia. Virginia Power expects that these investments collectively will provide the following benefits: expanded electricity production capability, increased technological and fuel diversity and a reduction in the CO2 emission intensity of its generation fleet. One component of thePowering Virginia program involves consideration of the extent to which Virginia Power can 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 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 consider CO2 and other GHG emissions when making these long-term decisions. SeeDominion Generation—Properties for more information.
Improvements in Other Energy Infrastructure
In December 2010, Virginia Power announced itsPower’s five-year investment plan which includes spending approximately $4 billionsignificant capital expenditures to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service, and are intended to address both continued population growth and increases in electricity consumption by the typical consumer. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed or to be developed in the
future. SeeGlobal Climate Change underRegulation—Environmental Regulations in this item for more information.
Virginia Power is taking measures to ensure that its electrical infrastructure can support the expected demand from electric vehicles, which have significantly lower carbon intensity than conventional vehicles. Virginia Power has partnered with Ford Motor Company to help prepare Virginia for the operation of electric vehicles, in a collaboration that involves consumer outreach, educational programs and the exchange of information on vehicle charging requirements. In July 2011, the Virginia Commission approved Virginia Power’s application to establish an Electric Vehicle Pilot Program, including two experimental and voluntary electric vehicle rate options.
Dominion, in connection with its five-year growth plan, is also pursuing the construction or upgrade of regulated infrastructure in its natural gas business.
Dominion and Virginia Power’s Strategy for Voluntarily Reducing GHG Emissions
While Dominion and Virginia Power have not established a standalone GHG emissions reduction target or timetable, they are actively engaged in voluntary reduction efforts, as well as working toward achieving required RPS standards established by existing state regulations, as set forth above. The Companies have an integrated voluntary strategy for reducing overall GHG emission intensity that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, oil, hydro and renewable energy, investing in renewable energy projects and promoting energy conservation and efficiency efforts. Below are some of the Companies’ efforts that have or are expected to reduce the Companies’ overall carbon emissions or intensity:
Ÿ | Since 2000, Dominion has added approximately 3,300 MW of non-emitting generation and over 5,000 MW of lower-emitting natural gas-fired generation, including over 3,000 MW at Virginia Power, to its generation mix. |
Ÿ | Virginia Power added 83 MW of renewable biomass and is converting three coal-fired power stations to biomass, which is anticipated to be considered carbon neutral by regulatory agencies. |
Ÿ | Virginia Power has requested approval from the Virginia Commission to convert Bremo Units 3 and 4 from coal to natural gas. |
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Ÿ | Dominion has over 800 MW of wind energy in operation or development. |
Ÿ | Virginia Power is constructing the natural gas-fired Warren County power station. |
Ÿ | Virginia Power has filed an application with the Virginia Commission for approval to construct an additional combined-cycle natural gas-fired power station and related transmission interconnection facilities in Brunswick County. |
Ÿ | Virginia Power has stated that coal-fired units at Chesapeake and Yorktown are planned to be retired by 2015. |
Ÿ | Virginia Power has received an Early Site Permit from the NRC for the possible addition of approximately 1,500 MW of nuclear generation in Virginia. Virginia Power has not yet committed to building a new nuclear unit. |
Ÿ | Virginia Power has developed and implemented the DSM programs described above. |
Ÿ | Virginia Power has initiated a demonstration of smart grid technologies as described above. |
Ÿ | In October 2011, Virginia Power announced plans to develop a community solar power program. |
Ÿ | In 2012, Dominion sold Salem Harbor and State Line, two coal-and fuel oil-fired facilities. |
Ÿ | In the third quarter of 2012, Dominion announced its intention to pursue the sale of its coal-fired merchant power stations, Brayton Point and Kincaid. |
Ÿ | In December 2012, Dominion announced its plans to develop a 15 MW fuel cell power generating facility in Bridgeport, Connecticut. |
While Virginia Power’s new Virginia City Hybrid Energy Center, which started commercial operations in July 2012, is 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 10% biomass for fuel and is designed to be carbon-capture compatible, meaning that technology to capture CO2 can be added to the station if or when it becomes commercially available. It is currently estimated that the Virginia City Hybrid Energy Center will have the potential to emit about 4.8 million metric tonnes of direct CO2 emissions in a year assuming a 100% capacity factor and 100% coal-fired operation. Actual emissions will depend on the capacity factor of the facility and the extent to which biomass is burned.
Dominion also developed a comprehensive GHG inventory for calendar year 2011. For Dominion Generation, Dominion’s and Virginia Power’s direct CO2 equivalent emissions, based on equity share (ownership), were approximately 42.1 million metric tonnes and 25.9 million metric tonnes, respectively, in 2011. The decrease in emissions from 2010 to 2011 is proportional to a decrease in generated MW, due mainly to lower demand and milder weather in 2011. For the DVP operating segment’s electric transmission and distribution operations, direct CO2 equivalent emissions for 2011 stayed the same as in 2010 at 0.2 million metric tonnes. For 2011, DTI’s (including Cove Point) direct CO2 equivalent emissions were approximately 1.2 million metric tonnes and East Ohio’s direct CO2 equivalent emissions were approximately 1.1 million metric tonnes. The emissions appear to have decreased significantly compared to previous year’s inventories. These differences may not be comparable, however, due to a change in calculation methodologies required under the
EPA Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98. Dominion’s GHG inventory now follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98 for calculating emissions.
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 2011, 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 29% and 18%, respectively. During such time period, the capacity of Dominion and Virginia Power’s electric generation fleet has grown. The Companies do not yet have final 2012 emissions data.
Alternative Energy Initiatives
The AES department conducts research in the renewable and alternative energy technologies sector and supports strategic investments to advance Dominion’s degree of understanding of such technologies. AES participates in federal and state policy development on alternative energy and identifies potential alternative energy resource and technology opportunities for Dominion’s business units. For example, in December 2012, Virginia Power was selected by the DOE to begin negotiations for initial engineering, design and permitting work for a wind turbine demonstration facility approximately 24 miles off the coast of Virginia. The proposed 12 MW grid-connected facility would generate power via two turbines mounted on foundations driven into the ocean floor. In March 2011, Dominion issued a report evaluating high-voltage underwater transmission lines from Virginia Beach into the ocean to support multiple offshore wind farms; the first of many steps with the goal being the development of a transmission line making offshore wind resources available to its customers. A 2010 Dominion study of its existing transmission system in eastern Virginia showed that it is possible to interconnect large scale wind facilities up to an installed capability of 4,500 MW.
In 2012, Dominion continued to enhance and refine its EDGE® grid-side efficiency product suite. EDGE® is a modular and adaptive conservation voltage management solution enabling utilities to deploy incremental grid-side energy management that requires no behavioral changes or purchases by end customers. In February 2013, Dominion was awarded a patent relating to the EDGE® technology.
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.
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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 certain securities.
Electric Regulation in Virginia
Prior toThe enactment of the Regulation Act whichin 2007 significantly changed electricityelectric service regulation in Virginia Virginia Power’s Virginia jurisdictional base rates wereby instituting a modified cost-of-service rate model. With respect to be capped at 1999 levels until December 31, 2010, at which time Virginia was to convertmost classes of customers, the Regulation Act ended Virginia’s planned transition to retail competition for its electric supply service. The Regulation Act ended cappedBase rates two years early, on December 31, 2008, at which time retail competition was made available only to individual retail customers withare set by 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 directingprocess that allows Virginia Power to file annual fuel cost recovery cases withrecover its operating costs and an ROIC. The Virginia Commission reviews Virginia Power’s base rates, terms and conditions for generation and distribution services on a biennial basis in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a combined two-year historic test period, and the determination of Virginia Power’s authorized ROE prospectively. If, as a result of the earnings test review, the Virginia Commission.
Pursuant toCommission determines that Virginia Power’s historic earnings for the two-year test period are more than 50 basis points above the authorized level, 60% or 100% of earnings above this level must be shared with customers through a refund process. Under certain circumstances described in the Regulation Act, the Virginia Commission entered anmay also order in January 2009 initiating the 2009 Base Rate Review. In connection with the 2009 Base Rate Review, Virginia Power submitteda base rate filings and accompanying schedules toincrease or reduction during the biennial review. Circumstances where the Virginia Commission during 2009. In February 2010, Virginia Power filedmay order a revised Stipulation and Recommendation withbase rate decrease include a determination by the Virginia Commission which had the supportthat Virginia Power has exceeded its authorized level of all of the interested parties, including the Staff of the Virginia Commission. Virginia Power’s fourth quarter 2009 results included a charge of $782 million ($477 million after-tax) representing its best estimate at the time of the probable outcome of the 2009 Base Rate Review. In March 2010, the Virginia Commission issued 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
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Base Rates
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FTR Credits
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Generation Riders R and S
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Transmission Rider T
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DSM Riders C1 and C2
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Commencing in 2011, the Virginia Commission will conduct biennial reviews of Virginia Power’s base rates, terms and conditions. In theearnings by more than 50 basis points for two consecutive biennial review as in the 2009 Base Rate Review,periods. Virginia Power’s authorized ROE can be set no lower than the average, for a three-year historic period, of thatthe actual returns reported to the SEC by not less than a majority of comparable utilities within the Southeastern U.S., with certain limitations as described in the Regulation Act. If Virginia Power’s earnings are
more thanROE may be increased or decreased by up to 100 basis points based on operating performance criteria, or alternatively, will be increased by 50 basis points abovefor compliance with Virginia’s RPS.
In addition, the authorized level, such earnings will be sharedRegulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation facilities or major unit modifications of existing facilities, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It provides for enhanced returns on capital expenditures relating to the construction or major modification of facilities that are nuclear-powered, clean coal/carbon capture compatible-powered, or renewable-powered, as well as conventional coal and combined-cycle combustion turbine facilities.
Costs of fuel used for the generation of electricity, along with customers.
costs of purchased power, are recovered from customers through an annually approved fuel rider, as provided under a separate section of the Virginia Power previously filed withCode. Decisions of 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 Virginia Power’s retail customers by ten percent of what was consumed in 2006. In March 2010, the Virginia Commission approved the recovery of approximately $28 million for five of the DSM programs through initiation of Riders C1 and C2, effective May 1, 2010. With respectmay be appealed 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 evaluationSupreme Court 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 was held by the Virginia Commission on Virginia Power’s 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 connection with the Bear Garden and Virginia City Hybrid Energy Center projects, 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 $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 the rate year ending March 31, 2012 is approximately $200 million, which represents an increase of $46 million over the revenue requirement associated with the Rider S customer 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 statutory enhancement) for use until the ROE is determined in the context of Virginia Power’s upcoming biennial review. Evidentiary hearings were held by the Virginia Commission on Riders R and S in December and November 2010, respectively.
The Virginia Commission is required to issue its orders in these proceedings by March 30, 2011.
With respect to Virginia Power’s costs of transmission service, in June 2010, the Virginia Commission approved Virginia Power’s annual update to Rider T which was effective September 1, 2010, reflecting the revenue requirement of approximately $338 million recommended by the Virginia Commission Staff and agreed to by Virginia Power. The $338 million revenue requirement reflects an increase of approximately $118 million over the previous revenue requirement.
In 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 $82 million for the period July 1, 2010 through June 30, 2011. The proposed fuel factor went into effect on July 1, 2010 on an interim basis. An evidentiary hearing on Virginia Power’s application was held in September 2010, and in October 2010, the Virginia Commission issued its final order approving the reduction in Virginia Power’s fuel factor as proposed in its application.Virginia.
If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s upcoming biennial review and rate adjustment clause filings, differ materially from Virginia Power’s expectations, it could adversely affect its results of operations, financial condition and cash flows.
SeeFuture Issues and Other Matters in Item 7. MD&A for changes to the Regulation Act enacted in 2013.
See Note 13 to the Consolidated Financial Statements for additional information.
Electric Regulation in North Carolina Regulation
Virginia Power’s retail electric base rates in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes and the rules and procedures of the North Carolina Commission. North Carolina base rates have been subjectare set by a process that allows Virginia Power to a five-year base rate moratorium, effective as of April 2005. Fuelrecover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the North Carolina Commission, retail electric rates continued tomay be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, Virginia Power’s future earnings could be negatively impacted. Fuel rates are subject to revision under annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveriescost adjustment proceedings.
Virginia Power’s transmission service rates in North Carolina are regulated by the North Carolina Commission as part of fuel costs.Virginia Power’s bundled retail service to North Carolina customers.
In February 2010, in preparation for the end of the five-year base rate moratorium,March 2012, Virginia Power filed an application to 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,with the North Carolina Commission issuedto increase base non-fuel revenues with January 1, 2013 as the North Carolina Settlement Approval Order. The North Carolina Settlement Approval Order authorizes an increase in base revenues of approximately $8 million and a one-year decrease in combined fuel revenues of approximately $32 million when compared to revenues produced from current rates. In addition, the North Carolina Settlement Approval Order permits the recovery 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 economic dispatch that do not provide actual cost data. The
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 requirementproposed effective date for the purpose of a global settlement of disputed issues inpermanent rate revision. See Note 13 to the proceedings. The new base and fuel rates became effective on January 1, 2011.Consolidated Financial Statements for additional information.
GAS
Dominion’s gas distribution services are regulated by the Ohio Commission and the West Virginia Commission.
Status of Competitive Retail Gas Services
Both of the states in which Dominion has gas distribution operations have considered legislation regarding a competitive deregulation of natural gas sales at the retail level.
Ohio—Since October 2000, East Ohio has not enacted legislation requiring supplier choice for residential or commercial natural gas consumers. However, in cooperation withoffered the Ohio Commission, Dominion offers retail choice toEnergy Choice program, under which residential and commercial customers. At December 31, 2010, approximately 1 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choiceare encouraged to purchase gas directly from retail suppliers or through a community aggregation program. In October 2006, East Ohio implemented a pilot program approvedrestructured its commodity service by the Ohio Commission as a transitional step towards the improvement and expansion of the Energy Choice program. Under the pilot program, East Ohio enteredentering into gas purchase contracts with selected suppliers at a fixed price above the NYMEX month-end settlement. Thissettlement and passing that gas cost to customers under the Standard Service Offer pricing mechanism replaced the traditional gas cost recovery rate with a monthly market price that eliminated the true-up adjustment, making it easier for customers to compare and switch to competitive suppliers if they so choose.
In June 2008, the Ohio Commission approved a settlement filed in response to East Ohio’s application seeking approval of Phase 2 of its plan to restructure its commodity service. Under that settlement, the existing Standard Service Offer program was continued through March 2009 with an update to the fixed rate adder to the NYMEX price.program. Starting in April 2009, East Ohio buys natural gas under the Standard Service Offer program only for customers not eligible to participate in the Energy Choice program and places
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Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills.
In January 2013, the Ohio Commission granted East Ohio’s motion to fully exit the merchant function for its nonresidential customers, beginning in April 2013, which will require those customers to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2012, approximately 1.0 million of Dominion’s 1.2 million Ohio customers were participating in the Energy Choice program. Subject to the Ohio Commission’s approval, East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. East Ohio continues to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.
West Virginia—At this time, West Virginia has not enacted legislation to require customer choicecustomers to choose in the retail natural gas markets served by Hope. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customercustomers a choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.
Rates
Dominion’s gas distribution subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which
they operate—Ohio and West Virginia. When necessary, Dominion’s gas distribution subsidiaries seek general base rate increases to recover increased operating costs.costs and a fair return on rate base investments. Base rates are set based on the cost of service by rate class. A straight-fixed-variable rate design, in which the majority of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohio’s customers pursuant to a 2008 rate case settlement. Base rates for Hope are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. In addition to general rate increases, Dominion’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery
through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective one-, three- or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.
In the fourth quarter of 2008, the The Ohio Commission has also approved an approximately $41 million annual base rate revenue increase and an 8.49% allowed rate of return on rate base for East Ohio, which were reflected in revised base rates commencing December 22, 2008.
In October 2008, the Ohio Commission approvedseveral stand-alone cost recovery for an initial five-year period of East Ohio’s 25-year PIR programmechanisms 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 actualrecover specified 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 Ohiofor infrastructure projects and the Staff of the Ohio Commission reflecting a revenue requirement of approximately $27 million. Other interested partiescertain other costs that vary widely over time; such costs are excluded from general base rates. See Note 13 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 millionConsolidated Financial Statements for the 12 months that the PIPP rider rate will be in effect. The PIPPadditional information.
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. In June 2010, the West Virginia Commission authorized an additional base rate increase of less than $1 million to correct a miscalculation of rates attached to the November 2009 order.
Federal Regulations
FEDERAL ENERGY REGULATORY COMMISSION
Electric
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominion’s merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion’s market-based sales tariffs authorized by FERC. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.
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 the 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, 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.
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
In July 2008, Virginia Power filed an application with FERC requesting a revision to its revenue 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 1.5% for four of the projects (including the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line) and an incentive of 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, 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-
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 RPM Buyers filed a complaint with 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. In November 2009, the Court transferred the appeal to the Court of Appeals for the District 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 operation of the bulk power system in the U.S. FERC has certified NERC as the ERO and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of between $1 thousand and $1 million per day, and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
Dominion and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion and Virginia Power employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. Dominion and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cyber securitycybersecurity programs as well as efforts to ensure appropriate facility ratings for Virginia Power’s transmission lines. In October 2010, NERC issued an industry alert identifying possible discrepancies between the design and actual field conditions of transmission facilities as a potential reliability issue. The alert recommends that entities review their current facilities rating methodology to verify that the methodology is based on actual field conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power is evaluating its transmission facilities for any discrepancies between design and
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actual field conditions. In addition, NERC has requested the industry to increase the number of assets subject to NERC reliability standards that are designated as critical assets, including cyber securitycybersecurity assets. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
Gas
FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate natural gas company subsidiaries, including DTI and Cove Point and the Dominion South Pipeline Company, LP.Point. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.
Dominion’s interstate gas transmission and storage activities are generally conducted on an open access basis, in accordance with certificates, tariffs and service agreements on file with FERC.
Dominion is also subject to the Pipeline Safety ActActs of 2002 and 2011, which mandatesmandate 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 this Act,these Acts, 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 DTI, its customersSeeFuture Issues and interested state commissions. The settlement, which became effective July 1, 2005, revised DTI’s natural gas transmission ratesOther Matters in Item 7. MD&A 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 subjectNote 13 to the terms of the tariff rates established pursuant to the settlement.
In December 2007, DTI and the IOGA entered into a settlement agreement on DTI’s gathering and processing rates, which DTI and IOGA agreed in May 2010 to extend through December 31, 2014. DTI, at its option, may elect to extend the agreementConsolidated Financial Statements for an additional year through December 31, 2015. The settlement extension 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. DTI will file the negotiated rates associated with the agreement extension with FERC in December 2011.information.
Dominion is required to file 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 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. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Companies. If expenditures for pollution control technologies and associated operating costs are not recoverable from customers through regulated rates (in regulated jurisdictions) or market prices (in deregulated jurisdictions), those costs could adversely affect future results of operations and cash flows. The cost of complying with appli-
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 MattersinFuture Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 2322 to the Consolidated Financial Statements.
GLOBAL CLIMATE CHANGE
General
In recent years there has been increasedThe national and international attention toin recent years on 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 tothat would provide a consistent, economy-wide approach to addressing this issue and are currently taking action to protect the environment and address climate change while meeting the future needs of their growing service territory. Dominion’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including climate change, and Dominion’s Board of Directors receives periodic updates on these matters.
Dominion has developed a comprehensive GHG inventory for calendar year 2009. For Dominion Generation, Dominion’s SeeEnvironmental Strategyabove, Environmental Matters inFuture Issues and Virginia Power’s direct CO2 equivalent emissions, based on equity share (ownership), were approximately 54 million metric tonnesOther Mattersin Item 7. MD&A and 33 million metric tonnes, respectively, in 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 Cove Point) direct CO2 equivalent emissions were approximately 2.5 million metric tonnes and East Ohio’s direct CO2 equivalent emissions were approximately 1.4 million metric tonnes. While the Companies do not have final 2010 emissions data, they do not expect a significant variance in emissions from 2009 amounts. With respect to electric generation, primary facility stack emissions of CO2 from carbon based fuel combustion are directly measured via continuous emissions monitor system methods set forth under 40 CFR Part 75 of the U.S. Electric Code of Federal Regulation. For those emission sources not covered under 40 CFR Part 75, and for methane and nitrous oxide emissions, quantification is based on fuel combustion, higher heating values, emission factors, and global warming potentials as specified in the EPA’s Mandatory Reporting of Greenhouse Gases Rule. For the DVP operating segment’s electric transmission and distribution emissions, the protocol used 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-GHG EstimationMethodologies and Procedures-Revision 2, September 28, 2005 developed by the Interstate Natural Gas Association of America.
For East Ohio, the protocol used to calculate the non-combustion related emissions was the American Gas Association’s April 2008 Greenhouse Emissions Estimation Methodologies and Procedures for Natural Gas Distribution Operations.
Climate Change Legislation and Regulation
See Note 2322 to the Consolidated Financial Statements for information on climate change legislation and regulation.
Dominion and Virginia Power’s Strategy for Voluntarily Reducing GHG Emissionsregulation, which information is incorporated herein by reference.
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. Below are some of the Companies’ efforts that have or are expected to reduce the Companies’ carbon emissions or intensity:
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While, upon entering service, Virginia Power’s new Virginia City Hybrid Energy Center, which is currently under construction in southwest Virginia, will be a new source of GHG emissions, Virginia Power has taken steps to minimize the impact on the environment. The new plant is expected to use at least 10% biomass for fuel and is 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 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 16% and 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. SeeNuclear Matters inFuture Issues and Other Matters in Item 7 MD&A for further information.
The NRC also requires Dominion and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and the Companies are required by the NRC to be financially prepared. For information on decommissioning trusts, seeDominion Generation—NuclearGeneration-Nuclear Decommissioning and Note 109 to the Consolidated Financial Statements. See Note 22 to the Consolidated Financial Statements for information on spent nuclear fuel.
SCPENT NUCLEAR FUELYBERSECURITY
Under provisionsIn an effort to reduce the likelihood and severity of cyber intrusions, the Nuclear Waste Policy ActCompanies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of 1982,data and systems. In addition, Dominion and Virginia Power entered into contractsare subject to mandatory cybersecurity regulatory requirements, interface regularly with the DOE for the disposala wide range of spent nuclear fuel.external organizations, and participate in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. 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 Millstone 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. In May 2010, the stay 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 $174 million, largely offset against property, plant and equipmentcurrent security posture and regulatory assetscompliance efforts are intended to address the evolving 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 in January 2011. Payment of any damages will not occur until the appeal process has been resolved.changing cyber threats.
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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 through 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
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, droughtsChanges in weather conditions can result in reduced water levels or changes in water temperatures that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level.level or sea temperatures.
The rates of Dominion’s gas transmission and distribution operations and Virginia Power’s electric transmission, distribution and generation operations are subject to regulatory review.Revenue provided by Virginia Power’s electric transmission, distribution and generation operations and Dominion’s gas transmission and distribution operations is based primarily on rates approved by state and federal regulatory agencies. The profitability of these businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.
Virginia Power’s wholesale rates for electric transmission service are adjusted on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism, Virginia Power’s wholesale electric transmission cost of service is estimated and thereafter adjusted to reflect Virginia Power’s actual electric transmission costs incurred. These wholesale rates are subject to FERC review and prospective adjustment in the event that customers and/or interested state commissions file a complaint with FERC and are able to demonstrate that Virginia Power’s wholesale revenue requirement is no longer just and reasonable.
Similarly, various rates and charges assessed by Dominion’s gas transmission businesses are subject to review by FERC. In addition, the rates of Dominion’s gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate.
Virginia Power’s base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission on a biennial basis in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a combined two-year historic test period, and the determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances described in the Regulation Act, Virginia Power may be required to share a portion of its earnings with customers through a refund process, and the Virginia Commission may order a base rate increase or reduction during the biennial review. Additionally, Virginia
Power was required to discontinue deferral accounting for certain existing rate adjustment clauses as of December 1, 2011. As a result, Virginia Power may potentially not fully recover costs associated with these existing rate adjustment clauses.
Virginia Power’s retail electric base rates for bundled generation, transmission, and distribution services to customers in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes, and the rules and procedures of the North Carolina Commission. If retail electric earnings exceed the returns established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery through base rates, on a timely basis, of costs incurred in providing service, Virginia Power’s future earnings could be negatively impacted.
Dominion and Virginia Power are subject to complex governmental regulation that could adversely affect their results of operations.operations and subject the Companies to monetary penalties.Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. These operations are also subject to legislation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that theirthe business is conducted in accordance with applicable laws. However, newThe Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if either Dominion or Virginia Power is found not to be in compliance, including mandatory reliability standards and interaction in the wholesale markets. New laws or regulations, the revision or reinterpretation of existing laws or regulations, or penalties imposed for non-compliance with existing laws or regulations may result in substantial expense.
Dominion’s and Virginia Power’s generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. Dominion’s and Virginia Power’s generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs to make changes in market design. FERC also periodically reviews Dominion’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets, Dominion’s or Virginia Power’s authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of Dominion’s or Virginia Power’s generation business.
Dominion and Virginia Power couldinfrastructure build plans often require regulatory approval before construction can commence. Dominion and Virginia Power may not complete plant construction or expansion projects that they commence, or they may complete projects on materially different terms or timing than initially anticipated, and they may not be subjectable to penaltiesachieve 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
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future. Commencing construction on announced plants requires approvals from applicable state and federal agencies. Projects may not be able to be completed on time as a result of mandatory reliability standards. Asweather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a resultdecline in the credit strength of EPACT, ownerstheir counterparties or vendors, or other factors beyond their control. Even if plant construction and operatorsexpansion projects are completed, the total costs of generation facilitiesthe projects may be higher than anticipated and bulk electric transmission systems, includingthe performance of the business of Dominion and Virginia Power are subjectfollowing the projects may not meet expectations. Additionally, Dominion and Virginia Power may not be able to mandatory reliability standards enacted by NERCtimely and enforced by FERC. Compliance witheffectively integrate the mandatory reliability standards may subject the Companies to higher operating costsprojects into their operations and such integration may result in increased capital expenditures. If either Dominionunforeseen operating difficulties or Virginia Power is foundunanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be in compliance withprudently incurred. Any of these or other factors could adversely affect the mandatory reliability standards it could be subjectCompanies’ ability to remediation costs, as well as sanctions, including substantial monetary penalties.realize the anticipated benefits from the plant construction and expansion projects.
Dominion’s and Virginia Power’s current costs of compliance with environmental laws are significant. The costs of compliance with futureenvironmental laws, including laws and regulations designed to addressglobal climate change, air quality, coal combustion by-products, cooling water and other matters could make certain of the Companies’ generation facilities uneconomical to maintain or operate.Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and Dominion and Virginia Power expect that they will remain significant in the future.
Existing environmental laws and regulations may be revised and/or new laws may be adopted or become applicable to Domin-
ionDominion or Virginia Power. The EPA is expected to issue additional regulations with respect to air quality under the CAA, including revised NAAQS a replacementand regulations governing the emissions of the CAIR relating to NOX and SO2emissions, and a MACT rule for coal and oil-firedGHGs from electric generation plants that will likely address numerous HAPs, including mercury.generating units. Risks relating to potential regulation of GHG emissions are discussed below. Dominion and Virginia Power also expect additional federal water and waste regulations, including regulations concerning cooling water intake structures and coal combustion by-product handling and disposal practices.practices that are expected to be applicable to at least some of its generating facilities.
Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new environmental rules or regulations related to emissions.regulations. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liability on all responsible parties. However, such expenditures, if excessive,material, could make the Companies’ generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.
If additional federal and/or state requirements are imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements, suchrequirements may result in compliancecosts that alone or in combinationcombination could make some of Dominion’s or Virginia Power’s electric generationgeneration units or natural gas facilities uneconomical to maintain or operate.The U.S. Congress,EPA, environmental advocacy groups, other organizations and some state and other federal agencies are focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. Dominion and Virginia Power expect that federal legislation and/or additional EPA regulation,regulations, and possibly additional state legislation and/or regulation,regulations, may passbe issued resulting in the imposition of additional limitations on GHG emissions or requiring efficiency improvements from fossil fuel-fired electric generating units.
There are also potential impacts on Dominion’s natural gas businesses as federal or state GHG legislation andor 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 hasand Rhode Island have implemented regulations requiring reductions in CO2 emissions through RGGI, a cap and trade program covering CO2 emissions from power plants in the Northeast, which affects several of Dominion’s facilities.
Compliance with GHG emission reduction requirements may require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon capture and storage technology, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower emitting generation facilities. The cost of compliance with GHG emission legislation and/or regulation is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon capture and storage technology,
and associated regulations, and the selected compliance alternatives. As a result, theThe Companies cannot estimate the aggregate effect of any such legislationrequirements on their results of operations, financial condition or their customers. However, such expenditures, if excessive,material, could make the Companies’ generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.
The 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. That review culminated in a final order in March 2010, in which the Commission ordered that Virginia Power’s base rates be frozen at their pre-September 1, 2009 levels until December 1, 2013. In 2011, however, the Virginia Commission will commence biennial reviews of the rates and terms and conditions of Virginia Power and, in that first biennial review, may order a credit to customers for a portion of earnings more than 50 basis points above the 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 federal and state regulatory agencies. The profitability of these businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.
Virginia Power’s wholesale charges for electric transmission service are adjusted on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism, Virginia Power’s wholesale electric transmission cost of service is estimated and thereafter adjusted as appropriate to reflect actual costs allocated to Virginia Power by PJM. These wholesale rates are subject to FERC review and prospective adjustment in the event that customers and/or interested state commissions file a complaint with FERC and are able to demonstrate that Virginia Power’s wholesale revenue requirement is no longer just and reasonable.
Similarly, various rates and charges assessed by Dominion’s gas transmission businesses are subject to review by FERC. Dominion is required to file a general base rate review for the FERC-jurisdictional services of Cove Point, effective no later than July 31, 2011. At that time, Cove Point’s cost-of-service will be reviewed by the FERC, with rates set based on analyses of Cove Point’s costs and capital structure.
Dominion’s gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate.
Risks arising from the reliability of electric generation, transmission and distribution equipmentthe Companies’ facilities supply chain disruptions or personnel issues could result in lost revenues andincreased expenses, including higher maintenance costs.Operation of the Companies’ generation, transmission and distribution facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions
resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents, earthquakes and other natural disasters can disrupt generation, transmission and distributionoperation of the Companies’ facilities. Because Virginia Power’s transmission facilities are interconnected with those of third parties, the operation of its facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
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Operation of the Companies’ generation facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of generating unitsthe Companies’ facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less energyoutput or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement energy and capacityoutput from third parties in the open market to satisfy forward energy and capacity or other contractual obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.
Dominion and Virginia Power have substantial ownership interests in and operate nuclear generating units; as a result, each may incursubstantial costs and liabilities.Dominion’s and Virginia Power’s nuclear facilities are subject to operational, environmental, health and financial risks such as the on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. Dominion and Virginia Power maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If Dominion’s and Virginia Power’s decommissioning trust funds are insufficient, and they are not allowed to recover the additional costs incurred through insurance, or in the case of Virginia Power through regulatory mechanisms, their results of operations could be negatively impacted.
Dominion’s and Virginia Power’s nuclear facilities are also subject to complex government regulation which could negatively impact their results of operations. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending on its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require Dominion and Virginia Power to make substantial expenditures at their nuclear plants. In addition, although the Companies have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could materially and adversely affect their results of operations and/or financial condition. A major incident at a nuclear facility anywhere in the world, such as the nuclear events in Japan in 2011, could cause the NRC to adopt increased safety regulations or otherwise limit or restrict the operation or licensing of domestic nuclear units.
Dominion depends on third parties to produce the natural gas it gathers and processes, and the NGLs it fractionates at its facilities. A reduction in these quantities could reduce Dominion’s revenues. Dominion obtains its supply of natural gas and NGLs from numerous third-party producers. Such producers are under no obligation to deliver a specific quantity of natural gas or NGLs to Dominion’s facilities, although the producers that have con-
tracted to supply natural gas to Dominion’s natural gas processing and fractionation facility under development in Natrium, West Virginia will generally be subject to contractual minimum fee payments. If producers were to decrease the supply of natural gas or NGLs to Dominion’s systems and facilities for any reason, Dominion could experience lower revenues to the extent it is unable to replace the lost volumes on similar terms.
Dominion’s merchant power business is operating in a challenging market, which could adversely affect its results of operations and future growth.
The success of Dominion’s merchant power business depends upon favorable market conditions including the ability to purchase and sell power at prices sufficient to cover its operating costs. Dominion operates in active wholesale markets that expose it to price volatility for electricity and fuel as well as the credit risk of counterparties. Dominion attempts to manage its price risk by entering into hedging transactions, including short-term and long-term fixed price sales and purchase contracts.
In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion does not enter into long-term power purchase agreements or otherwise effectively hedge its output, then these changes in market prices could adversely affect its financial results.
Dominion purchases fuel under a variety of terms, including long-term and short-term contracts and spot market purchases. Dominion is exposed to fuel cost volatility for the portion of its fuel obtained through short-term contracts or on the spot market.market, including as a result of market supply shortages. Fuel prices can be volatile and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs, thus adversely impacting Dominion’s financial results.
Energy conservation could negatively impact Dominion’s merchant powerand Virginia Power’s financial results. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices, including lighting and electric heat pumps, could lead to declines in per capita energy consumption. To the extent conservation results in reduced energy demand or significantly slowed growth in demand, the value of the Companies’ business activities could be adversely impacted.
Exposure to counterparty performance may be negatively affectedadversely affect the Companies’ financial results of operations. Dominion and Virginia Power are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Such defaults by possible FERC actions that could weaken competition incustomers, suppliers or other third parties may adversely affect 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 elec-Companies’ financial results.
tricityMarket performance and other changes may decrease the value of decommissioning trust funds and benefit plan assets or increase Dominion’s liabilities, which could then require significant additional funding. The performance of the capital markets regulated by FERC. The wholesale markets allowaffects 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 merchant generation stations to take advantage of market price opportunities, but also expose themareas and holds significant assets in these trusts. These assets are subject to market risk. Properly functioning competitive wholesale marketsfluctuation and will yield uncertain returns, which may fall below expected return rates.
With respect to decommissioning trust funds, a decline in PJM, MISOthe market value of these assets may increase the funding requirements of the obligations to decommission Dominion’s nuclear plants or require additional NRC-approved funding assurance.
A decline in the market value of the assets held in trusts to satisfy future obligations under Dominion’s pension and ISO-NE depend upon FERC’s continuation of clearly identified market rules. From time to time FERCother postretirement benefit plans may investigate and authorize PJM, MISO and ISO-NE to makeincrease the funding requirements under such plans. Additionally, changes in market design. FERCinterest 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 periodically reviews Dominion’s authority to sell at market-based rates. Material changes by FERCincrease the funding requirements of the obligations related 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 disasterpension and other significant events could adversely affect Dominion’spostretirement benefit plans.
If the decommissioning trust funds 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 direct 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, recessionbenefit plan assets are negatively impacted by market fluctuations or other factors, could result in a significant decline in the U.S. economy, and the increased cost of insurance coverage, any of which could negatively impact the Companies’Dominion’s results of operations, and financial condition.condition and/or cash flows could be negatively affected.
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.contract or upon the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these transactions. In the absence of actively-quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the underlyingunder-lying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
The use of derivatives to hedge future sales may limit the benefit Dominion would otherwise receive from increases in commodity prices. These hedge arrangements generally include collateral requirements that require Dominion to deposit funds or post letters of credit with counterparties, financial intermediaries or clearinghouses to cover the fair value of covered contracts in excess of agreed upon credit limits. For instance, when commodity prices rise to levels substantially higher than the levels where it has hedged future sales, Dominion may be required to use a material portion of its available liquidity or obtain additional liquidity to cover these collateral requirements. In some circumstances, this could have a compounding effect on Dominion’s financial liquidity and results of operations. In addition, the availability or security of the collateral delivered by Dominion
may be adversely affected by the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these types of transactions.
Derivatives designated under hedge accounting, to the extent not fully offset by the hedged transaction, can result in ineffectiveness losses. These losses primarily result from differences between the location and/or specifications of the derivative hedging instrument and the hedged item and could adversely affect Dominion’s results of operations.
Dominion’s and Virginia Power’s operations in regards to these transactions are subject to multiple market risks including market liquidity, counterpartyprice volatility, credit strength of the Companies’ counterparties and price volatility.the financial condition of the financial intermediaries, exchanges and clearinghouses used for the types of transactions. These market risks are beyond the Companies’ control and could adversely affect their results of operations, liquidity and future growth.
The Dodd-Frank Act which was enacted into law in July 2010 in an effort to improve regulation of financial markets. The Dodd-Frank Act includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can choose to exempt their hedging transactions from these clearing and exchange trading requirements. Final rules for the over-the-counter derivatives-relatedderivative-related provisions of the Dodd-Frank Act including the clearing, exchange trading and capital and margin requirements, will continue to be established through the CFTC’songoing rulemaking process which is required to be completed by July 2011.of the applicable regulators. 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.requirements, for their derivative activities. In addition, implementation of, and compliance with, the over-the-counter derivativesderivative provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in increased costs related to the Companies’ derivative activities.
Dominion and Virginia Power may not complete plant construction or expansion projects that they commence, or they may complete projects on materially different terms or timing than initially anticipated and they may not be able to achieve the intended benefits of any such project, if completed. Several plant construction and expansion projects have been announced and additional projects may be considered in the future. Management anticipates that they will be required to seek additional financing in the future to fund current and future plant construction and expansion projects and may not be able to secure such financing on favorable terms. In addition, projects may not be able to be completed on time as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of their counterparties or vendors, or other factors beyond their control. Even if plant construction and expansion projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of Dominion and Virginia Power following the projects may
not meet expectations. Additionally, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Further, Dominion and Virginia Power may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Any of these or other factors could adversely affect their ability to realize the anticipated benefits from the plant construction and expansion projects.
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 as significant sources of funding and liquidity for capital expenditures, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or market reputation, or general financial market disruptions outside of Dominion’s and Virginia Power’s control could increase their cost of borrowing or restrict their ability to access one or more financial markets. Further market disruptions could stem from delays in the current economic recovery, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, or the failure of financial institutions on which the Companies rely. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.
Market performance and other changes may decrease the value of decommissioning trust funds and benefit plan assets or increase Dominion’s liabilities, which 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 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.In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, Dominion and Virginia Power may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in Dominion’s credit ratings or the credit ratings of Virginia Power could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require Dominion to post additional collateral in connection with some of its price risk management activities.
An inability to access financial markets could adversely affect the execution of Dominion’s and Virginia Power’s business plans.Dominion and Virginia Power rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for capital expenditures, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of Dominion’s and Virginia Power’s control could increase their cost of borrowing or restrict their
23
ability to access one or more financial markets. Further market disruptions could stem from delays in the current economic recovery, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, or the failure of financial institutions on which the Companies rely. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.
Potential changes in accounting practices may adversely affect 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.
War, acts and threats of terrorism, natural disaster and other significant events could adversely affect Dominion’s and Virginia Power’s operations. Dominion and Virginia Power cannot predict the impact that any future terrorist attacks may have on the energy industry in general, or on the Companies’ business in particular. Any retaliatory military strikes or sustained military campaign may affect the Companies’ operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets. In addition, the Companies’ infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Furthermore, the physical compromise of the Companies’ facilities could adversely affect the Companies’ ability to manage these facilities effectively. Instability in financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy and increase the cost of insurance coverage. This could negatively impact the Companies’ results of operations and financial condition.
Hostile cyber intrusions could severely impair Dominion’s and Virginia Power’s operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on Dominion’s and Virginia Power’s business. The Companies own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run the Companies’ facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or the Companies’ operations could view the Companies’ computer systems, software or networks as attractive targets for cyber attack. In addition, the Companies’ businesses require that they collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.
A successful cyber attack on the systems that control the Companies’ electric generation, electric or gas transmission or distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other
confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. The Companies maintain property and casualty insurance that may cover certain damage caused by potential cybersecurity incidents, however, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect the Companies’ business, financial condition and results of operations.
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. An aging workforce in the energy industry necessitates recruiting, retaining and developing the next generation of leadership.
Item 1B. Unresolved Staff Comments
None.
As of December 31, 2010,2012, Dominion owned its principal executive office and three other corporate offices, all located in Richmond, Virginia. Dominion also leases corporate offices in other cities in which its subsidiaries operate. Virginia Power shares its principal office in Richmond, Virginia, which is owned by Dominion. In addition, Virginia Power’s DVP and Generation segments share certain leased buildings and equipment. See Item 1. Business for additional information about each segment’s principal properties, which information is incorporated herein by reference.
Dominion’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described here and in Item 1. Business.
Substantially all of Virginia Power’s property is subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2010;2012; 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. See Item 7. MD&A for more information.
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, 2010,2012, Dominion Generation’s total utility and merchant generating capacity was 27,615approximately 27,500 MW.
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The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2010:2012:
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 | % |
Plant | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | |||||||
Coal | ||||||||||
Mt. Storm | Mt. Storm, WV | 1,599 | ||||||||
Chesterfield | Chester, VA | 1,267 | ||||||||
Virginia City Hybrid Energy Center | Wise County, VA | 600 | ||||||||
Chesapeake(1) | Chesapeake, VA | 595 | ||||||||
Clover | Clover, VA | 433 | (5) | |||||||
Yorktown(1) | Yorktown, VA | 323 | ||||||||
Bremo(2) | Bremo Bluff, VA | 227 | ||||||||
Mecklenburg | Clarksville, VA | 138 | ||||||||
Altavista(3),(4) | Altavista, VA | 63 | ||||||||
Hopewell(4) | Hopewell, VA | 63 | ||||||||
Southampton(4) | Southampton, VA | 63 | ||||||||
Total Coal | 5,371 | 28 | % | |||||||
Gas | ||||||||||
Ladysmith (CT) | Ladysmith, VA | 783 | ||||||||
Remington (CT) | Remington, VA | 608 | ||||||||
Bear Garden (CC) | Buckingham County, VA | 590 | ||||||||
Possum Point (CC) | Dumfries, VA | 559 | ||||||||
Chesterfield (CC) | Chester, VA | 397 | ||||||||
Elizabeth River (CT) | Chesapeake, VA | 348 | ||||||||
Possum Point | Dumfries, VA | 316 | ||||||||
Bellemeade (CC) | Richmond, VA | 267 | ||||||||
Gordonsville Energy (CC) | Gordonsville, VA | 218 | ||||||||
Gravel Neck (CT) | Surry, VA | 170 | ||||||||
Darbytown (CT) | Richmond, VA | 168 | ||||||||
Rosemary (CC) | Roanoke Rapids, NC | 165 | ||||||||
Total Gas | 4,589 | 23 | ||||||||
Nuclear | ||||||||||
Surry | Surry, VA | 1,678 | ||||||||
North Anna | Mineral, VA | 1,668 | (6) | |||||||
Total Nuclear | 3,346 | 17 | ||||||||
Oil | ||||||||||
Yorktown | Yorktown, VA | 818 | ||||||||
Possum Point | Dumfries, VA | 786 | ||||||||
Gravel Neck (CT) | Surry, VA | 198 | ||||||||
Darbytown (CT) | Richmond, VA | 168 | ||||||||
Possum Point (CT) | Dumfries, VA | 72 | ||||||||
Chesapeake (CT) | Chesapeake, VA | 51 | ||||||||
Low Moor (CT) | Covington, VA | 48 | ||||||||
Northern Neck (CT) | Lively, VA | 47 | ||||||||
Total Oil | 2,188 | 11 | ||||||||
Hydro | ||||||||||
Bath County | Warm Springs, VA | 1,802 | (7) | |||||||
Gaston | Roanoke Rapids, NC | 220 | ||||||||
Roanoke Rapids | Roanoke Rapids, NC | 95 | ||||||||
Other | Various | 3 | ||||||||
Total Hydro | 2,120 | 11 | ||||||||
Biomass | ||||||||||
Pittsylvania | Hurt, VA | 83 | — | |||||||
Various | ||||||||||
Other | Various | 11 | — | |||||||
17,708 | ||||||||||
Power Purchase Agreements | 1,887 | 10 | ||||||||
Total Utility Generation | 19,595 | 100 | % |
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) |
(2) | Planned to convert to gas subject to necessary regulatory approvals. |
(3) | Facility has been placed into cold reserve status, but can be restarted within a reasonably short period if necessary. |
In the first quarter of 2012, the facility received regulatory approval to convert to biomass. |
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(5) | Excludes 50% undivided interest owned by ODEC. |
(6) | 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 Capability | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | ||||||||||||||||
Coal | ||||||||||||||||||||||
Kincaid | Kincaid, IL | 1,158 | (1) | |||||||||||||||||||
Brayton Point | Somerset, MA | 1,105 | ||||||||||||||||||||
State Line | Hammond, IN | 515 | ||||||||||||||||||||
Salem Harbor | Salem, MA | 314 | ||||||||||||||||||||
Morgantown | Morgantown, WV | 25 | (1),(2) | |||||||||||||||||||
Total Coal | 3,117 | 34 | % | |||||||||||||||||||
Nuclear | ||||||||||||||||||||||
Millstone | Waterford, CT | 2,016 | (3) | Waterford, CT | 2,016 | (5) | ||||||||||||||||
Kewaunee | Kewaunee, WI | 556 | ||||||||||||||||||||
Kewaunee(1) | Kewaunee, WI | 556 | ||||||||||||||||||||
Total Nuclear | 2,572 | 28 | 2,572 | 33 | % | |||||||||||||||||
Gas | ||||||||||||||||||||||
Fairless (CC) | Fairless Hills, PA | 1,196 | (4) | |||||||||||||||||||
Elwood (CT) | Elwood, IL | 712 | (1),(5) | |||||||||||||||||||
Fairless (CC)(2),(3) | Fairless Hills, PA | 1,196 | ||||||||||||||||||||
Elwood (CT)(2),(4) | Elwood, IL | 712 | (6) | |||||||||||||||||||
Manchester (CC) | Providence, RI | 432 | Providence, RI | 432 | ||||||||||||||||||
Total Gas | 2,340 | 25 | 2,340 | 30 | ||||||||||||||||||
Coal | ||||||||||||||||||||||
Kincaid(2),(4) | Kincaid, IL | 1,158 | ||||||||||||||||||||
Brayton Point(4) | Somerset, MA | 1,083 | ||||||||||||||||||||
Total Coal | 2,241 | 28 | ||||||||||||||||||||
Oil | ||||||||||||||||||||||
Salem Harbor | Salem, MA | 438 | ||||||||||||||||||||
Brayton Point | Somerset, MA | 440 | ||||||||||||||||||||
Brayton Point(4) | Somerset, MA | 435 | ||||||||||||||||||||
Total Oil | 878 | 10 | 435 | 6 | ||||||||||||||||||
Wind | ||||||||||||||||||||||
Fowler Ridge | Benton County, IN | 150 | (1),(6) | |||||||||||||||||||
NedPower Mt. Storm | Grant County, WV | 132 | (1),(7) | |||||||||||||||||||
Fowler Ridge(2) | Benton County, IN | 150 | (7) | |||||||||||||||||||
NedPower Mt. Storm(2) | Grant County, WV | 132 | (8) | |||||||||||||||||||
Total Wind | 282 | 3 | 282 | 3 | ||||||||||||||||||
Various | ||||||||||||||||||||||
Other | Various | 8 | — | |||||||||||||||||||
Brayton Point(4),(9) | Somerset, MA | 10 | — | |||||||||||||||||||
Total Merchant Generation | 9,197 | 100 | % | 7,880 | 100 | % |
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) |
(2) |
(3) | Includes generating units that Dominion operates under leasing arrangements. |
(4) | In the third quarter of 2012, Dominion announced its decision to pursue the sale of Brayton Point, Kincaid and its 50% interest in Elwood. |
(5) | Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and |
(6) | Excludes 50% membership interest owned by |
(7) | Excludes 50% membership interest owned by BP. |
(8) | Excludes 50% membership interest owned by Shell. |
(9) | Represents four diesel generators. |
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,the Companies, or permits issued by various local, state andand/or federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Companies and their subsidiaries are involved in various legal proceedings. 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 February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming new source review violations new source performance standards violations,of the CAA New Source Review requirements, NSPS, and Title V permit program violations pursuant toand the CAA and thestations’ 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 cannot predict the outcome 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 CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at Brayton Point and Salem Harbor.Point. Dominion submitted its response to the request in November 20102010.
Dominion believes that it complied with applicable laws and cannot predict the EPA regulations and interpretations in effect at the time the work in question took place. The CAA authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. In addition to any such penalties that may be awarded, an adverse outcome could require substantial capital expenditures or affect the timing of this matter.currently budgeted capital expenditures. Dominion is currently in settlement discussions to resolve these matters. However, there can be no assurance that Dominion will reach a settlement with the EPA. Dominion does not believe that final resolution of the matter will have a material adverse effect on its results of operations, financial condition or cash flows.
See Notes 13 and 22 to the Consolidated Financial Statements andFuture Issues and Other Mattersin MD&A, which information is incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which the Companies are a party.
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Executive Officers of Dominion
Information concerning the executive officers of Dominion, each of whom is elected annually, is as follows:
Name and Age | Business Experience Past Five Years(1) | |
Thomas F. Farrell II | 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 | |
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 | |
Paul D. Koonce | Executive Vice President and Chief Executive Officer – Energy Infrastructure Group of Dominion from | |
David A. Christian | Executive Vice President and Chief Executive Officer – Dominion Generation Group of Dominion from February 2013 to date; President and COO of Virginia Power from June 2009 to date; Executive Vice President of Dominion from May 2011 to February 2013; President and CNO of Virginia Power from October 2007 to May | |
David A. Heacock | President and CNO of Virginia Power from June 2009 to date; Senior Vice President of Dominion and President and | |
Gary L. Sypolt | Executive Vice President of Dominion from May 2011 to date; President of DTI from June 2009 to date; | |
Robert M. Blue | Senior Vice | |
Steven A. Rogers | Senior Vice President and Chief Administrative Officer of Dominion | |
Ashwini Sawhney | Vice |
(1) | Any service listed for Virginia Power, |
(2) | Steven A. Rogers ceased to be an executive officer of Dominion as of January 1, 2013. |
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Dominion
Dominion’s common stock is listed on the NYSE. At January 31, 2011,2013, there were approximately 144,000139,000 record holders of Dominion’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion’s direct stock purchase and dividend reinvestment plan.Dominion Direct. Discussions of theexpected dividend payments and restrictions on Dominion’s payment of dividends required by this Item are contained inDividend RestrictionsLiquidity and Capital Resources in Item 7. MD&A and Notes 1817 and 2120 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 20102012 and 2009.2011. Quarterly information concerning stock prices and dividends is disclosed in Note 2826 to the Consolidated Financial Statements, which information is incorporated herein by reference.
The following table presents certain information with respect to Dominion’s common stock repurchases during the fourth quarter of 2010.2012:
DOMINION PURCHASESOF EQUITY SECURITIES
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 |
Period | Total Number of Shares (or Units) Purchased(1) | Average Price Paid per Share (or Unit)(2) | Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(3) | ||||||||||||
10/1/2012-10/31/12 | 467 | $ | 52.81 | N/A | 19,629,059 shares/$ | 1.18 billion | ||||||||||
11/1/2012-11/30/12 | — | $ | — | N/A | 19,629,059 shares/$ | 1.18 billion | ||||||||||
12/1/2012-12/31/12 | — | $ | — | N/A | 19,629,059 shares/$ | 1.18 billion | ||||||||||
Total | 467 | $ | 52.81 | N/A | 19,629,059 shares/$ | 1.18 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. The aggregate authorization granted by the Dominion Board of Directors was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion. |
Virginia Power
There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion. Restrictions on Virginia Power’s payment of dividends are discussed 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 | ||||||||||||||||
(millions) | ||||||||||||||||||||
2010 | $ | 108 | $ | 81 | $ | 171 | $ | 140 | $ | 500 | ||||||||||
2009 | 101 | 75 | 190 | 97 | 463 |
Item 6. Selected Financial Data
Dominion
Year Ended December 31, | 2010 | 2009(1) | 2008(1) | 2007(1) | 2006(1) | |||||||||||||||
(millions, except per share amounts) | ||||||||||||||||||||
Operating revenue | $ | 15,197 | $ | 14,798 | $ | 15,895 | $ | 14,456 | $ | 16,893 | ||||||||||
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) | (155 | ) | 26 | 190 | 36 | (345 | ) | |||||||||||||
Extraordinary item, net of tax(2) | — | — | — | (158 | ) | — | ||||||||||||||
Net income attributable to Dominion | 2,808 | 1,287 | 1,834 | 2,539 | 1,380 | |||||||||||||||
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 | 42,817 | 42,554 | 42,053 | 39,139 | 49,296 | |||||||||||||||
Long-term debt | 15,758 | 15,481 | 14,956 | 13,235 | 14,791 |
2010 results include a $1.4 billion after-tax net income benefit from the sale of substantially all of Dominion’s Appalachian E&P operations, net of charges related to the divestiture and a $206 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, as discussed in Notes 4 and 23 to the Consolidated Financial Statements, respectively. Also in 2010, Dominion recorded $127 million of after-tax impairment charges at certain merchant generation facilities, as discussed in Note 7 to the Consolidated Financial Statements. The loss from discontinued operations in 2010 includes a $140 million after-tax loss on the sale of Peoples.
2009 results include a $435 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings discussed in Note 14 to the Consolidated Financial Statements. Also in 2009, Dominion recorded a $281 million after-tax ceiling test impairment charge related to the carrying value of its E&P properties.
2008 results include $109 million of after-tax charges reflecting other-than-temporary declines in the fair value of certain securities held as investments in nuclear decommissioning trusts. In addition, income from discontinued operations in 2008 includes a $120 million after-tax benefit due to the reversal of deferred tax liabilities associated with the sale of Peoples.
2007 results include a $1.5 billion after-tax benefit from the disposition of Dominion’s non-Appalachian E&P operations and a $252 million after-tax impairment charge associated with the sale of Dresden. Also in 2007, Dominion recorded a $137 million after-tax charge resulting from the termination of the long-term power sales agreement associated with State Line. In addition, the reapplication of accounting guidance for cost-based rate regulation to the Virginia jurisdiction of Virginia Power’s generation operations in 2007 resulted in a $158 million after-tax extraordinary charge.
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 includes a $164 million after-tax impairment charge to reduce the facilities’ carrying amounts to their estimated fair values less cost to sell.
Virginia Power
There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion. Restrictions on Virginia Power’s payment of dividends are discussed inDividend Restrictions in Item 7. MD&A and Note 20 to the Consolidated Financial Statements. Virginia Power paid quarterly cash dividends on its common stock as follows:
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 |
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year | ||||||||||||||||
(millions) | ||||||||||||||||||||
2012 | $ | 149 | $ | 120 | $ | 110 | $ | 180 | $ | 559 | ||||||||||
2011 | 131 | 118 | 199 | 109 | 557 |
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Item 6. Selected Financial Data
DOMINION
Year Ended December 31, | 2012 | 2011 | 2010 | 2009 | 2008 | |||||||||||||||
(millions, except per share amounts) | ||||||||||||||||||||
Operating revenue | $ | 13,093 | $ | 14,145 | $ | 14,927 | $ | 14,575 | $ | 15,594 | ||||||||||
Income from continuing operations, net of tax(1) | 324 | 1,433 | 3,066 | 1,276 | 1,599 | |||||||||||||||
Income (loss) from discontinued operations, net of tax(1) | (22 | ) | (25 | ) | (258 | ) | 11 | 235 | ||||||||||||
Net income attributable to Dominion | 302 | 1,408 | 2,808 | 1,287 | 1,834 | |||||||||||||||
Income from continuing operations before loss from discontinued operations per common share-basic | 0.57 | 2.50 | 5.21 | 2.15 | 2.76 | |||||||||||||||
Net income attributable to Dominion per common share-basic | 0.53 | 2.46 | 4.77 | 2.17 | 3.17 | |||||||||||||||
Income from continuing operations before loss from discontinued operations per common share-diluted | 0.57 | 2.49 | 5.20 | 2.15 | 2.75 | |||||||||||||||
Net income attributable to Dominion per common share-diluted | 0.53 | 2.45 | 4.76 | 2.17 | 3.16 | |||||||||||||||
Dividends declared per common share | 2.11 | 1.97 | 1.83 | 1.75 | 1.58 | |||||||||||||||
Total assets | 46,838 | 45,614 | 42,817 | 42,554 | 42,053 | |||||||||||||||
Long-term debt | 16,851 | 17,394 | 15,758 | 15,481 | 14,956 |
(1) | Amounts attributable to Dominion’s common shareholders. |
2012 results include a $1.0 billion after-tax impairment charge due to bids received for Brayton Point and Kincaid and a $303 million after-tax charge primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013.
2011 results include a $139 million after-tax charge reflecting generation plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units and a $59 million after-tax charge reflecting restoration costs associated with damage caused by Hurricane Irene.
2010 results include a $1.4 billion after-tax net income benefit from the sale of substantially all of Dominion’s Appalachian E&P operations, net of charges related to the divestiture and a $202 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, as discussed in Notes 3 and 22 to the Consolidated Financial Statements, respectively. The loss from discontinued operations in 2010 includes $127 million of after-tax impairment charges at certain merchant generation facilities and a $140 million after-tax loss on the sale of Peoples.
2009 results include a $435 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings. Also in 2009, Dominion recorded a $281 million after-tax ceiling test impairment charge related to the carrying value of its Appalachian E&P properties.
2008 results include $109 million of after-tax charges reflecting other-than-temporary declines in the fair value of certain securities held as investments in nuclear decommissioning trusts. In addition, income from discontinued operations in 2008 includes a $120 million after-tax benefit due to the reversal of deferred tax liabilities associated with the sale of Peoples.
VIRGINIA POWER
Year Ended December 31, | 2012 | 2011 | 2010 | 2009 | 2008 | |||||||||||||||
(millions) | ||||||||||||||||||||
Operating revenue | $ | 7,226 | $ | 7,246 | $ | 7,219 | $ | 6,584 | $ | 6,934 | ||||||||||
Net income | 1,050 | 822 | 852 | 356 | 864 | |||||||||||||||
Balance available for common stock | 1,034 | 805 | 835 | 339 | 847 | |||||||||||||||
Total assets | 24,811 | 23,544 | 22,262 | 20,118 | 18,802 | |||||||||||||||
Long-term debt | 6,251 | 6,246 | 6,702 | 6,213 | 6,000 |
2012 results include a $53 million after-tax charge reflecting restoration costs associated with damage caused by severe storms.
2011 results include a $139 million after-tax charge reflecting generation plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired generating units and a $59 million after-tax charge reflecting restoration costs associated with damage caused by Hurricane Irene.
2010 results include a $123 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, discussed in Note 2322 to the Consolidated Financial Statements.
2009 results include a $427 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings discussed in Note 14 to the Consolidated Financial Statements.
2007 results reflect the reapplication of accounting guidance for cost-based rate regulation to the Virginia jurisdiction of Virginia Power’s generation operations, which resulted in a $158 million after-tax extraordinary charge.proceedings.
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 | Selected Information—Energy Trading Activities |
Ÿ | Liquidity and Capital Resources |
Ÿ | Future Issues and Other Matters |
FORWARD-LOOKING STATEMENTS
This report contains statements concerning Dominion’s and Virginia Power’s expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words.
Dominion and Virginia Power make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:
Ÿ | Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; |
Ÿ | Extreme weather events and other natural disasters, including hurricanes, high winds, |
Ÿ | Federal, state and local legislative and regulatory developments; |
Ÿ | Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances; |
Ÿ | Cost of environmental compliance, including those costs related to climate change; |
Ÿ | Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; |
Ÿ | Unplanned outages of the Companies’ facilities; |
Ÿ | Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Dominion’s and Virginia Power’s liquidity position and the underlying value of their assets; |
Ÿ | Counterparty credit and performance risk; |
Ÿ | Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; |
Ÿ | Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; |
Ÿ | Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion; |
Ÿ | Fluctuations in interest rates; |
Ÿ | Changes in federal and state tax laws and regulations; |
Ÿ | Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; |
Ÿ | Changes in financial or regulatory accounting principles or policies imposed by governing bodies; |
Ÿ | Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; |
Ÿ |
|
Ÿ | Impacts of acquisitions, divestitures and retirements of assets based on asset portfolio reviews; |
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 |
Ÿ |
|
Ÿ | Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, |
Ÿ | Additional competition in the electric industry, including in electric markets in which Dominion’s merchant generation facilities |
Ÿ | Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; |
Ÿ | Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion; |
Ÿ | Timing and receipt of regulatory approvals necessary for planned construction or expansion projects; |
Ÿ | The inability to complete planned construction projects within the terms and time frames initially anticipated; and |
Ÿ | Adverse outcomes in litigation |
Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
ACCOUNTING MATTERS
Critical Accounting Policies and Estimates
Dominion and Virginia Power have identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to their financial condition or results of operations under different conditions or using different assumptions. Dominion and Virginia Power have discussed the development, selection and disclosure of each of these policies with the Audit CommitteeCommittees of their BoardBoards of Directors. Virginia Power’s Board of Directors also serves as its Audit Committee.
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.
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. The Companies currently believe the recovery of their regulatory assets is probable. See Notes 1312 and 1413 to the Consolidated Financial Statements.Statements for additional information.
ASSET RETIREMENT OBLIGATIONS
Dominion and Virginia Power recognize liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists.exists and the ARO can be reasonably estimated. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, the Companies estimate the fair value of their AROs using present value techniques, in which they make various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. 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, 20092012, 2011 and 2008,2010, Dominion recognized $85$77 million, $89$84 million and $94$85 million, respectively, of accretion, and expects to recognize $81$88 million in 2011.2013. In 2010, 20092012, 2011 and 2008,2010, Virginia Power recognized $35$34 million, $35$36 million and $38$35 million, respectively, of accretion, and expects to recognize $37$38 million in 2011.2013. Virginia Power records accretion and depreciation associated with utility nuclear decommissioning AROs as an adjustment to its regulatory liability for nuclear decommissioning.
A significant portion of the Companies’ AROs relates to the future decommissioning of Dominion’s merchant and Virginia
Power’s utility nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2010,2012, Dominion’s nuclear decommissioning AROs totaled $1.4$1.5 billion, representing approximately 87%86% of its total AROs. At December 31, 2010,2012, Virginia Power’s nuclear decommissioning AROs totaled $620$633 million, representing approximately 92%90% 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 resultThe selection of the updated decommissioningthese cost studies and applicable escalation rates obtained in 2009,is dependent on subjective factors which are considered to be a critical assumption.
In September 2012, Dominion recorded a decreasean increase 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$246 million in the nuclear decommissioning AROs for its units. The ARO revision was primarily driven by management’s decision to cease operations and begin decommissioning Kewaunee in 2013. Virginia Power recorded an increase of $43 million in the nuclear decommissioning AROs for its units. The ARO revision was driven by an increase in estimated costs. In December 2011, Dominion recorded a decrease of $290 million in the nuclear decommissioning AROs for its units. Virginia Power recorded a decrease of $95 million in the nuclear decommissioning AROs for its units. The ARO revision in 2011 was driven by a reduction in anticipated future decommissioning costs due to the expected future recovery from the DOE of certain spent fuel costs based on the Companies’ contracts with the DOE for disposal of spent nuclear fuel, as well as updated escalation rates.
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.
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Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2010,2012, Dominion had $307$293 million and Virginia Power had $117$57 million of unrecognized tax benefits. For a 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 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 quar-
terlyquarterly the probability of realizing deferred tax assets by reviewing a forecast ofconsidering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. The Companies establish a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2010,2012, Dominion had established $68$93 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 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 76 and 2221 to the Consolidated Financial Statements for further information on these fair value measurements.
Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, the Companies consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, the Companies must estimate prices based on available historical and near-term future price information and use of statistical methods, including regression analysis, that reflect their market assumptions.
The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
USEOF ESTIMATESIN GOODWILL IMPAIRMENT TESTING
As of December 31, 2010,2012, Dominion reported $3.1 billion of goodwill in its Consolidated Balance Sheet. A significant portion resulted from the acquisition of the former CNG in 2000.
In April of each year, Dominion tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2010, 20092012, 2011 and 20082010 annual tests and any interim tests did not result in the recognition of any goodwill impairment.
In general, Dominion estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving
peer group companies. For Dominion’s Appalachian E&P operations and Peoples and Hope and certain DCI operations, negotiated sales prices were used as fair value for the tests conducted in 2010, 2009 and 2008.2010. 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 1211 to the Consolidated Financial Statements for additional information.
USEOF ESTIMATESIN LONG--LLIVEDIVED ASSET IMPAIRMENT TESTING
Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about operating the long-lived assets and the
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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.consumed and expected proceeds from dispositions. See Note 76 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets.
EMPLOYEE BENEFIT PLANS
Dominion sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit
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 | Expected inflation and risk-free interest rate assumptions; |
Ÿ | Historical return analysis to determine |
Ÿ | Expected future risk premiums, asset volatilities and correlations; |
Ÿ | Forward-looking return expectations derived from the yield on long-term bonds and the |
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Ÿ | Investment allocation of plan assets. The strategic target asset allocation for Dominion’s pension funds is 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments, such as private equity investments. |
Strategic investment policies are established for 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. Future asset/
liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns.
Dominion develops assumptions, which are then compared to the forecasts of otheran independent investment advisorsadvisor 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, 20092012, 2011 and 2008.2010. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 7.75% for 2010, 20092012, 2011 and 2008.2010. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets.
Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost were 5.50% in 2012, 5.90% in 2011 and 6.60% in 2010 and 2009, compared to 6.60% and 6.50%, respectively, in 2008.2010. Dominion selected a discount rate of 5.90%4.40% for determining its December 31, 20102012 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, 2010 is 7.0%2012 was 7% and is expected to gradually decrease to 4.60% by 20602061 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 | )% | $ | 13 | $ | 5 | (0.25 | )% | $ | 17 | $ | 4 | ||||||||||||
Long-term rate of return on plan assets | (0.25 | )% | 13 | 3 | (0.25 | )% | 13 | 3 | ||||||||||||||||
Healthcare cost trend rate | 1.00 | % | N/A | 23 | 1 | % | N/A | 17 |
In addition to the effects on cost, at December 31, 2010,2012, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $138$219 million and its accumulated postretirement benefit obligation by $52$54 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $217$218 million. See Note 2221 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 amountsamount 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
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Power’s customer receivables included $397$348 million and $355$360 million of accrued unbilled revenue at December 31, 20102012 and 2009,2011, 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 and 2008, Dominion and Virginia Power were required to adopt several new accounting standards, which are discussed in Note 3 to the Consolidated Financial Statements.
DOMINION
RESULTSOF OPERATIONS
Presented below is a summary of Dominion’s consolidated results:
Year Ended December 31, | 2010 | $ Change | 2009 | $ Change | 2008 | 2012 | $ Change | 2011 | $ Change | 2010 | ||||||||||||||||||||||||||||||
(millions, except EPS) | ||||||||||||||||||||||||||||||||||||||||
Net Income attributable to Dominion | $ | 2,808 | $ | 1,521 | $ | 1,287 | $ | (547 | ) | $ | 1,834 | $ | 302 | $ | (1,106 | ) | $ | 1,408 | $ | (1,400 | ) | $ | 2,808 | |||||||||||||||||
Diluted EPS | 4.76 | 2.59 | 2.17 | (0.99 | ) | 3.16 | 0.53 | (1.92 | ) | 2.45 | (2.31 | ) | 4.76 |
Overview
20102012VS. 20092011
Net income attributable to Dominion increaseddecreased by 118%79%. Unfavorable drivers include impairment and other charges related to bids received for Brayton Point and Kincaid and management’s decision to cease operations and begin decommissioning Kewaunee in 2013. Favorable drivers include the absence of an impairment charge related to certain utility coal-fired power stations and the absence of restoration costs associated with damage caused by Hurricane Irene recorded in 2011.
2011VS. 2010
Net income attributable to Dominion decreased by 50%. Unfavorable drivers include the absence of a gain on the sale of Dominion’s Appalachian E&P operations, lower 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 proceedingsmargins from merchant generation operations, and the impact of less favorable weather, including Hurricane Irene, on electric utility operations. UnfavorableFavorable drivers include the absence of charges related to a workforce reduction program and the absence of a loss on the sale of Peoples, lower marginsand higher earnings 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 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.adjustment clauses.
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:
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These increases were partially offset by:
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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Other operations and maintenance increased $12 million primarily reflecting:
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These increases were partially offset by:
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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:
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These decreases were partially offset by:
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Other operations and maintenance expense increased 13%, primarily reflecting the combined effects of:
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These increases were partially offset by:
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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 (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:
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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 |
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 |
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 | $ | — |
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 |
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 |
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 |
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 | ) |
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 |
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’sDominion’s results of operations:
Year Ended December 31, | 2010 | $ Change | 2009 | $ Change | 2008 | 2012 | $ Change | 2011 | $ Change | 2010 | ||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
Operating Revenue | $ | 7,219 | $ | 635 | $ | 6,584 | $ | (350 | ) | $ | 6,934 | $ | 13,093 | $ | (1,052 | ) | $ | 14,145 | $ | (782 | ) | $ | 14,927 | |||||||||||||||||
Electric fuel and other energy-related purchases | 2,495 | (477 | ) | 2,972 | 265 | 2,707 | 3,748 | (349 | ) | 4,097 | 63 | 4,034 | ||||||||||||||||||||||||||||
Purchased electric capacity | 449 | 40 | 409 | (1 | ) | 410 | 387 | (67 | ) | 454 | 1 | 453 | ||||||||||||||||||||||||||||
Purchased gas | 1,177 | (587 | ) | 1,764 | (285 | ) | 2,049 | |||||||||||||||||||||||||||||||||
Net Revenue | 4,275 | 1,072 | 3,203 | (614 | ) | 3,817 | 7,781 | (49 | ) | 7,830 | (561 | ) | 8,391 | |||||||||||||||||||||||||||
Other operations and maintenance | 1,745 | 122 | 1,623 | 218 | 1,405 | 4,868 | 1,546 | 3,322 | (126 | ) | 3,448 | |||||||||||||||||||||||||||||
Depreciation and amortization | 671 | 30 | 641 | 33 | 608 | |||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 1,186 | 120 | 1,066 | 31 | 1,035 | |||||||||||||||||||||||||||||||||||
Other taxes | 218 | 27 | 191 | 8 | 183 | 571 | 23 | 548 | 24 | 524 | ||||||||||||||||||||||||||||||
Gain on sale of Appalachian E&P operations | — | — | — | (2,467 | ) | 2,467 | ||||||||||||||||||||||||||||||||||
Other income | 100 | (4 | ) | 104 | 52 | 52 | 223 | 45 | 178 | 8 | 170 | |||||||||||||||||||||||||||||
Interest and related charges | 347 | (2 | ) | 349 | 40 | 309 | 882 | 15 | 867 | 41 | 826 | |||||||||||||||||||||||||||||
Income tax expense | 542 | 395 | 147 | (353 | ) | 500 | 146 | (608 | ) | 754 | (1,358 | ) | 2,112 | |||||||||||||||||||||||||||
Loss from discontinued operations | (22 | ) | 3 | (25 | ) | 233 | (258 | ) |
An analysis of Dominion’s results of operations follows:
2012VS. 2011
Net Revenue decreased 1%, primarily reflecting:
Ÿ | A $161 million decrease from merchant generation operations, primarily reflecting a decrease in realized prices; and |
Ÿ | A $144 million decrease from regulated natural gas distribution operations primarily reflecting decreased rider revenue ($117 million) related to low income assistance programs. |
These decreases were partially offset by:
Ÿ | A $184 million increase from electric utility operations, primarily reflecting: |
Ÿ | The impact of rate adjustment clauses ($138 million); |
Ÿ | The absence of a charge recorded in 2011 based on the Biennial Review Order to refund revenues to customers ($81 million); and |
Ÿ | A decrease in net capacity expenses ($31 million); partially offset by |
Ÿ | The impact ($58 million) of a decrease in sales to retail customers, primarily due to a decrease in cooling and heating degree days ($184 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($126 million); |
Ÿ | A $57 million increase in retail energy marketing activities primarily due to price risk management activities; and |
Ÿ | A $6 million increase from regulated natural gas transmission operations, primarily due to new transportation assets placed in service. |
35
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
An analysis of Virginia Power’s results ofOther operations follows:
2010VS. 2009
Net Revenueand maintenance increased 33%47%, primarily reflecting:
|
|
|
|
These increases were partially offset by:
Ÿ | A |
Other operations and maintenance increased 8%, primarily reflecting:
|
Ÿ | A |
Ÿ | A |
These increases were partially offset by:
Ÿ | The absence of |
Ÿ | A $117 million |
Ÿ | The absence of |
Depreciation, depletion and amortization expense increased 5%11%, primarily due to property additions.
Other taxesIncome increased 14%25%, 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).realized gains (including investment income) on nuclear decommissioning trust funds.
Income tax expense increased $395 million,decreased 81%, primarily reflecting higher pretaxlower pre-tax income in 2010.2012.
20092011VS. 20082010
Net Revenue decreased 16%, primarily due to a charge for the settlement of the 2009 base rate case proceedings.
Other operations and maintenance expense increased 16%7%, primarily reflecting:
Ÿ | A |
Ÿ | A |
|
|
These increasesdecreases were partially offset by:
Ÿ | A |
Ÿ | A $28 million increase in producer services primarily related to higher physical margins and favorable price changes on economic hedging positions, all associated with natural gas aggregation, marketing and trading activities; |
Ÿ | A $13 million increase from electric utility operations, primarily reflecting: |
Ÿ | The impact of rate adjustment clauses ($169 million); and |
Ÿ | A decrease |
Ÿ | The impact ($120 million) of a decrease in sales to retail customers, primarily due to a decrease in heating and cooling degree days ($220 million), partially offset by an increase in sales due to the |
Ÿ | A decrease due to a charge based on the Biennial Review Order to refund revenues to customers ($81 million). |
DepreciationOther operations and amortization expensemaintenance increased 5%,decreased 4% primarily reflecting:
Ÿ | A $434 million decrease in salaries, wages and benefits primarily related to a 2010 workforce reduction program; partially offset by |
Ÿ | A $228 million impairment charge related to certain utility coal-fired generating units; and |
Ÿ | A $96 million increase due to restoration costs associated with damage caused by Hurricane Irene. |
Gain on sale of Appalachian E&P operations reflects a gain on the sale of these operations, as described in Note 3 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.Consolidated Financial Statements.
Interest and related charges increased 13%5%, primarily due to the absence of a $23 million benefit related torecorded in 2010 resulting from the redemptiondiscontinuance of Virginia Power’s Callablehedge accounting for certain interest rate derivatives ($73 million) and Puttable Enhanced Securitiesan increase in 2008, anddebt issuances in 2011 ($18 million), partially offset by the recognition of hedging gains that had previously been deferred as regulatory liabilities as a $17 million impact largely due toresult of the impact from additional borrowings.Biennial Review Order ($50 million).
Income tax expense decreased 71%64%, primarily reflecting lower pre-tax incomefederal and state taxes largely due to the absence of a gain from the sale of Dominion’s Appalachian E&P operations recorded in 2009.2010.
Loss from discontinued operations reflects the sale of Peoples in 2010, as well as losses associated with State Line and Salem Harbor, which were reclassified to discontinued operations as a result of their sale in 2012.
Outlook
Virginia Power expectsDominion’s strategy is to continue focusing on its regulated businesses while maintaining upside potential in well-positioned nonregulated businesses. The goals of this strategy are to provide earnings per share growth, a growing dividend and to maintain a stable credit profile. Dominion is in the process of transitioning to a more regulated earnings mix, and is targeting 80-90 percent of its earnings to come from regulated businesses in 2013 and beyond. This is evidenced by Dominion’s capital investments in regulated infrastructure, as well as its disposition of certain merchant generation facilities during 2012 and its announcement that certain other merchant generation facilities are expected to be sold or decommissioned in 2013.
In 2013, Dominion is expected to experience an increase in net income in 2011. Virginia Power’son a per share basis as compared to 2012. Dominion’s anticipated 20112013 results reflect the following significant factors:
Ÿ |
|
|
|
|
Ÿ | A return to normal weather in its electric utility |
Ÿ | Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue, as well as full-year earnings from gas transmission and gas distribution projects placed in service in 2012; and |
Ÿ | Growth in weather-normalized electric utility sales of approximately 2% resulting from the recovering economy and rising energy demand; partially offset by |
Ÿ | An increase in interest expense; |
Ÿ | Increases in certain operations and maintenance expense; and |
Ÿ | An increase in depreciation, depletion and amortization. |
Virginia Power alsoOn January 2, 2013, U.S. federal legislation was enacted that provides an extension of the 50 percent bonus depreciation allowance for qualifying capital expenditures incurred through 2013, as discussed in Note 5 to the Consolidated Financial Statements. Dominion 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 $600resulting in cash savings in 2013 and 2014 of approximately $250 million to $1.2 billion during 2011 through 2013. The acceleration of these tax deductions is expected to reduceand $350 million, respectively.
36 |
SEGMENT RESULTSOF OPERATIONS
Segment results include the domestic production activities income tax deduction through 2012 and will also increase deferred taxes, thereby reducing the regulated rate base. However, Virginia Power plans to partially mitigate the earnings impact of these itemsintersegment revenues and expenses, which may result in intersegment profit or loss. Presented below is a summary of contributions by usingDominion’s operating segments to net income attributable to Dominion:
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||||||||||||||
Net Income | Diluted EPS | Net Income | Diluted EPS | Net Income | Diluted EPS | |||||||||||||||||||
(millions, except EPS) | ||||||||||||||||||||||||
DVP | $ | 559 | $ | 0.98 | $ | 501 | $ | 0.87 | $ | 448 | $ | 0.76 | ||||||||||||
Dominion Generation | 874 | 1.52 | 968 | 1.68 | 1,263 | 2.14 | ||||||||||||||||||
Dominion Energy | 551 | 0.96 | 521 | 0.91 | 475 | 0.80 | ||||||||||||||||||
Primary operating segments | 1,984 | 3.46 | 1,990 | 3.46 | 2,186 | 3.70 | ||||||||||||||||||
Corporate and Other | (1,682 | ) | (2.93 | ) | (582 | ) | (1.01 | ) | 622 | 1.06 | ||||||||||||||
Consolidated | $ | 302 | $ | 0.53 | $ | 1,408 | $ | 2.45 | $ | 2,808 | $ | 4.76 |
DVP
Presented below are operating statistics related to DVP’s operations:
Year Ended December 31, | 2012 | % Change | 2011 | % Change | 2010 | |||||||||||||||
Electricity delivered (million MWh) | 80.8 | (2 | )% | 82.3 | (3 | )% | 84.5 | |||||||||||||
Degree days: | ||||||||||||||||||||
Cooling | 1,787 | (6 | ) | 1,899 | (9 | ) | 2,090 | |||||||||||||
Heating | 2,955 | (12 | ) | 3,354 | (12 | ) | 3,819 | |||||||||||||
Average electric distribution customer accounts (thousands)(1) | 2,455 | 1 | 2,438 | 1 | 2,422 | |||||||||||||||
Average retail energy marketing customer accounts (thousands)(1) | 2,129 | (1 | ) | 2,152 | 6 | 2,037 |
(1) | Thirteen-month average. |
Presented below, on an after-tax basis, are the cash tax savingskey factors impacting DVP’s net income contribution:
2012VS. 2011
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Regulated electric sales: | ||||||||
Weather | $ | (34 | ) | $ | (0.06 | ) | ||
Other | 28 | 0.05 | ||||||
FERC transmission equity return | 19 | 0.04 | ||||||
Retail energy marketing operations | 35 | 0.06 | ||||||
Storm damage and service restoration(1) | 14 | 0.03 | ||||||
Other | (4 | ) | (0.01 | ) | ||||
Change in net income contribution | $ | 58 | $ | 0.11 |
(1) | Excludes restoration costs associated with damage caused by severe storms in 2012 and 2011, which are reflected in the Corporate and Other segment. |
2011VS. 2010
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Regulated electric sales: | ||||||||
Weather | $ | (43 | ) | $ | (0.07 | ) | ||
Other | 10 | 0.02 | ||||||
FERC transmission equity return | 44 | 0.07 | ||||||
Retail energy marketing operations | 6 | 0.01 | ||||||
Storm damage and service restoration(1) | 9 | 0.02 | ||||||
Other operations and maintenance expense(2) | 28 | 0.04 | ||||||
Other | (1 | ) | — | |||||
Share accretion | — | 0.02 | ||||||
Change in net income contribution | $ | 53 | $ | 0.11 |
(1) | Excludes restoration costs associated with damage caused by Hurricane Irene which are reflected in the Corporate and Other segment. |
(2) | Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses. |
Dominion Generation
Presented below are operating statistics related to reduceDominion Generation’s operations:
Year Ended December 31, | 2012 | % Change | 2011 | % Change | 2010 | |||||||||||||||
Electricity supplied (million MWh): | ||||||||||||||||||||
Utility | 80.8 | (2 | )% | 82.3 | (3 | )% | 84.5 | |||||||||||||
Merchant(1) | 41.4 | (4 | ) | 43.0 | (9 | ) | 47.3 | |||||||||||||
Degree days (electric utility service area): | ||||||||||||||||||||
Cooling | 1,787 | (6 | ) | 1,899 | (9 | ) | 2,090 | |||||||||||||
Heating | 2,955 | (12 | ) | 3,354 | (12 | ) | 3,819 |
(1) | Includes 13.2, 17.3, and 22.7 million MWh for the years ended December 31, 2012, 2011, and 2010, respectively, related to Kewaunee, State Line, Salem Harbor, Brayton Point, Kincaid, and Dominion’s 50% interest in Elwood. |
Presented below, on an after-tax basis, are the amountkey factors impacting Dominion Generation’s net income contribution:
2012VS. 2011
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Merchant generation margin | $ | (109 | ) | $ | (0.19 | ) | ||
Regulated electric sales: | ||||||||
Weather | (78 | ) | (0.14 | ) | ||||
Other | 46 | 0.08 | ||||||
Brayton Point, Kincaid and Elwood third and fourth quarter 2011 earnings(1) | 7 | 0.01 | ||||||
Rate adjustment clause equity return | 17 | 0.03 | ||||||
PJM ancillary services | (27 | ) | (0.05 | ) | ||||
Net capacity expenses | 19 | 0.04 | ||||||
Outage costs | 8 | 0.01 | ||||||
Other | 23 | 0.05 | ||||||
Change in net income contribution | $ | (94 | ) | $ | (0.16 | ) |
(1) | Brayton Point’s, Kincaid’s and Elwood’s third and fourth quarter 2012 results of operations have been reflected in the Corporate and Other segment due to Dominion’s decision, in the third quarter of 2012, to pursue the sale of Brayton Point, Kincaid, and its 50% interest in Elwood. |
37
Management’s Discussion and Analysis of debt that would have otherwise been issued over the next three years.Financial Condition and Results of Operations, Continued
2011VS. 2010
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Merchant generation margin | $ | (278 | ) | $ | (0.48 | ) | ||
Regulated electric sales: | ||||||||
Weather | (91 | ) | (0.16 | ) | ||||
Other | 59 | 0.10 | ||||||
Rate adjustment clause equity return | 30 | 0.05 | ||||||
Outage costs | (11 | ) | (0.01 | ) | ||||
Other operations and maintenance expenses(1) | 72 | 0.13 | ||||||
Depreciation and amortization | (7 | ) | (0.01 | ) | ||||
Interest expense | (18 | ) | (0.03 | ) | ||||
Kewaunee 2010 earnings(2) | (19 | ) | (0.03 | ) | ||||
Other | (32 | ) | (0.06 | ) | ||||
Share accretion | — | 0.04 | ||||||
Change in net income contribution | $ | (295 | ) | $ | (0.46 | ) |
(1) | Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses. |
(2) | Kewaunee’s 2011 results of operations have been reflected in the Corporate and Other segment due to Dominion’s decision, in the first quarter of 2011, to pursue a sale of the power station. In 2012, Dominion decided to cease operations and begin decommissioning the facility in 2013. |
Dominion Energy
Presented below are selected operating statistics related to Dominion Energy’s operations. As discussed in Note 3, 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, | 2012 | % Change | 2011 | % Change | 2010 | |||||||||||||||
Gas distribution throughput (bcf): | ||||||||||||||||||||
Sales | 26 | (13 | )% | 30 | (3 | )% | 31 | |||||||||||||
Transportation | 259 | 2 | 253 | 5 | 241 | |||||||||||||||
Heating degree days | 4,986 | �� | (11 | ) | 5,584 | (2 | ) | 5,682 | ||||||||||||
Average gas distribution customer accounts (thousands)(1): | ||||||||||||||||||||
Sales | 251 | (2 | ) | 256 | (2 | ) | 260 | |||||||||||||
Transportation | 1,044 | — | 1,040 | — | 1,042 |
(1) | Thirteen-month average. |
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:
2012VS. 2011
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Weather | $ | (5 | ) | $ | (0.01 | ) | ||
Producer services margin | (13 | ) | (0.02 | ) | ||||
Gas transmission margin(1) | 8 | 0.01 | ||||||
Gain from sale of assets to Blue Racer | 43 | 0.08 | ||||||
Other | (3 | ) | (0.01 | ) | ||||
Change in net income contribution | $ | 30 | $ | 0.05 |
(1) | Primarily reflects placing the Appalachian Gateway Project into service. |
2011VS. 2010
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Producer services margin | $ | 18 | $ | 0.03 | ||||
Gas transmission margin(1) | 15 | 0.03 | ||||||
Other operations and maintenance expenses(2) | 11 | 0.02 | ||||||
Gas distribution margin: | ||||||||
AMR and PIR revenue | 9 | 0.02 | ||||||
Base gas sales | (4 | ) | (0.01 | ) | ||||
E&P disposed operations | (17 | ) | (0.03 | ) | ||||
Other | 14 | 0.02 | ||||||
Share accretion | — | 0.03 | ||||||
Change in net income contribution | $ | 46 | $ | 0.11 |
(1) | Primarily reflects an increase in revenue from NGLs. |
(2) | Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses. |
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results:
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
(millions, except EPS amounts) | ||||||||||||
Specific items attributable to operating segments | $ | (1,442 | ) | $ | (340 | ) | $ | 1,042 | ||||
Specific items attributable to Corporate and Other segment: | ||||||||||||
Peoples discontinued operations | — | — | (155 | ) | ||||||||
Other | (5 | ) | 29 | (22 | ) | |||||||
Total specific items | (1,447 | ) | (311 | ) | 865 | |||||||
Other corporate operations | (235 | ) | (271 | ) | (243 | ) | ||||||
Total net benefit (expense) | $ | (1,682 | ) | $ | (582 | ) | $ | 622 | ||||
EPS impact | $ | (2.93 | ) | $ | (1.01 | ) | $ | 1.06 |
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 25 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, | 2012 | $ Change | 2011 | $ Change | 2010 | |||||||||||||||
(millions) | ||||||||||||||||||||
Net Income | $ | 1,050 | $ | 228 | $ | 822 | $ | (30 | ) | $ | 852 |
Overview
2012VS. 2011
Net income increased by 28%. Favorable drivers include the absence of an impairment charge related to certain coal-fired
38 |
power stations recorded in 2011, the impact of rate adjustment clauses, and the absence of restoration costs associated with damage caused by Hurricane Irene recorded in 2011. Unfavorable drivers include the impact of less favorable weather and the restoration costs associated with damage caused by severe storms.
2011VS. 2010
Net income decreased by 4%, primarily reflecting less favorable weather, including Hurricane Irene, and an impairment charge related to certain coal-fired power stations, partially offset by higher earnings from rate adjustment clauses and the absence of charges related to a workforce reduction program.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Power’s results of operations:
Year Ended December 31, | 2012 | $ Change | 2011 | $ Change | 2010 | |||||||||||||||
(millions) | ||||||||||||||||||||
Operating Revenue | $ | 7,226 | $ | (20 | ) | $ | 7,246 | $ | 27 | $ | 7,219 | |||||||||
Electric fuel and other energy-related purchases | 2,368 | (138 | ) | 2,506 | 11 | 2,495 | ||||||||||||||
Purchased electric capacity | 386 | (66 | ) | 452 | 3 | 449 | ||||||||||||||
Net Revenue | 4,472 | 184 | 4,288 | 13 | 4,275 | |||||||||||||||
Other operations and maintenance | 1,466 | (277 | ) | 1,743 | (2 | ) | 1,745 | |||||||||||||
Depreciation and amortization | 782 | 64 | 718 | 47 | 671 | |||||||||||||||
Other taxes | 232 | 10 | 222 | 4 | 218 | |||||||||||||||
Other income | 96 | 8 | 88 | (12 | ) | 100 | ||||||||||||||
Interest and related charges | 385 | 54 | 331 | (16 | ) | 347 | ||||||||||||||
Income tax expense | 653 | 113 | 540 | (2 | ) | 542 |
An analysis of Virginia Power’s results of operations follows:
2012VS. 2011
Net Revenue increased 4%, primarily reflecting:
Ÿ | The impact of rate adjustment clauses ($138 million); |
Ÿ | The absence of a charge recorded in 2011 based on the Biennial Review Order to refund revenues to customers ($81 million); and |
Ÿ | A decrease in net capacity expenses ($31 million); partially offset by |
Ÿ | The impact ($58 million) of a decrease in sales to retail customers, primarily due to a decrease in cooling and heating degree days ($184 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($126 million). |
Other operations and maintenance decreased 16%, primarily reflecting:
Ÿ | The absence of an impairment charge recorded in 2011 related to certain coal-fired generating units ($228 million); and |
Ÿ | The absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene ($96 million); partially offset by |
Ÿ | A $64 million increase in storm damage and service restoration costs primarily due to the damage caused by severe storms in 2012. |
Interest and related charges increased 16%, primarily due to the absence of the recognition of hedging gains into income in 2011, that had been deferred as regulatory liabilities, as a result of the Biennial Review Order.
Income tax expense increased 21%, primarily reflecting higher pre-tax income in 2012.
2011VS. 2010
Net Revenue increased $13 million, primarily reflecting:
Ÿ | The impact of rate adjustment clauses ($169 million); and |
Ÿ | A decrease in net capacity expenses ($44 million); partially offset by |
Ÿ | The impact ($120 million) of a decrease in sales to retail customers, primarily due to a decrease in heating and cooling degree days ($220 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($100 million); and |
Ÿ | A decrease due to a charge based on the Biennial Review Order to refund revenues to customers ($81 million). |
Other operations and maintenance decreased $2 million, primarily reflecting:
Ÿ | A $267 million decrease in salaries, wages and benefits as well as certain administrative and general costs primarily due to a 2010 workforce reduction program; and |
Ÿ | A $54 million decrease in planned outage costs primarily due to fewer scheduled outage days at certain generation facilities; partially offset by |
Ÿ | A $228 million impairment charge related to certain coal-fired generating units; and |
Ÿ | A $96 million increase due to restoration costs associated with damage caused by Hurricane Irene. |
Other income decreased 12%, primarily due to a decrease in the equity component of AFUDC ($17 million), partially offset by an increase in amounts collectible from customers for taxes in connection with contributions in aid of construction ($5 million).
Outlook
Virginia Power expects to provide growth in net income in 2013. Virginia Power’s anticipated 2013 results reflect the following significant factors:
Ÿ | A return to normal weather; |
Ÿ | Growth in weather-normalized electric sales of approximately 2% resulting from the recovering economy and rising energy demand; and |
Ÿ | Construction and operation of growth projects and associated rate adjustment clause revenue; partially offset by |
Ÿ | Increases in certain operations and maintenance expense; and |
Ÿ | An increase in depreciation, depletion and amortization. |
On January 2, 2013, U.S. federal legislation was enacted that provides an extension of the 50 percent bonus depreciation allowance for qualifying capital expenditures incurred through
2013, as discussed in Note 5 to the Consolidated Financial
39
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Statements. Virginia Power expects the bonus depreciation provisions to reduce income taxes otherwise payable, resulting in cash savings in 2013 and 2014 of approximately $200 million and $250 million, respectively.
SEGMENT RESULTSOF OPERATIONS
Presented below is a summary of contributions by Virginia Power’s operating segments to net income:
Year Ended December 31, | 2010 | $ Change | 2009 | $ Change | 2008 | |||||||||||||||
(millions) | ||||||||||||||||||||
DVP | $ | 377 | $ | 64 | $ | 313 | $ | 6 | $ | 307 | ||||||||||
Dominion Generation | 630 | 155 | 475 | (108 | ) | 583 | ||||||||||||||
Primary operating segments | 1,007 | 219 | 788 | (102 | ) | 890 | ||||||||||||||
Corporate and Other | (155 | ) | 277 | (432 | ) | (406 | ) | (26 | ) | |||||||||||
Consolidated | $ | 852 | $ | 496 | $ | 356 | $ | (508 | ) | $ | 864 |
Year Ended December 31, | 2012 | $ Change | 2011 | $ Change | 2010 | |||||||||||||||
(millions) | ||||||||||||||||||||
DVP | $ | 448 | $ | 22 | $ | 426 | $ | 49 | $ | 377 | ||||||||||
Dominion Generation | 653 | (11 | ) | 664 | 34 | 630 | ||||||||||||||
Primary operating segments | 1,101 | 11 | 1,090 | 83 | 1,007 | |||||||||||||||
Corporate and Other | (51 | ) | 217 | (268 | ) | (113 | ) | (155 | ) | |||||||||||
Consolidated | $ | 1,050 | $ | 228 | $ | 822 | $ | (30 | ) | $ | 852 |
DVP
Presented below are operating statistics related to Virginia Power’s DVP segment:
Year Ended December 31, | 2010 | % Change | 2009 | % Change | 2008 | 2012 | % Change | 2011 | % Change | 2010 | ||||||||||||||||||||||||||||||
Electricity delivered (million MWh) | 84.5 | 4% | 81.4 | (3 | )% | 84.0 | 80.8 | (2 | )% | 82.3 | (3 | )% | 84.5 | |||||||||||||||||||||||||||
Degree days (electric service area): | ||||||||||||||||||||||||||||||||||||||||
Cooling | 2,090 | 42 | 1,477 | (9 | ) | 1,621 | 1,787 | (6 | ) | 1,899 | (9 | ) | 2,090 | |||||||||||||||||||||||||||
Heating | 3,819 | 2 | 3,747 | 9 | 3,426 | 2,955 | (12 | ) | 3,354 | (12 | ) | 3,819 | ||||||||||||||||||||||||||||
Average electric distribution customer accounts (thousands) | 2,422 | 1 | 2,404 | 1 | 2,386 | 2,455 | 1 | 2,438 | 1 | 2,422 | ||||||||||||||||||||||||||||||
(1) |
Thirteen-month average. |
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
20102012VS. 20092011
Increase (Decrease) | Increase (Decrease) | |||||||
(millions, except EPS) | ||||||||
Regulated electric sales: | ||||||||
Weather | $ | 48 | $ | (34 | ) | |||
FERC transmission revenue | 40 | |||||||
Other | (4 | ) | 28 | |||||
Depreciation and amortization | (15 | ) | ||||||
Storm damage and service restoration—distribution operations(1) | (11 | ) | ||||||
FERC transmission equity return | 19 | |||||||
Storm damage and service restoration(1) | 14 | |||||||
Other | 6 | (5 | ) | |||||
Change in net income contribution | $ | 64 | $ | 22 |
(1) |
20092011VS. 20082010
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 |
Increase (Decrease) | ||||
(millions) | ||||
Regulated electric sales: | ||||
Weather | $ | (43 | ) | |
Other | 10 | |||
FERC transmission equity return | 44 | |||
Storm damage and service restoration(1) | 9 | |||
Other operations and maintenance expense(2) | 28 | |||
Other | 1 | |||
Change in net income contribution | $ | 49 |
(1) |
(2) |
Dominion Generation
Presented below are operating statistics related to Virginia Power’s Dominion Generation segment:
Year Ended December 31, | 2010 | % Change | 2009 | % Change | 2008 | 2012 | % Change | 2011 | % Change | 2010 | ||||||||||||||||||||||||||||||
Electricity supplied (million MWh) | 84.5 | 4% | 81.4 | (3)% | 84.0 | 80.8 | (2 | )% | 82.3 | (3 | )% | 84.5 | ||||||||||||||||||||||||||||
Degree days (electric service area): | ||||||||||||||||||||||||||||||||||||||||
Cooling | 2,090 | 42 | 1,477 | (9) | 1,621 | 1,787 | (6 | ) | 1,899 | (9 | ) | 2,090 | ||||||||||||||||||||||||||||
Heating | 3,819 | 2 | 3,747 | 9 | 3,426 | 2,955 | (12 | ) | 3,354 | (12 | ) | 3,819 | ||||||||||||||||||||||||||||
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
20102012VS. 20092011
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 |
Increase (Decrease) | ||||
(millions) | ||||
Regulated electric sales: | ||||
Weather | $ | (78 | ) | |
Other | 46 | |||
Rate adjustment clause equity return | 17 | |||
PJM ancillary services | (27 | ) | ||
Net capacity expenses | 19 | |||
Other | 12 | |||
Change in net income contribution | $ | (11 | ) |
20092011VS. 20082010
Increase (Decrease) | ||||
(millions) | ||||
Outage costs | $ | (36 | ) | |
PJM ancillary services | (21 | ) | ||
Sale of emissions allowances | (17 | ) | ||
Interest expense | (15 | ) | ||
Depreciation expense | (13 | ) | ||
Regulated electric sales: | ||||
Customer growth | 10 | |||
Rate adjustment clause revenue(1) | 53 | |||
Other(2) | (59 | ) | ||
Other | (10 | ) | ||
Change in net income contribution | $ | (108 | ) |
Increase (Decrease) | ||||
(millions) | ||||
Regulated electric sales: | ||||
Weather | $ | (91 | ) | |
Other | 59 | |||
Rate adjustment clause equity return | 30 | |||
Outage costs | 33 | |||
Other | 3 | |||
Change in net income contribution | $ | 34 |
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results.results:
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||||
(millions) | ||||||||||||
Specific items attributable to operating segments | $ | (153 | ) | $ | (430 | ) | $ | (23 | ) | |||
Other corporate operations | (2 | ) | (2 | ) | (3 | ) | ||||||
Total net expense | $ | (155 | ) | $ | (432 | ) | $ | (26 | ) |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
(millions) | ||||||||||||
Specific items attributable to operating segments | $ | (51 | ) | $ | (268 | ) | $ | (153 | ) | |||
Other corporate operations | — | — | (2 | ) | ||||||||
Total net expense | $ | (51 | ) | $ | (268 | ) | $ | (155 | ) |
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 2725 to the Consolidated Financial Statements for a discussion of these items.
SELECTED INFORMATION—ENERGY TRADING ACTIVITIES
Dominion engages in energy trading, marketing and hedging activities to complement its businesses and facilitate its price 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, 2011 | $ | 20 | ||
Contracts realized or otherwise settled during the period | 3 | |||
Change in unrealized gains and losses | 55 | |||
Net unrealized gain at December 31, 2012 | $ | 78 |
The balance of net unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes at December 31, 2012, is summarized in the following table based on the approach used to determine fair value:
Maturity Based on Contract Settlement or Delivery Date(s) | ||||||||||||||||||||
Sources of Fair Value | 2013 | 2014—2015 | 2016—2017 | 2018 and thereafter | Total | |||||||||||||||
(millions) | ||||||||||||||||||||
Prices actively quoted—Level 1(1) | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Prices provided by other external sources—Level 2(2) | 59 | 26 | 2 | — | 87 | |||||||||||||||
Prices based on models and other valuation methods—Level 3(3) | 1 | (6 | ) | (4 | ) | — | (9 | ) | ||||||||||||
Total | $ | 60 | $ | 20 | $ | (2 | ) | $ | — | $ | 78 |
(1) | Values represent observable unadjusted quoted prices for traded instruments in active markets. |
(2) | Values with inputs that are observable directly or indirectly for the instrument, but do not qualify for Level 1. |
(3) | Values with a significant amount of inputs that are not observable for the instrument. |
LIQUIDITYAND CAPITAL RESOURCES
Dominion and Virginia Power depend on both internal and external sources of liquidity to provide working capital and as a bridge to fund capital requirements.long-term debt financings. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.
At December 31, 2010,2012, Dominion had $2$1.1 billion of unused capacity under its credit facilities, including $559$256 million of unused capacity under joint credit facilities available to Virginia Power. See additional discussion underCredit Facilities and Short-Term Debt.
The disposition of certain merchant generation facilities during 2012 and the expected sale or decommissioning of certain other merchant generation facilities in 2013 are not expected to negatively impact Dominion’s liquidity.
A summary of Dominion’s cash flows is presented below:
Year Ended December 31, | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Cash and cash equivalents at beginning of year | $ | 50 | $ | 71 | $ | 287 | $ | 102 | $ | 62 | $ | 50 | ||||||||||||
Cash flows provided by (used in): | ||||||||||||||||||||||||
Operating activities | 1,825 | 3,786 | 2,676 | 4,137 | 2,983 | 1,825 | ||||||||||||||||||
Investing activities | 419 | (3,695 | ) | (3,490 | ) | (3,840 | ) | (3,321 | ) | 419 | ||||||||||||||
Financing activities | (2,232 | ) | (112 | ) | 598 | (151 | ) | 378 | (2,232 | ) | ||||||||||||||
Net increase (decrease) in cash and cash equivalents | 12 | (21 | ) | (216 | ) | |||||||||||||||||||
Net increase in cash and cash equivalents | 146 | 40 | 12 | |||||||||||||||||||||
Cash and cash equivalents at end of year | $ | 62 | $ | 50 | $ | 71 | $ | 248 | $ | 102 | $ | 62 |
41
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
A summary of Virginia Power’s cash flows is presented below:
Year Ended December 31, | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Cash and cash equivalents at beginning of year | $ | 19 | $ | 27 | $ | 49 | $ | 29 | $ | 5 | $ | 19 | ||||||||||||
Cash flows provided by (used in): | ||||||||||||||||||||||||
Operating activities | 1,409 | 1,970 | 1,235 | 2,706 | 2,024 | 1,409 | ||||||||||||||||||
Investing activities | (2,425 | ) | (2,568 | ) | (2,003 | ) | (2,282 | ) | (1,947 | ) | (2,425 | ) | ||||||||||||
Financing activities | 1,002 | 590 | 746 | (425 | ) | (53 | ) | 1,002 | ||||||||||||||||
Net decrease in cash and cash equivalents | (14 | ) | (8 | ) | (22 | ) | ||||||||||||||||||
Net increase (decrease) in cash and cash equivalents | (1 | ) | 24 | (14 | ) | |||||||||||||||||||
Cash and cash equivalents at end of year | $ | 5 | $ | 19 | $ | 27 | $ | 28 | $ | 29 | $ | 5 |
Operating Cash Flows
In 2010,2012, net cash provided by Dominion’s operating activities decreasedincreased by approximately $2$1.2 billion, primarily due to lowerhigher deferred fuel and gas cost recoveries contributionsin its Virginia jurisdiction, lower margin collateral requirements, changes in other working capital items and income tax refunds in 2012 as compared to Dominion’s pension plans, the absence of disposed Appalachian E&P operations,income tax payments in 2011. The increase was partially offset by lower merchant generation margins and refunds related to the 2009 Virginia Power base rate case settlement, partially offset
by lower income tax payments, lower margin collateral requirements and the favorable impact of weather and rate adjustment clauses on electric utility operations.less favorable weather.
In 2010,2012, net cash provided by Virginia Power’s operating activities decreasedincreased by $561$682 million, primarily due to lowerhigher deferred fuel cost recoveries in its Virginia jurisdiction refunds related to the 2009 Virginia base rate case settlement, and contributions to Dominion’s pension plans;net changes in other working capital items, partially offset by the favorable impact of weather and rate adjustment clauses, and cash received for income tax benefitspayments in 2010,2012 as compared to income taxes paidtax refunds in 2009.
Dominion’s lower income tax payments2011 and Virginia Power’s realizationthe impact 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.less favorable weather.
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 2011,2012, Dominion’s boardBoard of directorsDirectors adopted a new dividend policy that raised its target payout ratio. The Boardratio to 65-70%, and established an annual dividend rate for 2013 of $1.97$2.25 per share of common stock, a 7.7%6.6% increase over the 20102012 rate. QuarterlyDeclarations of dividends are subject to declaration by the Board.further Board of Directors approval. 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, and which are discussed in Item 1A. Risk Factors.
CREDIT RISK
Dominion’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion’s credit exposure as of December 31, 20102012 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized onon- 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) | $ | 426 | $ | 26 | $ | 400 | $ | 281 | $ | — | $ | 281 | ||||||||||||
Non-investment grade(2) | 10 | 3 | 7 | 4 | — | 4 | ||||||||||||||||||
No external ratings: | ||||||||||||||||||||||||
Internally rated-investment grade(3) | 102 | — | 102 | 113 | — | 113 | ||||||||||||||||||
Internally rated-non-investment grade(4) | 82 | — | 82 | 114 | — | 114 | ||||||||||||||||||
Total | $ | 620 | $ | 29 | $ | 591 | $ | 512 | $ | — | $ | 512 |
(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 |
Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers and iswas not considered material at December 31, 2010.2012.
Investing Cash Flows
In 2010, net cash provided by Dominion’s investing activities was $419 million as compared to2012, net cash used in Dominion’s investing activities of $3.7 billion in 2009. This change isincreased by $519 million, primarily due to higher capital expenditures, mainly related to investments in growth projects, and lower restricted cash reimbursements for the purpose of funding certain qualifying construction projects, partially offset by proceeds received from the sale of substantially all of Dominion’s Appalachian E&P operationsassets, primarily related to Blue Racer, in April 2010 and the sale 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 sales are reported in cash flow from investing activities.2012.
In 2010,2012, net cash used in Virginia Power’s investing activities decreasedincreased by $143$335 million, primarily due to lowerhigher capital expenditures partially offset by an increase inand lower restricted cash equivalents designated to financereimbursements for the purpose of funding certain qualifying facilities.construction projects.
Financing Cash Flows and Liquidity
Dominion and Virginia Power rely on 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 registrationregistra-
42 |
tion statements to register any offering of securities, other than those for exchange offers or business combination transactions.
In 2010,2012, net cash used in Dominion’s financing activities increased by $2.1 billion, primarily due to net debt repayments in 2010was $151 million as compared to net cash provided by financing activities of $378 million in 2011, primarily reflecting lower net debt issuances in 2009, and net2012 as compared to 2011 as a result of higher cash flow from operations, partially offset by the absence of the repurchases of common stock recorded in 2010 as compared to issuances of common stock in 2009. This reflects the use of proceeds from the sales of Dominion’s Appalachian E&P operations and Peoples.2011.
In 2010,2012, net cash provided byused in Virginia Power’s financing activities increased by $412$372 million, primarily due to higherreflecting lower net debt issuances in 20102012 as compared to 2009,2011 as a result of lowerhigher 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 financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties. Dominion and Virginia Power replaced certain of their existing credit facilities in 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.
DOMINIONDominion
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 |
December 31, 2012 | Facility Limit | Outstanding Commercial Paper | Outstanding Letters of Credit | Facility Capacity Available | ||||||||||||
(millions) | ||||||||||||||||
Joint revolving credit facility(1) | $ | 3,000 | $ | 2,412 | $ | — | $ | 588 | ||||||||
Joint revolving credit facility(2) | 500 | — | 26 | 474 | ||||||||||||
Total | $ | 3,500 | $ | 2,412 | (3) | $ | 26 | $ | 1,062 |
(1) |
(2) |
(3) | The weighted-average interest rate of the outstanding commercial paper supported by Dominion’s credit facilities was |
VIRGINIA POWERVirginia 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 and Virginia Power and for other general corporate purposes.
Virginia Power’s share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion, 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 |
December 31, 2012 | Facility Sub-limit | Outstanding Commercial Paper | Outstanding Letters of Credit | Facility Sub-limit Capacity Available | ||||||||||||
(millions) | ||||||||||||||||
Joint revolving credit facility(1) | $ | 1,000 | $ | 992 | $ | — | $ | 8 | ||||||||
Joint revolving credit facility(2) | 250 | — | 2 | 248 | ||||||||||||
Total | $ | 1,250 | $ | 992 | (3) | $ | 2 | $ | 256 |
(1) |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
(2) |
(3) | The weighted-average interest rate of the outstanding commercial paper supported by these credit facilities was |
In addition to the credit facility commitments mentioned above, Virginia Power also has a three-year $120 million credit facility thatfacility. Effective September 2012, the maturity date was entered into inextended from September 2010. The2016 to September 2017. This facility which terminates in September 2013, supports certain tax-exempt financings of Virginia Power.
SHORT-TERM NOTES
In November and December 2012, Dominion issued $250 million and $150 million, respectively, of private placement short-term notes that mature in November 2013 and bear interest at a variable rate. The proceeds were used for general corporate purposes.
LONG-T-ERMTERM DEBT
During 2010,2012, 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 | $ | 250 | 2.25 | % | 2015 | Dominion | $ | 350 | 1.40 | % | 2017 | Dominion | ||||||||||||||||||||
Senior notes | 300 | 3.45 | % | 2022 | Virginia Power | 350 | 2.75 | % | 2022 | Dominion | ||||||||||||||||||||||
Senior notes | 350 | 4.05 | % | 2042 | Dominion | |||||||||||||||||||||||||||
Senior notes | 450 | 2.95 | % | 2022 | Virginia Power | |||||||||||||||||||||||||||
Total notes issued | $ | 550 | $ | 1,500 |
In November 2010,December 2011, Virginia Power borrowed $105$75 million in connection with the IndustrialEconomic Development Authority of Wisethe County Solid Wasteof Chesterfield Pollution Control Refunding Revenue
43
Management’s Discussion and Sewage Disposal Revenue Analysis of Financial Condition and Results of Operations, Continued
Bonds, Series 20102011 A, which mature in 20402017 and bear interest during the initial period at a couponvariable rate of 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 will bewere used to finance certain qualifying facilities atrefund the Virginia 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 Authorityprincipal amount 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 bonds upon issuance with the intention of remarketing them to third parties at a later time. The proceeds will be used to finance certain qualifying facilities at the Virginia City Hybrid Energy Center. At December 31, 2010, these bonds had not been remarketed and thus are not reflected on the Consolidated Balance Sheets.
In December 2010, Virginia Power borrowed $100 million in connection with the Industrial Development Authority of Halifaxthe County of Chesterfield, Virginia Recovery Zone FacilityMoney Market MunicipalsTM Pollution Control 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.
In December 2010, Brayton Point borrowed approximately $160 million and approximately $75 million in connection with the Massachusetts Development Finance Agency Recovery Zone Facility Bonds, Series 20101987 A and the Solid Waste Disposal Revenue Bonds, Series 20101987 B respectively, which maturethat would otherwise have matured in 2041 and bear interest during 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.June 2017.
During 2010,2012, Dominion and Virginia Power repaid and repurchased $1.5$1.7 billion and $347$641 million, respectively, of long-term debt and notes payable.debt.
ISSUANCEOF COMMON STOCK
Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2012, Dominion began issuing new common shares for these direct stock purchase plans.
During 2010,2012, Dominion issued 2.3approximately 6.4 million shares of common stock forthrough various programs. Dominion received cash proceeds of $74 million. The$265 million from the issuance of 5.3 million of such shares issued and cash proceeds received during 2010 were through Dominion Direct,®, employee savings plans, and the exercise of employee stock options.
In January 2012, Dominion doesfiled a new SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at the market program. Dominion entered into four separate Sales Agency Agreements to effect sales under the program. However, with the exception of issuing approximately $318 million in equity through employee savings plans, direct stock purchase and dividend reinvestment plans, converted securities and other employee and director benefit plans, Dominion did not currently plan any market issuances ofissue common stock in 2011 or 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.
In 2010,2012, Virginia Power issued 33,013did not issue any shares of its common stock to Dominion for approximately $1 billion. The proceeds were used to pay down short-term demand note borrowings from Dominion.
REPURCHASE OFOF COMMON STOCK
In March 2010, Dominion began repurchasing commondid not repurchase any shares in anticipation of proceeds from the sale of its 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 intends2012 and does not plan to repurchase between $400 million and $700 million of commonshares during 2013, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted 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.which do not count against its stock repurchase authorization.
BORROWINGS FROM PARENT
Virginia Power has the ability to borrow funds from Dominion under both short-term and long-term borrowing arrangements andarrangements. Virginia Power’s short-term demand note borrowings from Dominion were $243 million at December 31, 2010, its2012. There were no long-term borrowings from Dominion at December 31, 2012. At December 31, 2012, Virginia Power’s nonregulated subsidiaries had outstanding borrowings, net of repayments, under the Dominion money pool of $24$192 million. Virginia Power’s short-term demand note borrowings from Dominion 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.
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 of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.
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 solely 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 23, 201122, 2013 follow:
Fitch | Moody’s | Standard & Poor’s | ||||||||||
Dominion | ||||||||||||
Senior unsecured debt securities | BBB+ | Baa2 | A- | |||||||||
Junior subordinated debt securities | BBB- | Baa3 | BBB | |||||||||
Enhanced junior subordinated notes | BBB- | Baa3 | BBB | |||||||||
Commercial paper | F2 | P-2 | A-2 | |||||||||
Virginia Power | ||||||||||||
Mortgage bonds | A | A1 | A | |||||||||
Senior unsecured (including tax-exempt) debt securities | A- | A3 | A- | |||||||||
Junior subordinated debt securities | BBB | Baa1 | BBB | |||||||||
Preferred stock | BBB | Baa2 | BBB | |||||||||
Commercial paper | F2 | P-2 | A-2 |
As of February 23, 2011,22, 2013, Fitch, Moody’s and Standard & Poor’s maintained a stable outlook for their respective ratings of Dominion and 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 investment 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, theThe Companies may find it necessary to modify their business plans to maintain or achieve appropriate credit ratings and such changes may adversely affect growth and EPS.
Debt Covenants
As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion 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
44 |
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, 2010,2012, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:
Company | Maximum Allowed Ratio | Actual Ratio(1) | Maximum Allowed Ratio | Actual Ratio(1) | ||||||||||||
Dominion | 65 | % | 54 | % | 65 | % | 60 | % | ||||||||
Virginia Power | 65 | % | 46 | % | 65 | % | 46 | % |
(1) | Indebtedness as defined by the bank agreements excludes junior subordinated notes reflected as long-term debt or securities due within one year 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 fails to make payment on various debt obligations in excess of $100 million, the lenders could require that company to accelerate its repayment of any outstanding borrowings under the credit 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 agreements.
Dominion executed RCCs in connection with its issuance of the following hybrid securities:
Ÿ | June 2006 hybrids; |
Ÿ | September 2006 hybrids; and |
Ÿ | June 2009 hybrids. |
UnderSee Note 17 to the Consolidated Financial Statements for terms of the RCCs, Dominion covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids
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, 2010,2012, the termination dates and covered debt under the RCCs associated with Dominion’s hybrids arewere as follows:
Hybrid | RCC Termination Date | Designated Covered Debt Under RCC | ||||||
June 2006 hybrids | 6/30/2036 | September 2006 hybrids | ||||||
September 2006 hybrids | 9/30/2036 | June 2006 hybrids | ||||||
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, 2010,2012, there have been no events of default under or changes to Dominion’s or Virginia Power’s debt covenants.
Virginia Power Mortgage Supplement
Substantially all of Virginia Power’s property is subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. In July 2012, Virginia Power entered into a supplement to the indenture in order to amend various of its terms and conditions and to incorporate certain new provisions. The supplement reduces Virginia Power’s overall compliance responsibilities associated with the indenture by limiting the maximum principal amount of bonds that may be outstanding under the indenture to $10 million unless otherwise provided in a further supplement, and by modifying or eliminating altogether certain compliance requirements while there are no bonds outstanding. The supplement also provides Virginia Power with flexibility to determine when or if certain newly or recently acquired properties will be pledged as collateral under the indenture. There were no bonds outstanding as of December 31, 2012; however, by leaving the indenture open, Virginia Power expects to retain the flexibility to issue mortgage bonds in the future.
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, 2010,2012, 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, 2010.2012.
See Note 1817 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.notes, which information is incorporated herein by reference.
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, 2010.2012. 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
45
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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 2011.2013.
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 |
Dominion | 2013 | 2014- 2015 | 2016- 2017 | 2018 and thereafter | Total | |||||||||||||||
(millions) | ||||||||||||||||||||
Long-term debt(1) | $ | 2,200 | $ | 2,058 | $ | 2,790 | $ | 11,940 | $ | 18,988 | ||||||||||
Interest payments(2) | 898 | 1,693 | 1,457 | 12,218 | 16,266 | |||||||||||||||
Leases(3) | 79 | 136 | 118 | 161 | 494 | |||||||||||||||
Purchase obligations(4): | ||||||||||||||||||||
Purchased electric capacity for utility operations | 350 | 695 | 456 | 327 | 1,828 | |||||||||||||||
Fuel commitments for utility operations | 716 | 778 | 265 | 259 | 2,018 | |||||||||||||||
Fuel commitments for nonregulated operations | 254 | 258 | 116 | 187 | 815 | |||||||||||||||
Pipeline transportation and storage | 131 | 174 | 96 | 366 | 767 | |||||||||||||||
Energy commodity purchases for resale(5) | 79 | 32 | 29 | 146 | 286 | |||||||||||||||
Other(6) | 469 | 56 | 7 | 21 | 553 | |||||||||||||||
Other long-term liabilities(7): | ||||||||||||||||||||
Financial derivative-commodities(5) | 48 | 29 | 3 | — | 80 | |||||||||||||||
Other contractual obligations(8) | 16 | 12 | 30 | 2 | 60 | |||||||||||||||
Total cash payments | $ | 5,240 | $ | 5,921 | $ | 5,367 | $ | 25,627 | $ | 42,155 |
(1) | Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders. |
(2) | Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2012 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 17 to the Consolidated Financial Statements. Does not reflect Dominion’s ability to defer interest 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. |
(5) | 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. |
(6) | Includes capital, operations, and maintenance commitments. |
(7) | Excludes regulatory liabilities, AROs and employee benefit plan obligations, which are not contractually fixed as to timing and amount. See Notes |
(8) | Includes interest rate swap agreements. |
Virginia Power | 2013 | 2014- 2015 | 2016- 2017 | 2018 and thereafter | Total | |||||||||||||||
(millions) | ||||||||||||||||||||
Long-term debt(1) | $ | 418 | $ | 228 | $ | 1,155 | $ | 4,875 | $ | 6,676 | ||||||||||
Interest payments(2) | 342 | 660 | 594 | 3,869 | 5,465 | |||||||||||||||
Leases(3) | 26 | 43 | 26 | 26 | 121 | |||||||||||||||
Purchase obligations(4): | ||||||||||||||||||||
Purchased electric capacity for utility operations | 350 | 695 | 456 | 327 | 1,828 | |||||||||||||||
Fuel commitments for utility operations | 716 | 778 | 265 | 259 | 2,018 | |||||||||||||||
Transportation and storage | 27 | 52 | 40 | 197 | 316 | |||||||||||||||
Other(5) | 302 | 29 | 4 | 12 | 347 | |||||||||||||||
Total cash payments(6) | $ | 2,181 | $ | 2,485 | $ | 2,540 | $ | 9,565 | $ | 16,771 |
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. |
(2) | Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2012 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 17 to the Consolidated Financial Statements. |
(3) | Primarily consists of operating leases. |
Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined. |
Includes capital, operations, and maintenance commitments. |
(6) | Excludes regulatory liabilities, AROs and employee benefit plan contributions that are not contractually fixed as to timing and amount. See Notes |
PLANNED CAPITAL EXPENDITURES
Dominion’s planned capital expenditures are expected to total approximately $3.9 billion, $4.7 billion, $4.2 billion and $4.4$3.3 billion in 2011, 20122013, 2014 and 2013,2015, 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.fuel and the buyout of the lease at Fairless in 2013.
Virginia Power’s planned capital expenditures are expected to total approximately $2.2$2.6 billion, $3.0 billion and $3.3$2.3 billion in 2011, 20122013, 2014 and 2013,2015, respectively. Virginia Power’s expenditures are expected to include construction and expansion of electric generation facilities, environmental upgrades, construction improvements and expansion of electric transmission and distribution 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 respective company’s 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. SeeDVP, Dominion Generation-PropertiesGenerationand Dominion Energy-Properties in Item 1. Business for a discussion of Dominion’s and Virginia Power’s expansion plans.
These estimates are based on a capital expenditures plan reviewed and endorsed by Dominion’s Board of Directors in late
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2012 and 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, 2010, Dominion had issued $131 million of guarantees, primarily to support equity method 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 related to 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) advancedSee Note 22 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 FairlessConsolidated Financial Statements for additional information, which information 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.incorporated herein by reference.
Benefits of this arrangement include:
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FUTURE ISSUESAND OTHER MATTERS
See Item 1. Business, Item 3. Legal Proceedings, and Notes 1413 and 2322 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other matters that may impact future results of operations, financial condition, and/or financial condition.cash flows.
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$189 million, $252$184 million and $205$228 million of expenses (including depreciation) during 2010, 2009,2012, 2011, and 20082010 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $231$193 million and $251$181 million in 20112013 and 2012,2014, respectively. In addition, capital expenditures related to environmental controls were $213 million, $403 million, and $351 million $266 million,for 2012, 2011 and $254 million for 2010, 2009 and 2008, respectively. These expenditures are expected to be approximately $398$75 million and $553$115 million for 2013 and 2014, respectively.
Virginia Power incurred approximately $120 million, $129 million and $144 million of expenses (including depreciation) during 2012, 2011 and 2010, respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $148 million and $157 million in 2013 and 2014, respectively. In addition, capital expenditures related to environmental controls were $34 million, $77 million and $101 million for 2012, 2011 and 2010, respectively. These expenditures are expected to be approximately $20 million and $99 million for 2013 and 2014, respectively.
FUTURE ENVIRONMENTAL REGULATIONS
Air
The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At
a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of Dominion’s and Virginia Power’s facilities are subject to the CAA’s permitting and other requirements.
In December 2012, the EPA issued a final rule that set a more stringent annual air quality standard for fine particulate matter. The EPA is expected to complete final air quality designations by December 2014. States will have until 2020 to meet the revised standard. The extent to which a revised particulate matter standard will impact Dominion is uncertain at this time, but is not expected to be material.
The EPA has finalized rules establishing a new 1-hour NAAQS for NO2 and a new 1-hour NAAQS for SO2, which could require additional NOX and SO2 controls in certain areas where the Companies operate. Until the states have developed implementation plans for these standards, the impact on Dominion’s or Virginia Power’s facilities that emit NOX and SO2 is uncertain.
In January 2010, the EPA also proposed a new, more stringent NAAQS for ozone and had planned to finalize the rule in 2011. In September 2011, the EPA announced a delay from 2011 to 2014 of the rulemaking, therefore NOx controls that may have been required by the rulemaking are also expected to be delayed. In the interim, the EPA is proceeding with implementation of the current ozone standard and made final attainment/nonattainment designations in May 2012. Several Dominion electric generating facilities are located in areas impacted by this standard. Until the states have developed implementation plans for the new NOx, SO2 and ozone standards, it is not possible to determine the impact on Dominion’s or Virginia Power’s facilities that emit NOX and SO2. The Companies cannot currently predict with certainty whether or to what extent the new rules will ultimately require additional controls, however, if significant expenditures are required, it could adversely affect Dominion’s results of operations, and Dominion’s and Virginia Power’s cash flows.
In June 2005, the EPA finalized amendments to the Regional Haze Rule, also known as the Clean Air Visibility Rule. The rule requires the states to implement Best Available Retrofit Technology requirements for sources to address impacts to visual air quality through regional haze state implementation plans, but allows other alternative options. The EPA is in the process of completing rulemakings on regional haze state implementation plans. Although Dominion and Virginia Power anticipate that the emission reductions achieved through compliance with other CAA-required programs will generally address this rule, additional emission reduction requirements may be imposed on the Companies’ facilities.
Water
The CWA is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. Dominion and Virginia Power must comply with all aspects of the CWA programs at their operating facilities. In July 2004, the EPA published regulations under CWA Section 316(b) that govern existing utilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold. In April 2008, the U.S. Supreme Court granted an industry
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
request to review the question of whether Section 316(b) authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. The U.S. Supreme Court ruled in April 2009 that the EPA has the authority to consider costs versus environmental benefits in selecting the best technology available for reducing impacts of cooling water intakes at power stations. It is currently unknown how the EPA will interpret the ruling in its ongoing rulemaking activity addressing cooling water intakes as well as how the states will implement this decision. In April 2011, the EPA published the proposed rule related to Section 316(b) in the Federal Register, and agreed to publish a final rule no later than July 27, 2012. In July 2012, the EPA announced a delay to no later than June 27, 2013 of its impending rulemaking related to Section 316(b).
The rule in its proposed form seeks to establish a uniform national standard for impingement, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA proposes to delegate entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of nine facility-specific factors, including a social cost-benefit test.
The proposed rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Under this proposal, Dominion has 16 facilities that may be subject to these proposed regulations. If finalized as proposed, Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power incurred approximately $144 million, $134 millioncannot estimate the need or potential for entrainment controls under the proposed rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and $125 millionbenefit studies. However, the impacts of expenses (including depreciation) duringthis proposed rule may be material to the results of operations, financial condition and/or cash flows.
Solid and Hazardous Waste
In June 2010, the EPA proposed federal regulations under the RCRA for management of coal combustion by-products generated by power plants. The EPA is considering two possible options for the regulation of coal combustion by-products, both of which fall under the RCRA. Under the first proposal, the EPA would classify these by-products as special wastes subject to regulation under subtitle C, the hazardous waste provisions of the RCRA, when destined for disposal at landfills or surface impoundments. Under the second proposal, the EPA would regulate coal combustion by-products under subtitle D of the RCRA, the section for non-hazardous wastes. While the Companies cannot currently predict the outcome of this matter, regulation under either option will affect Dominion’s and Virginia Power’s onsite disposal facilities and coal combustion by-product management practices, and potentially require material investments.
Climate Change Legislation and Regulation
In December 2009, the EPA issued theirFinal Endangerment and 2008, respectively,Cause or Contribute Findings for Greenhouse Gases underSection 202(a) of the Clean Air Act, finding that GHGs “endanger
both the public health and the public welfare of current and future generations.” On April 1, 2010, the EPA and the Department of Transportation’s National Highway Safety Administration announced a joint final rule establishing a program that will dramatically reduce GHG emissions and improve fuel economy for new cars and trucks sold in connectionthe United States. These rules took effect in January 2011 and established GHG emissions as regulated pollutants under the CAA.
In May 2010, the EPA issued theFinal Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rulethat, combined with environmental protectionprior actions, require Dominion and monitoring activitiesVirginia Power to obtain permits for GHG emissions for new and expects these expensesmodified facilities over certain size thresholds, and meet best available control technology for GHG emissions. The EPA has issued draft guidance for GHG permitting, including best available control technology.
In April 2012, the EPA published proposed NSPS for GHG emissions for new electric generating units. This proposed rule sets national emission standards for new coal, oil, integrated gasification combined cycle, and combined cycle units larger than 25MW. The rule, which is expected to be approximately $142 millionfinalized in the Spring of 2013, covers CO2 only and $156 million in 2011 and 2012, respectively. In addition, capital expenditures relateddoes not apply to environmental controls were $101 million, $109 million and $116 million for 2010, 2009 and 2008, respectively. These expendituresexisting sources. New natural gas combined cycle units, including Brunswick County, are expected to be approximately $72 million and $341 millionable to meet this standard. The rule also does not apply to any new or existing simple cycle combustion turbine units or biomass units. The schedule for 2011 and 2012, respectively.
FUTURE ENVIRONMENTAL REGULATIONSa final rulemaking governing a GHG NSPS for existing sources is uncertain.
There have already been federal and stateare other legislative proposals and regulatory action regarding the regulation ofthat may be considered that would have an indirect impact on GHG emissions. There is the potential for the U.S. Congress to consider a mandatory Clean Energy Standard. In addition to possible federal action, some regions and states in which Dominion and Virginia Power expectoperate have already adopted or may adopt GHG emission reduction programs. Any of these new or contemplated regulations may affect capital costs, or create significant permitting delays, for new or modified facilities that there may be federal legislation and/or regulatory action regarding compliance with more stringent air emission standards, regarding coal combustion by-products, and regarding regulation of cooling water intake structures and discharges inemit GHGs.
In July 2008, Massachusetts passed the future. With respect toGWSA. Among other provisions, the GWSA sets economy-wide GHG emissions reduction goals for Massachusetts, including reductions of 25% below 1990 levels by 2020, interim goals for 2030 and 2040 and reductions of 80% below 1990 levels by 2050. No regulations impacting Dominion under the GWSA have been proposed. Dominion operates Brayton Point in Massachusetts and acts as a retail electric supplier in Massachusetts, which are subject to the implementation of the GWSA.
In December 2010,2009, the EPA announcedgovernors of 11 Northeast and mid-Atlantic states, including Connecticut, Maryland, Massachusetts, New York, Pennsylvania, and Rhode Island (RGGI states plus Pennsylvania) signed a schedule for when they will propose regulations which would establishmemorandum of understanding committing their states toward developing a low carbon fuel standard to reduce GHG performance standards for new, modifiedemissions from vehicles. The memorandum of understanding established a process to develop a regional framework by 2011 and existing fossil-fired electric generating units. Regulations are expectedexamine the economic impacts of a low carbon fuel standard program. Although economic studies and policy options were examined in 2011, a definitive framework has yet 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 performance standards, if these rules are finalized. The EPA has not provided any detail yet on what the performance standard might be or what measures facilities might have to make to reach the standard. With respect to emission reductions of SO2, NOx, mercury and HAPs (in addition to mercury), specific requirements will depend on the following:established.
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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 by-products, Dominion and Virginia Power expect federal regulation of coal combustion by-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 exemptedchoose to exempt their hedging transactions 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 continue to be established through the CFTC’s and SEC’songoing rulemaking process which is required to be completed by July 2011.of the applicable regulators. 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.requirements, for their derivative activities. 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.
Cove Point Export Project
Dominion is pursuing a liquefaction project at Cove Point, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. The project, which is expected to cost between approximately $3.4 billion and $3.8 billion, exclusive of financing costs, has a planned capacity of approximately 750 million cubic feet per day on the inlet and approximately 4.5 to 5 million metric tons per annum on the outlet. In 2011, Cove Point requested authorization from the DOE to export LNG to countries that have a free trade agreement requiring trade in natural gas with the U.S. as well as countries that do not have such a free trade agreement. In October 2011, Cove Point received authorization from the DOE to export LNG to free trade agreement countries and Cove Point expects to receive authorization from the DOE to export LNG to non-free trade agreement countries in 2013. In June 2012, FERC approved Cove Point’s request to initiate the pre-filing process under which environmental review for the project commenced. Approval of the project could take up to two years from the pre-filing approval date.
In March 2012, Cove Point entered into precedent agreements with two major companies, one of which is Sumitomo Corporation, pursuant to which Cove Point would provide liquefaction, storage and loading services but would not own or directly export the LNG. In October 2012, Cove Point and the unnamed company terminated their precedent agreement by mutual consent. In December 2012, Cove Point entered into a 20-year terminal services agreement with Pacific Summit Energy LLC, a U.S. subsidiary of Sumitomo Corporation, for half of the planned project capacity. The agreement contains final terms subject to certain conditions precedent which include conditions related to customer contracting. Cove Point is in active negotiations with a company for a definitive terminal services agreement for the remaining half of the planned project capacity.
In May 2012, in response to claims by the Sierra Club, Cove Point filed a complaint for declaratory judgment to confirm its right to construct the project. In January 2013, a Maryland circuit court issued declaratory judgment confirming Cove Point’s right to build liquefaction facilities. In February 2013, the Sierra Club filed a notice of appeal with the Maryland Court of Special Appeals.
Subject to a final decision on pursuing the project, execution of binding terminal service agreements, receipt of regulatory and other approvals, and successful completion of engineering studies, construction of liquefaction facilities could begin in 2014 with an in-service date in 2017.
Cove Point Re-Export Project
In August 2011, Cove Point filed an application with the DOE seeking blanket authority to re-export up to the equivalent of 150 bcf of foreign-sourced LNG from the Cove Point terminal over a two-year period. In January 2012, the DOE conditionally approved Cove Point’s application. Due to lack of customer interest in re-export, Cove Point made no filings with FERC and the DOE re-export authorization automatically terminated in January 2013.
Regulation Act Legislation
In January 2013, legislation was introduced in the Virginia General Assembly which would amend the Regulation Act. The legislation passed the Virginia House of Delegates and the Senate of Virginia and was signed into law by the governor in February 2013. Among other things the amendments eliminate the 50 basis points RPS ROE incentive prospectively, as well as the new generation ROE incentives for future projects, except for nuclear and offshore wind projects, which instead are reduced from the current 200 basis points ROE incentive to 100 basis points. ROE incentives for previously approved, as well as filed for but unconstructed projects, remain in place. In addition, the performance incentive provision of the Regulation Act, authorizing the Virginia Commission to increase or decrease a utility’s authorized ROE by up to 100 basis points based on operating comparisons with certain nationally recognized standards, is removed and the Virginia Commission has the discretion to increase or decrease a utility’s authorized ROE based on commission precedent that existed prior to the enactment of the Regulation Act. The legislation includes changes to the earnings test parameters defined by the Regulation Act to allow for a wider band of 70 basis points above and below the authorized ROE in determining whether a utility’s earned ROE is either insufficient or excessive beginning with the biennial review for 2013-2014 to be filed in 2015. Additionally, if a utility is deemed to have over-earned, the customer refund share of excess earnings increases to 70% from the current 60% level beginning with the biennial review for 2013-2014 to be filed in 2015. The legislation also provides guidance to the Virginia Commission on rate-making treatment for severe weather events and natural disasters and for asset impairments related to early retirements of utility generation plants, for which the decision to retire was made before December 31, 2012. This guidance on rate-making treatment applies to Virginia Power’s upcoming biennial review for 2011-2012 to be filed in 2013. Additionally, the provision in the Regulation Act requiring the Virginia Commission to combine transmission-related rider costs with base rates is eliminated and the transmission costs will con-
49
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
tinue to be segregated and recovered separately. The legislation requires a utility seeking approval to construct a generating facility to demonstrate that it has considered and weighed alternative options in its selection process.
Virginia Offshore Wind Lease
In March 2012, Virginia Power filed a notice with BOEM of its interest in obtaining leases off the Virginia coast in an area sufficient for construction of offshore wind turbines having the potential to generate approximately 1,500-2,000 MW of electricity or enough electricity to serve approximately 500,000 homes at peak demand. In December 2012, BOEM announced that it would auction approximately 113,000 acres off the Virginia coast as a single lease in 2013.
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’sPower��s electric operations, Dominion’s gas 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 or interest rates.
Commodity Price Risk
To manage price risk, Dominion and Virginia Power primarily hold commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of elec-
tricity,electricity, 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 marketcommodity prices of Dominion’s non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $183$128 million and $150$179 million as of December 31, 20102012 and 2009,2011, respectively. A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $5 million and $11 million in the fair value of Dominion’s commodity-based financial derivative instruments held for trading purposes would have resulted in a decrease in fair value of approximately $18 million and $8 million as of December 31, 20102012 and 2009,2011, respectively.
A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of Virginia Power’s non-trading commodity-based financial derivatives as of December 31, 20102012 or 2009.2011.
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 the contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.
Interest Rate Risk
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 instrumentsvariable rate debt and interest rate swaps designated under fair value hedging and outstanding for Dominion and Virginia Power, a hypothetical 10% increase in market interest rates would not have resulted in a material change in annual earnings atas of December 31, 20102012 or 2009.2011.
Dominion and Virginia Power may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. AtAs of December 31, 2009,2012, Dominion and Virginia Power had $1.7$1.8 billion and $850$750 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. At December 31, 2009, aA hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $62$21 million and $33$9 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at December 31, 2012. As of December 31, 2011, Dominion and Virginia Power had $2.3 billion and $1.3 billion, respectively, in aggregate notional amounts of these interest rate derivatives held by Dominionoutstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $31 million and $15 million, respectively, in the fair value of Dominion’s and Virginia Power, respectively. Subsequent to June 30, 2010, all forward-starting
Power’s interest rate swap contracts were terminated; therefore, Dominion and Virginia Power have no sensitivity to changes in interest rates related to these interest rate swaps.derivatives at December 31, 2011.
The impact of a change in market interest rates on these anticipatory hedgesDominion’s and Virginia Power’s interest rate-based financial derivative instruments at a point in time is not necessarily representative of the
50 |
results that will be realized when suchthe contracts are ultimately settled. Net gains and/or losses from interest rate derivativesderivative instruments used for anticipatory hedging purposes, to the extent realized, will generally be amortized over the lifeoffset by recognition of the respective debt issuance being hedged.hedged transaction.
Investment Price Risk
Dominion and Virginia Power are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value.
Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $95$126 million and $25$54 million in 20102012 and 2009,2011, 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 20102012 and 2009,2011, Dominion recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $182$210 million and $360$52 million, respectively.
Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $44$53 million and $24 million in 2010. Virginia Power recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $3 million in 2009.2012 and 2011, 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 20102012 and 2009,2011, Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $67$89 million and $149$25 million, respectively.
Dominion sponsors pension and other postretirement employee 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$743 million in 2010 2012
and $777$273 million in 2009,2011, versus expected returns of $479$509 million and $462$519 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the periodic cost recognized for employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. As of December 31, 20102012 and 2009,2011, 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 $13 million for pension benefits and $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
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, 20102012 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.
51
Item 8. Financial Statements and Supplementary Data
Page No. | |||||
Dominion Resources, Inc. | |||||
53 | |||||
Consolidated Statements of Income for the years ended December 31, | 54 | ||||
55 | |||||
Consolidated Statements of Equity at December 31, 2012, 2011 and 2010 and for the years then ended | 58 | ||||
59 | |||||
Virginia Electric and Power Company | |||||
60 | |||||
Consolidated Statements of Income for the years ended December 31, | 61 | ||||
Consolidated Balance Sheets at December 31, | 63 | ||||
65 | |||||
66 | |||||
67 |
52 |
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, 20102012 and 2009,2011, and the related consolidated statements of income, common shareholders’ equity, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2010.2012. 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, 20102012 and 2009,2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010,2012, 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 standard for the impairment framework for oil and gas 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, 2010,2012, based on the criteria established inInternal Control—IntegratedControl-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 201127, 2013 expressed an unqualified opinion on Dominion’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 25,27, 2013
53 |
Consolidated Statements of Income
Year Ended December 31, | 2012 | 2011(1) | 2010(1) | |||||||||
(millions, except per share amounts) | ||||||||||||
Operating Revenue | $ | 13,093 | $ | 14,145 | $ | 14,927 | ||||||
Operating Expenses | ||||||||||||
Electric fuel and other energy-related purchases | 3,748 | 4,097 | 4,034 | |||||||||
Purchased electric capacity | 387 | 454 | 453 | |||||||||
Purchased gas | 1,177 | 1,764 | 2,049 | |||||||||
Other operations and maintenance(2) | 4,868 | 3,322 | 3,448 | |||||||||
Depreciation, depletion and amortization | 1,186 | 1,066 | 1,035 | |||||||||
Other taxes | 571 | 548 | 524 | |||||||||
Total operating expenses | 11,937 | 11,251 | 11,543 | |||||||||
Gain on sale of Appalachian E&P operations | — | — | 2,467 | |||||||||
Income from operations | 1,156 | 2,894 | 5,851 | |||||||||
Other income | 223 | 178 | 170 | |||||||||
Interest and related charges | 882 | 867 | 826 | |||||||||
Income from continuing operations including noncontrolling interests before income taxes | 497 | 2,205 | 5,195 | |||||||||
Income tax expense | 146 | 754 | 2,112 | |||||||||
Income from continuing operations including noncontrolling interests | 351 | 1,451 | 3,083 | |||||||||
Loss from discontinued operations(3) | (22 | ) | (25 | ) | (258 | ) | ||||||
Net income including noncontrolling interests | 329 | 1,426 | 2,825 | |||||||||
Noncontrolling interests | 27 | 18 | 17 | |||||||||
Net income attributable to Dominion | 302 | 1,408 | 2,808 | |||||||||
Amounts attributable to Dominion: | ||||||||||||
Income from continuing operations, net of tax | 324 | 1,433 | 3,066 | |||||||||
Loss from discontinued operations, net of tax | (22 | ) | (25 | ) | (258 | ) | ||||||
Net income attributable to Dominion | 302 | 1,408 | 2,808 | |||||||||
Earnings Per Common Share-Basic: | ||||||||||||
Income from continuing operations | $ | 0.57 | $ | 2.50 | $ | 5.21 | ||||||
Loss from discontinued operations | (0.04 | ) | (0.04 | ) | (0.44 | ) | ||||||
Net income attributable to Dominion | $ | 0.53 | $ | 2.46 | $ | 4.77 | ||||||
Earnings Per Common Share-Diluted: | ||||||||||||
Income from continuing operations | $ | 0.57 | $ | 2.49 | $ | 5.20 | ||||||
Loss from discontinued operations | (0.04 | ) | (0.04 | ) | (0.44 | ) | ||||||
Net income attributable to Dominion | $ | 0.53 | $ | 2.45 | $ | 4.76 | ||||||
Dividends declared per common share | $ | 2.11 | $ | 1.97 | $ | 1.83 |
(1) | Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast. |
(2) | For 2012, includes impairment and other charges of $2.1 billion related to Brayton Point, Kincaid and Kewaunee. See Note 6 for additional information. |
(3) | Includes income tax benefit of $27 million, $9 million, and $34 million in 2012, 2011 and 2010, respectively. |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
54 |
Consolidated Statements of Comprehensive Income
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 |
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
(millions) | ||||||||||||
Net income including noncontrolling interests | $ | 329 | $ | 1,426 | $ | 2,825 | ||||||
Other comprehensive income (loss), net of taxes: | ||||||||||||
Net deferred gains (losses) on derivatives-hedging activities, net of $5, $48 and $(52) tax | (8 | ) | (67 | ) | 84 | |||||||
Changes in unrealized net gains on investment securities, net of $(68), $(7) and $(54) tax | 108 | 11 | 89 | |||||||||
Changes in net unrecognized pension and other postretirement benefit costs, net of $209, $147 and $40 tax | (330 | ) | (231 | ) | (18 | ) | ||||||
Amounts reclassified to net income: | ||||||||||||
Net derivative (gains)-hedging activities, net of $34, $28 and $193 tax | (60 | ) | (38 | ) | (314 | ) | ||||||
Net realized (gains) losses on investment securities, net of $16, $(4) and $9 tax | (25 | ) | 6 | (14 | ) | |||||||
Net pension and other postretirement benefit costs, net of $(32), $(25) and $(38) tax | 48 | 39 | 54 | |||||||||
Total other comprehensive loss | (267 | ) | (280 | ) | (119 | ) | ||||||
Comprehensive income including noncontrolling interests | 62 | 1,146 | 2,706 | |||||||||
Comprehensive income attributable to noncontrolling interests | 27 | 18 | 17 | |||||||||
Comprehensive income attributable to Dominion | $ | 35 | $ | 1,128 | $ | 2,689 |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
55 |
At December 31, | 2010 | 2009 | 2012 | 2011 | ||||||||||||
(millions) | ||||||||||||||||
ASSETS | ||||||||||||||||
Current Assets | ||||||||||||||||
Cash and cash equivalents | $ | 62 | $ | 48 | $ | 248 | $ | 102 | ||||||||
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 | ||||||||||||||
Customer receivables (less allowance for doubtful accounts of $28 and $29) | 1,621 | 1,780 | ||||||||||||||
Other receivables (less allowance for doubtful accounts of $4 and $8) | 96 | 255 | ||||||||||||||
Inventories: | ||||||||||||||||
Materials and supplies | 609 | 590 | 684 | 641 | ||||||||||||
Fossil fuel | 354 | 408 | 467 | 541 | ||||||||||||
Gas stored | 200 | 187 | 108 | 166 | ||||||||||||
Derivative assets | 739 | 1,128 | 518 | 705 | ||||||||||||
Assets held for sale | — | 1,018 | ||||||||||||||
Regulatory assets | 407 | 170 | 203 | 541 | ||||||||||||
Prepayments | 277 | 405 | 326 | 262 | ||||||||||||
Deferred income taxes | 573 | 9 | ||||||||||||||
Other | 506 | 683 | 296 | 428 | ||||||||||||
Total current assets | 5,400 | 6,817 | 5,140 | 5,430 | ||||||||||||
Investments | ||||||||||||||||
Nuclear decommissioning trust funds | 2,897 | 2,625 | 3,330 | 2,999 | ||||||||||||
Investment in equity method affiliates | 571 | 595 | 558 | 553 | ||||||||||||
Restricted cash equivalents | 400 | — | 33 | 141 | ||||||||||||
Other | 283 | 272 | 270 | 292 | ||||||||||||
Total investments | 4,151 | 3,492 | 4,191 | 3,985 | ||||||||||||
Property, Plant and Equipment | ||||||||||||||||
Property, plant and equipment | 39,855 | 39,036 | 43,364 | 42,033 | ||||||||||||
Property, plant and equipment, VIE | 957 | 957 | ||||||||||||||
Accumulated depreciation, depletion and amortization | (13,142 | ) | (13,444 | ) | (13,548 | ) | (13,320 | ) | ||||||||
Total property, plant and equipment, net | 26,713 | 25,592 | 30,773 | 29,670 | ||||||||||||
Deferred Charges and Other Assets | ||||||||||||||||
Goodwill | 3,141 | 3,354 | 3,130 | 3,141 | ||||||||||||
Pension and other postretirement benefit assets | 712 | 702 | 702 | 681 | ||||||||||||
Intangible assets | 642 | 693 | 536 | 637 | ||||||||||||
Regulatory assets | 1,446 | 1,390 | 1,717 | 1,382 | ||||||||||||
Other | 612 | 514 | 649 | 688 | ||||||||||||
Total deferred charges and other assets | 6,553 | 6,653 | 6,734 | 6,529 | ||||||||||||
Total assets | $ | 42,817 | $ | 42,554 | $ | 46,838 | $ | 45,614 |
56 |
At December 31, | 2010 | 2009 | 2012 | 2011 | ||||||||||||
(millions) | ||||||||||||||||
LIABILITIESAND SHAREHOLDERS’ EQUITY | ||||||||||||||||
LIABILITIESAND EQUITY | ||||||||||||||||
Current Liabilities | ||||||||||||||||
Securities due within one year | $ | 497 | $ | 1,137 | $ | 1,363 | $ | 1,479 | ||||||||
Securities due within one year, VIE | 860 | — | ||||||||||||||
Short-term debt | 1,386 | 1,295 | 2,412 | 1,814 | ||||||||||||
Accounts payable | 1,562 | 1,401 | 1,137 | 1,250 | ||||||||||||
Accrued interest, payroll and taxes | 849 | 676 | 636 | 648 | ||||||||||||
Derivative liabilities | 633 | 679 | 510 | 951 | ||||||||||||
Liabilities held for sale | — | 428 | ||||||||||||||
Regulatory liabilities | 135 | 536 | 136 | 243 | ||||||||||||
Accrued severance | 132 | 4 | ||||||||||||||
Other | 579 | 677 | 709 | 577 | ||||||||||||
Total current liabilities | 5,773 | 6,833 | 7,763 | 6,962 | ||||||||||||
Long-Term Debt | ||||||||||||||||
Long-term debt | 14,023 | 13,730 | 15,478 | 14,785 | ||||||||||||
Junior subordinated notes payable to affiliates | 268 | 268 | ||||||||||||||
Enhanced junior subordinated notes | 1,467 | 1,483 | ||||||||||||||
Long-term debt, VIE | — | 890 | ||||||||||||||
Junior subordinated notes | 1,373 | 1,719 | ||||||||||||||
Total long-term debt | 15,758 | 15,481 | 16,851 | 17,394 | ||||||||||||
Deferred Credits and Other Liabilities | ||||||||||||||||
Deferred income taxes and investment tax credits | 4,708 | 4,244 | 5,800 | 5,216 | ||||||||||||
Asset retirement obligations | 1,577 | 1,605 | 1,641 | 1,383 | ||||||||||||
Pension and other postretirement benefit liabilities | 765 | 1,260 | 1,831 | 962 | ||||||||||||
Regulatory liabilities | 1,392 | 1,215 | 1,514 | 1,324 | ||||||||||||
Other | 590 | 474 | 556 | 613 | ||||||||||||
Total deferred credits and other liabilities | 9,032 | 8,798 | 11,342 | 9,498 | ||||||||||||
Total liabilities | 30,563 | 31,112 | 35,956 | 33,854 | ||||||||||||
Commitments and Contingencies (see Note 23) | ||||||||||||||||
Commitments and Contingencies (see Note 22) | ||||||||||||||||
Subsidiary Preferred Stock Not Subject To Mandatory Redemption | 257 | 257 | 257 | 257 | ||||||||||||
Common Shareholders’ Equity | ||||||||||||||||
Common stock—no par(1) | 5,715 | 6,525 | ||||||||||||||
Equity | ||||||||||||||||
Common stock-no par(1) | 5,493 | 5,180 | ||||||||||||||
Other paid-in capital | 194 | 185 | 162 | 179 | ||||||||||||
Retained earnings | 6,418 | 4,686 | 5,790 | 6,697 | ||||||||||||
Accumulated other comprehensive loss | (330 | ) | (211 | ) | (877 | ) | (610 | ) | ||||||||
Total common shareholders’ equity | 11,997 | 11,185 | 10,568 | 11,446 | ||||||||||||
Total liabilities and shareholders’ equity | $ | 42,817 | $ | 42,554 | ||||||||||||
Noncontrolling interest | 57 | 57 | ||||||||||||||
Total equity | 10,625 | 11,503 | ||||||||||||||
Total liabilities and equity | $ | 46,838 | $ | 45,614 |
(1) | 1 billion shares authorized; |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
57 |
Consolidated Statements of Common Shareholders’ Equity
Common Stock | Dominion Shareholders | Common Stock | Dominion Shareholders | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Shares | Amount | Other Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling interest | Total | Shares | Amount | Other Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total Common Shareholders’ Equity | Noncontrolling Interests | Total Equity | ||||||||||||||||||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2007 | 577 | $ | 5,733 | $ | 175 | $ | 3,510 | $ | (12 | ) | $ | 29 | $ | 9,435 | ||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2009 | 599 | $ | 6,525 | $ | 185 | $ | 4,686 | $ | (211 | ) | $ | 11,185 | $ | — | $ | 11,185 | ||||||||||||||||||||||||||||||||||||||||||||
Net income including noncontrolling interests | 1,851 | (1 | ) | 1,850 | 2,825 | 2,825 | 2,825 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Issuance of stock-employee and direct stock purchase plans | 1 | 10 | 10 | 10 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 2 | 80 | 80 | 2 | 80 | 80 | 80 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock repurchases | (21 | ) | (900 | ) | (900 | ) | (21 | ) | (900 | ) | (900 | ) | (900 | ) | ||||||||||||||||||||||||||||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 9 | 9 | 9 | 9 | 9 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends(2) | (1,093 | ) | (1,093 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends(1) | (1,093 | ) | (1,093 | ) | (1,093 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other comprehensive loss, net of tax | (119 | ) | (119 | ) | (119 | ) | (119 | ) | (119 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2010 | 581 | $ | 5,715 | $ | 194 | $ | 6,418 | $ | (330 | ) | — | $ | 11,997 | |||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2010 | 581 | 5,715 | 194 | 6,418 | (330 | ) | 11,997 | — | 11,997 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Net income including noncontrolling interests | 1,425 | 1,425 | 1 | 1,426 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Consolidation of noncontrolling interests(2) | — | 61 | 61 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 1 | 49 | 49 | 49 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock repurchases | (13 | ) | (601 | ) | (601 | ) | (601 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Other stock issuances(3) | 1 | 17 | (17 | ) | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 2 | 2 | 2 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends | (1,146 | )(1) | (1,146 | ) | (5 | ) | (1,151 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Other comprehensive loss, net of tax | (280 | ) | (280 | ) | (280 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2011 | 570 | 5,180 | 179 | 6,697 | (610 | ) | 11,446 | 57 | 11,503 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Net income including noncontrolling interests | 318 | 318 | 11 | 329 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Issuance of stock-employee and direct stock purchase plans | 4 | 246 | 246 | 246 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 1 | 26 | 26 | 26 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other stock issuances(3) | 1 | 41 | (27 | ) | 14 | 14 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 10 | 10 | 10 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends | (1,225 | )(1) | (1,225 | ) | (11 | ) | (1,236 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Other comprehensive income, net of tax | (267 | ) | (267 | ) | (267 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2012 | 576 | $ | 5,493 | $ | 162 | $ | 5,790 | $ | (877 | ) | $ | 10,568 | $ | 57 | $ | 10,625 |
(1) |
Includes subsidiary preferred dividends related to noncontrolling interests of |
(2) | See Note 15 for consolidation of a VIE in October 2011. |
(3) |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.Statements
58 |
Consolidated Statements of Comprehensive IncomeCash Flows
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 |
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net income including noncontrolling interests | $ | 329 | $ | 1,426 | $ | 2,825 | ||||||
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: | ||||||||||||
Gain from sale of Appalachian E&P operations | — | — | (2,467 | ) | ||||||||
Loss from sale of Peoples | — | — | 113 | |||||||||
Impairment of generation assets (including discontinued operations) | 2,089 | 283 | 194 | |||||||||
Net reserves (payments) related to rate refunds | (151 | ) | 3 | (500 | ) | |||||||
Contributions to pension plans | — | — | (650 | ) | ||||||||
Charges (payments) related to workforce reduction program | (9 | ) | (115 | ) | 229 | |||||||
Depreciation, depletion and amortization (including nuclear fuel) | 1,443 | 1,288 | 1,258 | |||||||||
Deferred income taxes and investment tax credits | 246 | 756 | 682 | |||||||||
Gain on the sale of assets to Blue Racer | (81 | ) | — | — | ||||||||
Other adjustments | (155 | ) | (92 | ) | (40 | ) | ||||||
Changes in: | ||||||||||||
Accounts receivable | 292 | 365 | (60 | ) | ||||||||
Inventories | 33 | (185 | ) | 35 | ||||||||
Deferred fuel and purchased gas costs, net | 368 | (3 | ) | (246 | ) | |||||||
Prepayments | (85 | ) | (19 | ) | 139 | |||||||
Accounts payable | (61 | ) | (413 | ) | 119 | |||||||
Accrued interest, payroll and taxes | (12 | ) | (216 | ) | 166 | |||||||
Other operating assets and liabilities | (109 | ) | (95 | ) | 28 | |||||||
Net cash provided by operating activities | 4,137 | 2,983 | 1,825 | |||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions (including nuclear fuel) | (4,145 | ) | (3,652 | ) | (3,422 | ) | ||||||
Proceeds from sale of Appalachian E&P operations | — | — | 3,450 | |||||||||
Proceeds from sale of Peoples | — | — | 741 | |||||||||
Proceeds from sales of securities | 1,356 | 1,757 | 2,814 | |||||||||
Purchases of securities | (1,392 | ) | (1,824 | ) | (2,851 | ) | ||||||
Proceeds from Blue Racer | 115 | — | — | |||||||||
Restricted cash equivalents | 108 | 259 | (396 | ) | ||||||||
Other | 118 | 139 | 83 | |||||||||
Net cash provided by (used in) investing activities | (3,840 | ) | (3,321 | ) | 419 | |||||||
Financing Activities | ||||||||||||
Issuance of short-term debt, net | 598 | 429 | 91 | |||||||||
Issuance of short-term notes | 400 | — | — | |||||||||
Issuance and remarketing of long-term debt | 1,500 | 2,320 | 1,090 | |||||||||
Repayment and repurchase of long-term debt | (1,675 | ) | (637 | ) | (1,492 | ) | ||||||
Issuance of common stock | 265 | 38 | 74 | |||||||||
Repurchase of common stock | — | (601 | ) | (900 | ) | |||||||
Common dividend payments | (1,209 | ) | (1,129 | ) | (1,076 | ) | ||||||
Subsidiary preferred dividend payments | (16 | ) | (17 | ) | (17 | ) | ||||||
Other | (14 | ) | (25 | ) | (2 | ) | ||||||
Net cash provided by (used in) financing activities | (151 | ) | 378 | (2,232 | ) | |||||||
Increase in cash and cash equivalents | 146 | 40 | 12 | |||||||||
Cash and cash equivalents at beginning of year | 102 | 62 | 50 | |||||||||
Cash and cash equivalents at end of year | $ | 248 | $ | 102 | $ | 62 | ||||||
Supplemental Cash Flow Information | ||||||||||||
Cash paid (received) during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts | $ | 913 | $ | 920 | $ | 894 | ||||||
Income taxes | (58 | ) | 166 | 991 | ||||||||
Significant noncash investing and financing activities: | ||||||||||||
Accrued capital expenditures | 388 | 328 | 240 | |||||||||
Consolidation of VIE—assets at fair value | — | 957 | — | |||||||||
Consolidation of VIE—debt | — | 896 | — |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
59 |
Consolidated Statements of Cash Flows
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 |
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, 20102012 and 2009,2011, and the related consolidated statements of income, comprehensive income, common shareholder’s equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010.2012. 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, 20102012 and 2009,2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010,2012, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 25, 2011
[THIS PAGE INTENTIONALLY LEFT BLANK]
27, 2013
Virginia Electric and Power Company
Consolidated Statements of Income
Year Ended December 31, | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Operating Revenue | $ | 7,219 | $ | 6,584 | $ | 6,934 | $ | 7,226 | $ | 7,246 | $ | 7,219 | ||||||||||||
Operating Expenses | ||||||||||||||||||||||||
Electric fuel and other energy-related purchases | 2,495 | 2,972 | 2,707 | 2,368 | 2,506 | 2,495 | ||||||||||||||||||
Purchased electric capacity | 449 | 409 | 410 | 386 | 452 | 449 | ||||||||||||||||||
Other operations and maintenance: | ||||||||||||||||||||||||
Affiliated suppliers | 384 | 324 | 399 | 305 | 306 | 384 | ||||||||||||||||||
Other | 1,361 | 1,299 | 1,006 | 1,161 | 1,437 | 1,361 | ||||||||||||||||||
Depreciation and amortization | 671 | 641 | 608 | 782 | 718 | 671 | ||||||||||||||||||
Other taxes | 218 | 191 | 183 | 232 | 222 | 218 | ||||||||||||||||||
Total operating expenses | 5,578 | 5,836 | 5,313 | 5,234 | 5,641 | 5,578 | ||||||||||||||||||
Income from operations | 1,641 | 748 | 1,621 | 1,992 | 1,605 | 1,641 | ||||||||||||||||||
Other income | 100 | 104 | 52 | 96 | 88 | 100 | ||||||||||||||||||
Interest and related charges | 347 | 349 | 309 | 385 | 331 | 347 | ||||||||||||||||||
Income from operations before income tax expense | 1,394 | 503 | 1,364 | 1,703 | 1,362 | 1,394 | ||||||||||||||||||
Income tax expense | 542 | 147 | 500 | 653 | 540 | 542 | ||||||||||||||||||
Net Income | 852 | 356 | 864 | 1,050 | 822 | 852 | ||||||||||||||||||
Preferred dividends | 17 | 17 | 17 | 16 | 17 | 17 | ||||||||||||||||||
Balance available for common stock | $ | 835 | $ | 339 | $ | 847 | $ | 1,034 | $ | 805 | $ | 835 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Comprehensive Income
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
(millions) | ||||||||||||
Net income | $ | 1,050 | $ | 822 | $ | 852 | ||||||
Other comprehensive income (loss), net of taxes: | ||||||||||||
Net deferred losses on derivatives-hedging activities, net of $3, $3 and $1 tax | (5 | ) | (6 | ) | (1 | ) | ||||||
Changes in unrealized net gains on nuclear decommissioning trust funds, net of $(7), $(1) and $(6) tax | 13 | 2 | 9 | |||||||||
Amounts reclassified to net income: | ||||||||||||
Net derivative (gains) losses-hedging activities, net of $(2), $—and $4 tax | 2 | (1 | ) | (8 | ) | |||||||
Net realized gains on nuclear decommissioning trust funds, net of $2, $—and $2 tax | (4 | ) | — | (2 | ) | |||||||
Other comprehensive income (loss) | 6 | (5 | ) | (2 | ) | |||||||
Comprehensive income | $ | 1,056 | $ | 817 | $ | 850 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
62 |
Virginia Electric and Power Company
Consolidated Balance Sheets
At December 31, | 2012 | 2011 | ||||||
(millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 28 | $ | 29 | ||||
Customer receivables (less allowance for doubtful accounts of $10 and $11) | 849 | 892 | ||||||
Other receivables (less allowance for doubtful accounts of $3 and $7) | 51 | 145 | ||||||
Inventories (average cost method): | ||||||||
Materials and supplies | 385 | 359 | ||||||
Fossil fuel | 404 | 438 | ||||||
Prepayments | 23 | 41 | ||||||
Regulatory assets | 119 | 479 | ||||||
Deferred income taxes | 92 | — | ||||||
Other | 30 | 53 | ||||||
Total current assets | 1,981 | 2,436 | ||||||
Investments | ||||||||
Nuclear decommissioning trust funds | 1,515 | 1,370 | ||||||
Other | 14 | 36 | ||||||
Total investments | 1,529 | 1,406 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 30,631 | 28,626 | ||||||
Accumulated depreciation and amortization | (10,014 | ) | (9,615 | ) | ||||
Total property, plant and equipment, net | 20,617 | 19,011 | ||||||
Deferred Charges and Other Assets | ||||||||
Intangible assets | 181 | 183 | ||||||
Regulatory assets | 396 | 399 | ||||||
Other | 107 | 109 | ||||||
Total deferred charges and other assets | 684 | 691 | ||||||
Total assets | $ | 24,811 | $ | 23,544 |
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 |
63 |
At December 31, | 2012 | 2011 | ||||||
(millions) | ||||||||
LIABILITIESAND SHAREHOLDER’S EQUITY | ||||||||
Current Liabilities | ||||||||
Securities due within one year | $ | 418 | $ | 616 | ||||
Short-term debt | 992 | 894 | ||||||
Accounts payable | 430 | 405 | ||||||
Payables to affiliates | 67 | 108 | ||||||
Affiliated current borrowings | 435 | 187 | ||||||
Accrued interest, payroll and taxes | 204 | 226 | ||||||
Derivative liabilities | 33 | 135 | ||||||
Customer deposits | 100 | 106 | ||||||
Regulatory liabilities | 32 | 178 | ||||||
Deferred income taxes | — | 91 | ||||||
Other | 296 | 175 | ||||||
Total current liabilities | 3,007 | 3,121 | ||||||
Long-Term Debt | 6,251 | 6,246 | ||||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes and investment tax credits | 3,879 | 3,180 | ||||||
Asset retirement obligations | 705 | 624 | ||||||
Regulatory liabilities | 1,285 | 1,095 | ||||||
Other | 194 | 271 | ||||||
Total deferred credits and other liabilities | 6,063 | 5,170 | ||||||
Total liabilities | 15,321 | 14,537 | ||||||
Commitments and Contingencies (see Note 22) | ||||||||
Preferred Stock Not Subject to Mandatory Redemption | 257 | 257 | ||||||
Common Shareholder’s Equity | ||||||||
Common stock-no par(1) | 5,738 | 5,738 | ||||||
Other paid-in capital | 1,113 | 1,111 | ||||||
Retained earnings | 2,357 | 1,882 | ||||||
Accumulated other comprehensive income | 25 | 19 | ||||||
Total common shareholder’s equity | 9,233 | 8,750 | ||||||
Total liabilities and shareholder’s equity | $ | 24,811 | $ | 23,544 |
(1) | 500,000 shares authorized at December 31, 2012 and 2011; 274,723 shares outstanding at December 31, 2012 and 2011. |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
64 |
Virginia Electric and Power Company
Consolidated Statements of Common Shareholder’s Equity
At December 31, | 2010 | 2009 | ||||||
(millions) | ||||||||
LIABILITIESAND SHAREHOLDER’S EQUITY | ||||||||
Current Liabilities | ||||||||
Securities due within one year | $ | 15 | $ | 245 | ||||
Short-term debt | 600 | 442 | ||||||
Accounts payable | 499 | 390 | ||||||
Payables to affiliates | 76 | 67 | ||||||
Affiliated current borrowings | 103 | 2 | ||||||
Accrued interest, payroll and taxes | 214 | 213 | ||||||
Customer deposits | 116 | 117 | ||||||
Regulatory liabilities | 109 | 491 | ||||||
Deferred income taxes | 83 | — | ||||||
Accrued severance | 58 | — | ||||||
Other | 205 | 241 | ||||||
Total current liabilities | 2,078 | 2,208 | ||||||
Long-Term Debt | 6,702 | 6,213 | ||||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes and investment tax credits | 2,672 | 2,359 | ||||||
Asset retirement obligations | 669 | 636 | ||||||
Regulatory liabilities | 1,174 | 995 | ||||||
Other | 203 | 277 | ||||||
Total deferred credits and other liabilities | 4,718 | 4,267 | ||||||
Total liabilities | 13,498 | 12,688 | ||||||
Commitments and Contingencies (see Note 23) | ||||||||
Preferred Stock Not Subject to Mandatory Redemption | 257 | 257 | ||||||
Common Shareholder’s Equity | ||||||||
Common stock—no par(1) | 5,738 | 4,738 | ||||||
Other paid-in capital | 1,111 | 1,110 | ||||||
Retained earnings | 1,634 | 1,299 | ||||||
Accumulated other comprehensive income | 24 | 26 | ||||||
Total common shareholder’s equity | 8,507 | 7,173 | ||||||
Total liabilities and shareholder’s equity | $ | 22,262 | $ | 20,118 |
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, 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 | ||||||||||||||||||
Net income | 822 | 822 | ||||||||||||||||||||||
Dividends | (574 | ) | (574 | ) | ||||||||||||||||||||
Other comprehensive loss, net of tax | (5 | ) | (5 | ) | ||||||||||||||||||||
Balance at December 31, 2011 | 275 | 5,738 | 1,111 | 1,882 | 19 | 8,750 | ||||||||||||||||||
Net income | 1,050 | 1,050 | ||||||||||||||||||||||
Dividends | (575 | ) | (575 | ) | ||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 2 | 2 | ||||||||||||||||||||||
Other comprehensive income, net of tax | 6 | 6 | ||||||||||||||||||||||
Balance at December 31, 2012 | 275 | $ | 5,738 | $ | 1,113 | $ | 2,357 | $ | 25 | $ | 9,233 |
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 EquityCash Flows
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 |
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net income | $ | 1,050 | $ | 822 | $ | 852 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization (including nuclear fuel) | 927 | 838 | 782 | |||||||||
Deferred income taxes and investment tax credits, net | 502 | 496 | 609 | |||||||||
Impairment of generation assets | — | 228 | — | |||||||||
Net reserves (payments) related to rate refunds | (151 | ) | 3 | (500 | ) | |||||||
Contributions to pension plans | — | — | (302 | ) | ||||||||
Charges (payments) related to workforce reduction program | (4 | ) | (53 | ) | 98 | |||||||
Other adjustments | (66 | ) | (40 | ) | (40 | ) | ||||||
Changes in: | ||||||||||||
Accounts receivable | 126 | 76 | (9 | ) | ||||||||
Affiliated accounts receivable and payable | (2 | ) | (7 | ) | 11 | |||||||
Inventories | 8 | (200 | ) | 17 | ||||||||
Deferred fuel expenses, net | 378 | 12 | (213 | ) | ||||||||
Prepayments | 18 | 24 | (10 | ) | ||||||||
Accounts payable | 19 | (117 | ) | 108 | ||||||||
Accrued interest, payroll and taxes | (22 | ) | 12 | 1 | ||||||||
Other operating assets and liabilities | (77 | ) | (70 | ) | 5 | |||||||
Net cash provided by operating activities | 2,706 | 2,024 | 1,409 | |||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions | (2,082 | ) | (1,885 | ) | (2,113 | ) | ||||||
Purchases of nuclear fuel | (206 | ) | (205 | ) | (121 | ) | ||||||
Purchases of securities | (638 | ) | (1,057 | ) | (1,211 | ) | ||||||
Proceeds from sales of securities | 626 | 1,030 | 1,192 | |||||||||
Restricted cash equivalents | 22 | 137 | (165 | ) | ||||||||
Other | (4 | ) | 33 | (7 | ) | |||||||
Net cash used in investing activities | (2,282 | ) | (1,947 | ) | (2,425 | ) | ||||||
Financing Activities | ||||||||||||
Issuance of short-term debt, net | 98 | 294 | 158 | |||||||||
Issuance of affiliated current borrowings, net | 248 | 85 | 1,101 | |||||||||
Issuance and remarketing of long-term debt | 450 | 235 | 605 | |||||||||
Repayment and repurchase of long-term debt | (641 | ) | (91 | ) | (347 | ) | ||||||
Common dividend payments | (559 | ) | (557 | ) | (500 | ) | ||||||
Preferred dividend payments | (16 | ) | (17 | ) | (17 | ) | ||||||
Other | (5 | ) | (2 | ) | 2 | |||||||
Net cash provided by (used in) financing activities | (425 | ) | (53 | ) | 1,002 | |||||||
Increase (decrease) in cash and cash equivalents | (1 | ) | 24 | (14 | ) | |||||||
Cash and cash equivalents at beginning of year | 29 | 5 | 19 | |||||||||
Cash and cash equivalents at end of year | $ | 28 | $ | 29 | $ | 5 | ||||||
Supplemental Cash Flow Information | ||||||||||||
Cash paid (received) during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts | $ | 376 | $ | 376 | $ | 349 | ||||||
Income taxes | 225 | (27 | ) | (101 | ) | |||||||
Significant noncash investing and financing activities: | ||||||||||||
Accrued capital expenditures | 242 | 199 | 136 | |||||||||
Settlement of debt and issuance of common stock to Dominion | — | — | 1,000 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
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Virginia Electric and Power Company
Consolidated Statements of Comprehensive Income
Year Ended December 31, | 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 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Cash Flows
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.
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 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 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, 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.
Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of Peoplesoperations that are expected to be and certain DCI operations,are currently discontinued, which areis discussed in Notes 4 and 25, respectively.Note 3. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 2725 for further discussion of Dominion’s and Virginia Power’s operating segments.
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, expenses and expensescash flows 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.subsidiaries and those VIEs where Dominion has been determined to be the primary beneficiary.
Dominion and Virginia Power report certain contracts, instruments and investments at fair value. See Note 76 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 2221 for further information on these plans.
Certain amounts in the 20092011 and 20082010 Consolidated Financial Statements and footnotes have been reclassified to conform to the 20102012 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.
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, 20102012 and 20092011 included $466$411 million and $409$423 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity orand natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 20102012 and 20092011 included $397$348 million and $355$360 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 |
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 |
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 |
67
Combined Notes to Consolidated Financial Statements, Continued
Electric Fuel, Purchased Energy and Purchased Gas—DeferredGas-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.
Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 84%83% 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. 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 a substantial amount of Dominion’s and Virginia Power’s unrecognized tax benefits, the ultimate deductibility is highly certain; 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 expenseexpense. Changes in interest receivable related to net overpay-
ments of income taxes and estimated penalties that may result from the settlement of some uncertain tax positions are recognized in other income. In its Consolidated Statements of Income for 2010, 20092012, Dominion recognized interest income of $8 million and 2008,interest expense of $3 million and a reduction in penalties of less than $1 million. In 2011, Dominion recognized interest income of $12 million and interest expense of $7 million and a reduction in penalties of less than $1 million. In 2010, Dominion recognized a reduction in interest expense of $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, respectively.million. Dominion had accrued interest receivable of $27$5 million, and interest payable of $10 million and penalties payable of less than $1 million at December 31, 2010,2012 and interest receivable of $26$48 million, and interest payable of $10 million and penalties payable of $4less than $1 million at December 31, 2009.2011.
Virginia Power’s interest and penalties were immaterial in 2010, 20092012 and 2008.2010. In 2011, Virginia Power recognized interest income of $12 million, and penalties were immaterial. Virginia Power had accrued interest receivable of $17 million at December 31, 2011.
At December 31, 2010,2012, Virginia Power’s Consolidated Balance Sheet included $46$10 million of prepaid federal and state income taxes payable and $102$36 million of noncurrent federal and state income taxes payable.
At December 31, 2009,2011, Virginia Power’s Consolidated Balance Sheet included $21$18 million of prepaidcurrent federal income taxes $3receivable, $34 million of current state income taxes payable and $45$110 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, 20102012 and 2009,2011, Dominion’s accounts payable included $56$53 million and $55$75 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 20102012 and 2009,2011, Virginia Power’s accounts payable included $28$30 million and $22$40 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.
70
All derivatives, other 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
68 |
reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.
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 $244$212 million and $149$319 million associated with cash collateral at December 31, 20102012 and 2009,2011, respectively. Dominion had margin liabilities of $62$4 million and $114$66 million associated with cash collateral at December 31, 20102012 and 2009,2011, respectively. Virginia Power had margin assets of $18 million and $41 million associated with cash collateral at December 31, 2012 and 2011, respectively. Virginia Power’s margin assets and liabilities associated with cash collateral were not material at December 31, 20102012 and 2009.2011.
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. |
In Virginia Power’s generation operations, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.
DERIVATIVE INSTRUMENTS DESIGNATEDAS 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 relation-
shiprelationship 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 hedginghedg-
ing relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.
Cash Flow Hedges—A majority of 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. The Companies also use foreign currency contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which 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 useuses fair value hedges to mitigate the fixed price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, theyDominion and Virginia Power have designated interest rate swaps as fair value hedges on certain fixed-ratefixed 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 76 for further information about fair value measurements and associated valuation methods for derivatives. See Note 87 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, 20092012, 2011 and 2008,2010, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $102$91 million, $76$85 million and $88$102 million, respectively. In 2010, 20092012, 2011 and
69
Combined Notes to Consolidated Financial Statements, Continued
2008,2010, Virginia Power capitalized interest costs and AFUDC to property, plant and equipment of $61$31 million, $47$31 million and $21$61 million, respectively. Under current Virginia legislation,law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2010, 20092012, 2011 and 2008,2010, Virginia Power recorded $13$37 million, $34$20 million and $18$13 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 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.retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be retired or abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be retired or abandoned.
For Dominion and Virginia Power property that is not subject to cost-of-service rate regulation, including nonutility property, 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, | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | ||||||||||||||||||
(percent) | ||||||||||||||||||||||||
Dominion | ||||||||||||||||||||||||
Generation | 2.59 | 2.62 | 2.60 | 2.62 | 2.68 | 2.59 | ||||||||||||||||||
Transmission | 2.24 | 2.27 | 2.22 | 2.17 | 2.26 | 2.24 | ||||||||||||||||||
Distribution | 3.20 | 3.21 | 3.22 | 3.17 | 3.19 | 3.20 | ||||||||||||||||||
Storage | 2.75 | 2.83 | 2.87 | 2.59 | 2.64 | 2.75 | ||||||||||||||||||
Gas gathering and processing | 2.39 | 2.18 | 2.13 | 2.49 | 2.52 | 2.39 | ||||||||||||||||||
General and other | 4.60 | 4.33 | 4.35 | 4.55 | 4.66 | 4.60 | ||||||||||||||||||
Virginia Power | ||||||||||||||||||||||||
Generation | 2.59 | 2.62 | 2.60 | 2.62 | 2.68 | 2.59 | ||||||||||||||||||
Transmission | 1.94 | 1.92 | 2.03 | 1.98 | 2.03 | 1.94 | ||||||||||||||||||
Distribution | 3.33 | 3.33 | 3.37 | 3.32 | 3.33 | 3.33 | ||||||||||||||||||
General and other | 4.28 | 3.95 | 3.97 | 4.32 | 4.38 | 4.28 |
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 | ||||
Merchant generation—other | ||||
General and other |
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.
Dominion follows the full cost method of accounting for its gas and oil E&P activities, which subjects capitalized costs to 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 the ceiling test calculation.
At March 31,In 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 discontinuance of hedge accounting for certain cash flow hedges as discussed in 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).
In 2010, Dominion recognized a gain from the sale of substantially all of its Appalachian E&P operations, as discussed in Note 4.3.
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 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. A portion of Dominion’s and Virginia Power’s SO2 and NOX allowances are issued by the EPA at zero cost.
These allowances are amortized in the periods the emissions are generated, with the amortization reflected in DD&Adepreciation, depletion and amortization 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. See Note 6 for discussion of impairments related to emissions allowances.
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. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for a discussion of impairments related to certain long-lived assets and intangible assets with finite lives.
Intangible assets with finite lives are amortized over their estimated useful 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 that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.
The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions 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.
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 generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is
estimated using discounted cash flow analyses. Virginia PowerDominion reports accretion of the AROs associated with nuclear decommissioning of its nuclear power stations due to the passage of timenatural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Virginia Power reports accretion of AROs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions, consistent with the practice for its other cost-of-service rate regulated operations. Dominion and Virginia Power report accretionjurisdictions. Accretion of all other AROs is reported 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 beenare 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. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other available-for-sale securities, including those held in Dominion’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, |
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-M-ARKETABLEMARKETABLE 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. |
71
Combined Notes to Consolidated Financial Statements, Continued
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.other-than-temporary. If a decline in fair value of any security is determined to be other than temporary,other-than-temporary, the security is written down to its fair value at the end of the reporting period.
Decommissioning Trust Investments—Special Considerations
Ÿ |
|
Combined Notes to Consolidated Financial Statements, Continued
the FASB’s other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities. |
Ÿ | Debt Securities—Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion and Virginia Power |
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 the debt security before recovery of its fair value up to its cost basis. If that is the case, but the debt security 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. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.
Ÿ | Equity securities and other investments—Dominion’s and Virginia Power’s method of assessing other-than-temporary declines requires demonstrating the ability to hold individual securities for a period of time sufficient to allow for the anticipated recovery in their market value prior to the consideration of the other criteria mentioned above. Since the Companies have limited ability to oversee the day-to-day management of nuclear decommissioning trust fund investments, they do not have the ability to ensure investments are held through an anticipated recovery period. Accordingly, they consider all equity and other securities as well as non-marketable investments held in nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired. |
Inventories
Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory used in Dominion’sEast Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at $48$24 million and $30$48 million at December 31, 20102012 and 2009,December 31, 2011, respectively. Based on the average price of gas purchased during 20102012 and 2009,2011, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $107$69 million and $172$86 million, respectively. Stored gas inventory held by Hope and certain nonregulated gas operations is valued using the weighted-average cost method.
Gas Imbalances
Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion 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.
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. NDEWLY ADOPTED ACCOUNTING STANDARDSISPOSITIONS
2009Sale of Salem Harbor and State Line
NONCONTROLLING INTERESTSIN CONSOLIDATED FINANCIAL STATEMENTSIn August 2012, Dominion completed the sale of Salem Harbor. In the second quarter of 2012, the assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell. During the second quarter of 2012, Dominion completed the sale of State Line, which ceased operations in March 2012. See Note 6 for impairments related to these power stations.
Effective January 1, 2009, Dominion adopted new accounting guidance for noncontrolling interests that requires retrospective applicationThe following table presents selected information regarding the results of presentationoperations of Salem Harbor 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 identifiedState Line, which are classified 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 interestdiscontinued operations 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 recovery of their fair values up to their cost 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. 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 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.
See Note 7 for further information on fair value measurements.
ENDORSEMENT SPLIT-DOLLAR 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 guid-
ance resulted in an immaterial amount recognized through a cumulative effect of accounting change adjustment to retained earnings as of January 1, 2008.
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
(millions) | ||||||||||||
Operating revenue | $ | 57 | $ | 233 | $ | 269 | ||||||
Loss before income taxes(1) | (49 | ) | (34 | ) | (158 | ) |
NOTE 4. DISPOSITIONS
(1) | Includes long-lived asset impairment charges of $55 million and $194 million in 2011 and 2010, respectively. |
Sale of Appalachian E&P Operations
In April 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. The transaction includesincluded 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 resulted in an after-tax gain of approximately $1.4 billion, which includes a $134 million write-off of goodwill. Proceeds fromgoodwill, recorded in the sale have been or will be used to pay taxes on the gain, offset allsecond quarter of Dominion’s 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 Dominion Foundation, reduce debt and offset the majority of the impact of Virginia Power’s 2009 base rate case settlement.2010.
The results of operations for Dominion’s Appalachian E&P business are not reported as discontinued operations in the Consolidated Statements of Income since Dominion did not sell its entire U.S. cost pool.
Due to the 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.
72 |
Sale of Peoples
In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The sale resulted in an after-tax loss of approximately $140 million, 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.
Prior 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 Peoples were reclassified to discontinued operations in the Consolidated Statements of Income for all periods presented. Certain 2009 and 2008 amounts have been recast to reflect Peoples as discontinued operations.
Combined Notes to Consolidated Financial Statements, Continued
The carrying amounts of the major classes of assets and liabilities classified as held for sale in Dominion’s Consolidated Balance Sheets were as follows:
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, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income:
Year Ended December 31, | 2010 | 2009 | 2008 | 2010 | ||||||||||||
(millions) | ||||||||||||||||
Operating revenue | $ | 67 | $ | 432 | $ | 535 | $ | 67 | ||||||||
Income (loss) before income taxes(1) | (134 | )(2) | 42 | 119 | ||||||||||||
Loss before income taxes | (134 | )(1) |
(1) |
Includes a loss and other charges related to the sale of Peoples. |
NOTE 5.4. OPERATING REVENUE
Dominion’s and Virginia Power’s operating revenue consists of the following:
Year Ended December 31, | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Dominion | ||||||||||||||||||||||||
Electric sales: | ||||||||||||||||||||||||
Regulated | $ | 7,123 | $ | 6,477 | $ | 6,797 | $ | 7,102 | $ | 7,114 | $ | 7,123 | ||||||||||||
Nonregulated | 3,829 | 3,802 | 3,543 | 2,742 | 3,100 | 3,559 | ||||||||||||||||||
Gas sales: | ||||||||||||||||||||||||
Regulated | 308 | 494 | 877 | 250 | 287 | 308 | ||||||||||||||||||
Nonregulated | 2,010 | 2,315 | 3,114 | 1,071 | 1,635 | 2,010 | ||||||||||||||||||
Gas transportation and storage | 1,493 | 1,268 | 1,072 | 1,401 | 1,506 | 1,493 | ||||||||||||||||||
Other | 434 | 442 | 492 | 527 | 503 | 434 | ||||||||||||||||||
Total operating revenue | $ | 15,197 | $ | 14,798 | $ | 15,895 | $ | 13,093 | $ | 14,145 | $ | 14,927 | ||||||||||||
Virginia Power | ||||||||||||||||||||||||
Regulated electric sales | $ | 7,123 | $ | 6,477 | $ | 6,797 | $ | 7,102 | $ | 7,114 | $ | 7,123 | ||||||||||||
Other | 96 | 107 | 137 | 124 | 132 | 96 | ||||||||||||||||||
Total operating revenue | $ | 7,219 | $ | 6,584 | $ | 6,934 | $ | 7,226 | $ | 7,246 | $ | 7,219 |
NOTE 6.5. INCOME TAXES
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. 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.
In 2010,On January 2, 2013, 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 otherwise provides an extension of the fifty50 percent bonus depreciation allowance for qualifying capital expenditures incurred through 2013.
In December 2011, the IRS issued temporary regulations that provide guidance to taxpayers on the treatment of amounts paid to acquire, produce or improve tangible property and of dispositions of such property, including whether expenditures should be deducted as repairs or capitalized and depreciated on tax returns. Upon issuance, the temporary regulations were generally to be effective for expenditures made on or after January 1, 2012. However, there is uncertainty aboutin December 2012, in response to public comments received, the earliestIRS amended the temporary regulations to postpone the effective date on which construction of propertyuntil January 1, 2014.
Changes in tax treatment elected by Dominion or for a taxpayer could have begun in order to qualify forrequired by the full deduction of qualifying capital expenditures. Clarifying guidance is expected from the U.S. Treasury Department in 2011. For Dominion and Virginia Power,regulations will impact income taxes payable, have been reducedcash flows from operations and deferred tax liabilities have increased in 2010 as a resulttaxes. Except to the extent the implementation impacts deferred taxes and, therefore, the rate base used to establish customer rates for regulated utilities, results of claiming these benefits.operations are not expected to be materially affected.
Continuing Operations
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
Dominion | Virginia Power | Dominion(1) | Virginia Power(2) | |||||||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | 2012 | 2011 | 2010 | ||||||||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||||||||||
Current: | ||||||||||||||||||||||||||||||||||||||||||||||||
Federal | $ | 891 | $ | 952 | $ | 502 | $ | (78 | ) | $ | 465 | $ | 158 | $ | (117 | ) | $ | 3 | $ | 894 | $ | 70 | $ | (35 | ) | $ | (78 | ) | ||||||||||||||||||||
State | 308 | 129 | 115 | 10 | 91 | 37 | 80 | 9 | 309 | 81 | 79 | 10 | ||||||||||||||||||||||||||||||||||||
Total current | 1,199 | 1,081 | 617 | (68 | ) | 556 | 195 | |||||||||||||||||||||||||||||||||||||||||
Total current expense (benefit) | (37 | ) | 12 | 1,203 | 151 | 44 | (68 | ) | ||||||||||||||||||||||||||||||||||||||||
Deferred: | ||||||||||||||||||||||||||||||||||||||||||||||||
Federal | 764 | (424 | ) | 338 | 537 | (339 | ) | 279 | 214 | 694 | 818 | 482 | 484 | 537 | ||||||||||||||||||||||||||||||||||
State | 96 | (59 | ) | 3 | 74 | (69 | ) | 30 | (30 | ) | 50 | 93 | 21 | 13 | 74 | |||||||||||||||||||||||||||||||||
Total deferred | 860 | (483 | ) | 341 | 611 | (408 | ) | 309 | ||||||||||||||||||||||||||||||||||||||||
Total deferred expense | 184 | 744 | 911 | 503 | 497 | 611 | ||||||||||||||||||||||||||||||||||||||||||
Amortization of deferred investment tax credits | (2 | ) | (2 | ) | (5 | ) | (1 | ) | (1 | ) | (4 | ) | (1 | ) | (2 | ) | (2 | ) | (1 | ) | (1 | ) | (1 | ) | ||||||||||||||||||||||||
Total income tax expense | $ | 2,057 | $ | 596 | $ | 953 | $ | 542 | $ | 147 | $ | 500 | $ | 146 | $ | 754 | $ | 2,112 | $ | 653 | $ | 540 | $ | 542 |
(1) | In 2012, Dominion’s current federal income tax benefit includes a benefit related to the carryback of its current year operating loss, and deferred state income tax benefit reflects the impact of Brayton Point, Kincaid and Kewaunee impairment charges. In 2011, Dominion’s federal income tax expense includes a benefit related to its current year operating loss that is expected to be used in future years, and state income tax expense reflects changes in the amount of income apportioned among states, higher tax credits, claims for refunds and previously unrecognized tax benefits due to the expiration of statutes of limitations. |
(2) | In 2011, Virginia Power’s federal income tax expense includes a benefit related to a portion of its current year operating loss that is expected to be used in future years. Also, in 2011 and 2010, Virginia Power’s federal income tax expense reflects the amounts of current year operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries. |
73
Combined Notes to Consolidated Financial Statements, Continued
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, | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | 2012 | 2011 | 2010 | ||||||||||||||||||||||||||||||||||||
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. Appalachian E&P business | 0.9 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
Legislative change | 1.1 | 0.4 | (0.1 | ) | 1.1 | — | (0.4 | ) | ||||||||||||||||||||||||||||||||||||||||
State taxes, net of federal benefit | 5.0 | 2.4 | 2.5 | 3.8 | 2.8 | 3.6 | 8.1 | 1.8 | 5.1 | 3.9 | 4.4 | 3.8 | ||||||||||||||||||||||||||||||||||||
Valuation allowances | 0.1 | (0.4 | ) | 0.5 | — | — | — | (1.5 | ) | — | (0.2 | ) | — | — | — | |||||||||||||||||||||||||||||||||
Domestic production activities deduction | (0.4 | ) | (2.9 | ) | (0.5 | ) | (0.3 | ) | (4.5 | ) | (0.5 | ) | ||||||||||||||||||||||||||||||||||||
Investment and production tax credits | (0.3 | ) | (1.5 | ) | (0.1 | ) | — | (0.2 | ) | (0.1 | ) | |||||||||||||||||||||||||||||||||||||
Production tax credits | (2.4 | ) | (0.6 | ) | (0.3 | ) | — | — | — | |||||||||||||||||||||||||||||||||||||||
Amortization of investment tax credits | — | (0.1 | ) | (0.2 | ) | (0.1 | ) | (0.2 | ) | (0.3 | ) | (0.3 | ) | (0.1 | ) | — | (0.1 | ) | (0.1 | ) | (0.1 | ) | ||||||||||||||||||||||||||
AFUDC – equity | (0.4 | ) | (1.0 | ) | (0.3 | ) | (1.1 | ) | (3.4 | ) | (0.5 | ) | ||||||||||||||||||||||||||||||||||||
AFUDC—equity | (4.1 | ) | (0.6 | ) | (0.4 | ) | (0.9 | ) | (0.8 | ) | (1.1 | ) | ||||||||||||||||||||||||||||||||||||
Employee stock ownership plan deduction | (0.3 | ) | (0.8 | ) | (0.5 | ) | — | — | — | (3.1 | ) | (0.7 | ) | (0.3 | ) | — | — | — | ||||||||||||||||||||||||||||||
Pension and other benefits | — | (0.6 | ) | (0.3 | ) | — | (0.6 | ) | (0.2 | ) | ||||||||||||||||||||||||||||||||||||||
Goodwill | 0.4 | — | 0.9 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
Legislative change | — | — | 1.1 | — | — | 1.1 | ||||||||||||||||||||||||||||||||||||||||||
Other, net | 0.1 | 1.3 | 0.5 | 0.5 | 0.4 | 0.1 | (2.8 | ) | (0.6 | ) | (0.2 | ) | 0.4 | 1.2 | 0.2 | |||||||||||||||||||||||||||||||||
Effective tax rate | 40.8 | % | 31.8 | % | 36.5 | % | 38.9 | % | 29.3 | % | 36.7 | % | 29.3 | % | 34.2 | % | 40.7 | % | 38.3 | % | 39.7 | % | 38.9 | % |
Dominion’s effective tax rate in 2012 reflects the amplified effect of permanent differences due to lower pre-tax income, as well as the state tax impact of Brayton Point, Kincaid and Kewaunee impairment charges. The rate also reflects a $20 million reduction of a valuation allowance related to state operating loss carryforwards attributable to Fairless and a $14 million increase in valuation allowance related to Brayton Point state credit carryforwards. After considering the results of Fairless’ operations in recent years and a forecast of future operating results reflecting Dominion’s planned purchase of the facility, Dominion has concluded that it is more likely than not that the tax benefit of the operating losses will be realized. Significant assumptions include future commodity prices, in particular, those for electric energy produced by Fairless and those for natural gas, as compared to other fuels used for the generation of electricity, which will significantly influence the extent to which Fairless is dispatched by PJM. Also, in connection with its intention to sell Brayton Point, Dominion evaluated state tax credits previously recognized for the power station and recorded a $14 million increase in valuation allowance related to credit carryforwards and a $14 million deferred tax liability, representing recapture of credits claimed in prior years that would result upon completion of a sale. Dominion will continue to evaluate the likelihood of realizing these tax benefits on a quarterly basis.
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 addition, Dominion’s effective tax rate in 2010 includes higher state income taxes and the impact of goodwill written off that is not deductible for tax purposes associated with the sale 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 result of working with the IRS under its Pre-Filing Program. The objective of the Pre-Filing Program is to provide taxpayers with greater certainty regarding a specific issue at an earlier point in time than can be attained under the normal post-filing examination process.
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts 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, | 2010 | 2009 | 2010 | 2009 | 2012 | 2011 | 2012 | 2011 | ||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Deferred income taxes: | ||||||||||||||||||||||||||||||||
Total deferred income tax assets | $ | 1,642 | $ | 1,839 | $ | 402 | $ | 533 | $ | 2,505 | $ | 2,229 | $ | 466 | $ | 503 | ||||||||||||||||
Total deferred income tax liabilities | 6,233 | 5,683 | 3,139 | 2,652 | 7,716 | 7,424 | 4,238 | 3,759 | ||||||||||||||||||||||||
Total net deferred income tax liabilities | $ | 4,591 | $ | 3,844 | $ | 2,737 | $ | 2,119 | $ | 5,211 | $ | 5,195 | $ | 3,772 | $ | 3,256 | ||||||||||||||||
Total deferred income taxes: | ||||||||||||||||||||||||||||||||
Plant and equipment, primarily depreciation method and basis differences | $ | 3,027 | $ | 2,877 | $ | 2,109 | $ | 1,934 | $ | 4,601 | $ | 4,008 | $ | 3,394 | $ | 2,758 | ||||||||||||||||
Nuclear decommissioning | 749 | 689 | 343 | 307 | 994 | 913 | 407 | 374 | ||||||||||||||||||||||||
Deferred state income taxes | 446 | 416 | 228 | 152 | 474 | 493 | 265 | 243 | ||||||||||||||||||||||||
Federal benefit of deferred state income taxes | (166 | ) | (173 | ) | (93 | ) | (85 | ) | ||||||||||||||||||||||||
Deferred fuel, purchased energy and gas costs | 120 | 12 | 111 | 7 | 3 | 161 | (16 | ) | 144 | |||||||||||||||||||||||
Pension benefits | 521 | 351 | 26 | (49 | ) | 231 | 396 | (17 | ) | 8 | ||||||||||||||||||||||
Other postretirement benefits | (186 | ) | (216 | ) | (14 | ) | (29 | ) | (171 | ) | (167 | ) | (7 | ) | (13 | ) | ||||||||||||||||
Loss and credit carryforwards | (181 | ) | (192 | ) | — | — | (656 | ) | (577 | ) | (77 | ) | (55 | ) | ||||||||||||||||||
Reserve for rate proceedings | (56 | ) | (179 | ) | (56 | ) | (179 | ) | — | (54 | ) | — | (54 | ) | ||||||||||||||||||
Partnership basis differences | 265 | 236 | — | — | 174 | 274 | — | — | ||||||||||||||||||||||||
Valuation allowances | 68 | 62 | — | — | 93 | 96 | — | — | ||||||||||||||||||||||||
Other | (182 | ) | (212 | ) | (10 | ) | (24 | ) | (366 | ) | (175 | ) | (84 | ) | (64 | ) | ||||||||||||||||
Total net deferred income tax liabilities | $ | 4,591 | $ | 3,844 | $ | 2,737 | $ | 2,119 | $ | 5,211 | $ | 5,195 | $ | 3,772 | $ | 3,256 |
At December 31, 2010,2012, Dominion had the following deductible loss and credit carryforwards:
Ÿ | Federal loss carryforwards of |
Ÿ | Federal production tax credits of $26 million that expire if unutilized through 2032; |
Ÿ | State loss carryforwards of |
Ÿ | State minimum tax credits of |
Ÿ | State investment tax credits of $28 million that expire if unutilized through 2016. A valuation allowance on $21 million of these credits has been established for credits that are not expected to be utilized. |
There were no loss or credit carryforwards forAt December 31, 2012, Virginia Power at December 31, 2010.had federal loss carryforwards of $220 million that expire if unutilized through 2031.
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 financial statements by increasing income taxes payable, reducing
74 |
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, thean 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 | |||||||||||||||||||||||||||||||||||||||||||||
2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | 2012 | 2011 | 2010 | |||||||||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||||||||||
Balance at January 1 | $ | 291 | $ | 404 | $ | 407 | $ | 121 | $ | 180 | $ | 195 | $ | 347 | $ | 307 | $ | 291 | $ | 114 | $ | 117 | $ | 121 | ||||||||||||||||||||||||
Increases—prior period positions | 34 | 51 | 42 | 4 | 11 | 20 | 28 | 127 | 34 | 4 | 22 | 4 | ||||||||||||||||||||||||||||||||||||
Decreases—prior period positions | (59 | ) | (142 | ) | (54 | ) | (28 | ) | (71 | ) | (22 | ) | (106 | ) | (119 | ) | (75 | ) | (80 | ) | (51 | ) | (33 | ) | ||||||||||||||||||||||||
Current period positions | 61 | 43 | 63 | 25 | 22 | 20 | ||||||||||||||||||||||||||||||||||||||||||
Prior period positions becoming otherwise deductible in current period | (16 | ) | (36 | ) | (21 | ) | (5 | ) | (9 | ) | (11 | ) | ||||||||||||||||||||||||||||||||||||
Increases—current period positions | 43 | 64 | 61 | 24 | 47 | 25 | ||||||||||||||||||||||||||||||||||||||||||
Decreases—current period positions | — | (21 | ) | — | — | (21 | ) | — | ||||||||||||||||||||||||||||||||||||||||
Settlements with tax authorities | — | (13 | ) | (33 | ) | — | (9 | ) | (22 | ) | (4 | ) | — | — | (4 | ) | — | — | ||||||||||||||||||||||||||||||
Expiration of statutes of limitation | (4 | ) | (16 | ) | — | — | (3 | ) | — | (15 | ) | (11 | ) | (4 | ) | (1 | ) | — | — | |||||||||||||||||||||||||||||
Balance at December 31 | $ | 307 | $ | 291 | $ | 404 | $ | 117 | $ | 121 | $ | 180 | $ | 293 | $ | 347 | $ | 307 | $ | 57 | $ | 114 | $ | 117 |
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may 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 statutes of limitation. For Dominion and its subsidiaries, these unrecognized tax benefits were $133$167 million, $95$184 million and $121$133 million at December 31, 2010, 20092012, 2011 and 2008,2010, respectively. For Dominion, the change in these unrecognized tax benefits increased income tax expense by $1 million, $51 million and $38 million in 2012, 2011 and 2010, decreased income tax expense by $26 million in 2009 and increased tax expense by $25 million in 2008.respectively. For Virginia Power, these unrecognized tax benefits were $14$13 million, $14$20 million and $21$14 million at December 31, 2010, 20092012, 2011 and 2008,2010, respectively. For Virginia Power, the change in these unrecognized tax benefits increased income tax expense by $1 million, $6 million and by less than $1 million in 2012, 2011 and 2010, decreased income tax expense by $7 million in 2009 and increased income tax expense by $13 million in 2008.respectively.
A 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; 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. Pending resolution of these uncertainties, interest is 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 2004, except that2008. For prior years, Dominion had reserved the right to pursue refunds related to certain deductions has been reservedthe calculation of interest to be capitalized in connection with improvements to in-service plant and equipment for the years 1995 through 2003.2007. The IRS position had provided that capitalized interest must also be computed on the adjusted tax basis of in-service assets that are idled while making improvements to them. In response to litigation initiated by Dominion in March 2008, the U.S. Court of Federal Claims ruled in February 2011, sustaining the IRS position. In July 2011, Dominion filed an appeal with the United States Court of Appeals for the Federal Circuit and, in May 2012, the U.S. Court of Appeals for the Federal Circuit ruled in favor of Dominion. The resolution of this matter did not have a material impact on the Companies’ cash flows, results of operations or financial condition.
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,January 2012, the Appellate Division of the IRS informed Dominion that the Joint Committee had approvedcompleted its review of the settlement of tax years 20022004 and 20032005 for Dominion and its
consolidated subsidiaries. Dominion received a refundSince the measurement of $54 millionunrecognized tax benefits in November 2010. The2011 considered the results of completed settlement excludes two issues, for which Dominion has reserved the right to litigate and pursue claims for refunds.negotiations, Dominion’s results of operations in 2012 were not affected.
In 2009,April 2012, the Joint Committee completedIRS issued its review ofRevenue Agent Report for Dominion’s settlement with the Appellate Division of the IRSconsolidated tax returns for tax years 1999 through 2001. Dominion2006 and 2007, reflecting the resolution of all issues, except the capitalized interest on idle property issue that was entitledin litigation at that time but later resolved as discussed above.
The IRS examination of tax years 2008, 2009 and 2010 began in the first quarter of 2012 and was later expanded to a $60 million refund,include examination of which $20 million was applied as an estimated payment for 2009 taxes and $40 million was paidthe 2011 tax year. The audit is expected to Dominionbe concluded 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.late 2013.
During examinations by tax authorities in 2011, itIt is reasonably possible that Dominionsettlements with and payments to tax authorities in 2013 and the expiration of statutes of limitations could agree to apply procedures used previously to resolve similar tax return filing positions, reducing Dominion’sreduce unrecognized tax benefits for Dominion and Virginia Power by $50 millionup to $70$65 million and Virginia Power’s unrecognized tax benefits by $30$35 million, to $35 million. Dominion’s unrecognized tax benefits could also be reduced by $15 million, including $5 million for Virginia Power, to recognize prior period amounts becoming otherwise deductible in 2011.respectively. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, Dominion’s earnings could increase by up to $25$10 million, with no material impact onand Virginia Power’s earnings.earnings would not be affected.
Otherwise, with regard to 20102012 and prior years, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2011.2013.
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. |
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
IncomeDominion’s effective tax expenserate for 2012 reflects the dispositions of State Line and Salem Harbor.
Dominion’s effective tax rate for 2011 reflects an expectation that State Line’s deferred tax assets, including 2011 operating losses, will not be realized in 2010State Line’s separately filed state tax returns.
Dominion’s effective tax rate for Dominion’s discontinued operations primarily2010 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.
75
Combined Notes to Consolidated Financial Statements, Continued
NOTE 7.6. 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.
Inputs and Assumptions
The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, they seek price information is sought 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.
Dominion’s and Virginia Power’s commodity derivative valuations are prepared by the ERM department. The ERM department reports directly to the Companies’ CFO. The ERM department creates a daily file containing market valuations for the Companies’ derivative transactions. The inputs that go into the market valuations are transactional information stored in the systems of record and market pricing information that resides in data warehouses. The majority of forward prices are automatically uploaded into the data warehouses from various third-party sources. Inputs obtained from third-party sources are evaluated for
reliability considering the reputation, independence, market presence, and methodology used by the third-party. If forward prices are not available from third-party sources, then the ERM department models the forward prices based on other available market data. A team consisting of risk management and risk quantitative analysts meets each business day to assess the validity of market prices and valuations. During this meeting, the changes in market valuations from period to period are examined and qualified against historical expectations. If any discrepancies are identified during this process, the mark-to-market valuations or the market pricing information is evaluated further and adjusted, if necessary.
For options and contracts with option-like characteristics where observable pricing information is not available from external sources, 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 | Transaction 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 | Volumes |
Ÿ | Credit enhancements |
Ÿ | Time value |
Combined Notes to Consolidated Financial Statements, Continued
For investments:
Ÿ | Quoted securities prices and indices |
Ÿ | Securities trading information including volume and restrictions |
Ÿ | Maturity |
Ÿ | Interest rates |
Ÿ | Credit quality |
Ÿ | NAV (only for alternative investments) |
76 |
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.
Levels
The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:
Ÿ | Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as 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, restricted cash equivalents, and 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. |
Ÿ | Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for Dominion and Virginia Power consist of long-dated commodity derivatives, FTRs and other modeled commodity derivatives. Additional instruments categorized in Level 3 for Dominion include NGLs and natural gas peaking options and alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments, held in benefit plan trust funds. |
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the appli-
cableapplicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.
For derivative contracts, Dominion and Virginia Power recognize transfers among Level 1, Level 2 and Level 3 based on fair
values as of the first day of the month in which the transfer occurs. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.
Level 3 Valuations
Fair value measurements are categorized as Level 3 when a significant amount of price or other inputs that are considered to be unobservable are used in their valuations. Long-dated commodity derivatives are generally based on unobservable inputs due to the length of time to settlement and the absence of market activity and are therefore categorized as Level 3. For NGL derivatives, market illiquidity requires a valuation based on proxy markets that do not always correlate to the actual instrument, therefore they are categorized as Level 3. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from ISO auctions, which is accurate for day-one valuation, butare generally is not considered to be representative of the ultimate settlement values.liquid markets. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets. Alternative investments are categorized as Level 3 due to the absence of quoted market prices, illiquidity and the long-term nature of these assets. These investments are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date.
For derivative contracts, Dominion and Virginia Power recognize transfers among Level 1, Level 2enter into certain physical and financial forwards and futures, options, and full requirements contracts, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards, futures, and full requirements contracts. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on fair values asforward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. Full requirements contracts add load shaping and usage factors in addition to the discounted cash flow model inputs. An option model is used to value Level 3 physical and financial options. The option model calculates mark-to-market valuations using variations of the first dayBlack-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the month in whichoption expiration dates, the transfer occurs. Transfers out of Level 3 represent assetsoption strike prices, price correlations, the original sales prices, and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.
At December 31, 2010, Dominion’s and Virginia Power’s net balance of commodity derivatives categorized asvolumes. For Level 3 fair value measurements, was a net liabilitythe forward market prices, the implied price volatilities, price correlations, load shaping, and usage factors are considered unobservable. The unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.
77
Combined Notes to Consolidated Financial Statements, Continued
The following table presents Dominion’s quantitative information about Level 3 fair value measurements. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility, price correlations, load shaping, and usage factors.
Fair Value (millions) | Valuation Techniques | Unobservable Input | Range | Weighted Average(1) | ||||||||||||||||||
At December 31, 2012 | ||||||||||||||||||||||
Assets: | ||||||||||||||||||||||
Physical and Financial Forwards and Futures: | ||||||||||||||||||||||
Natural Gas(2) | $ | 13 | Discounted Cash Flow | Market Price (per Dth) | (3 | ) | (1) – 6 | 3 | ||||||||||||||
Electricity | 6 | Discounted Cash Flow | Market Price (per MWh) | (3 | ) | 30 – 85 | 50 | |||||||||||||||
FTRs | 5 | Discounted Cash Flow | Market Price (per MWh) | (3 | ) | (6) – 7 | 1 | |||||||||||||||
Capacity | 7 | Discounted Cash Flow | Market Price (per MW) | (3 | ) | 95 – 115 | 101 | |||||||||||||||
Liquids(8) | 21 | Discounted Cash Flow | Market Price (per Gal) | (3 | ) | 0 – 3 | 1 | |||||||||||||||
Physical and Financial Options: | ||||||||||||||||||||||
Natural Gas | 5 | Option Model | Market Price (per Dth) | (3 | ) | 3 – 5 | 4 | |||||||||||||||
Price Volatility | (4 | ) | 21% – 36% | 24 | % | |||||||||||||||||
Price Correlation | (5 | ) | 73% – 73% | 73 | % | |||||||||||||||||
Full Requirements Contracts: | ||||||||||||||||||||||
Electricity | 27 | Discounted Cash Flow | Market Price (per MWh) | (3 | ) | 8 – 439(9) | 40 | |||||||||||||||
Load Shaping | (6 | ) | 0% – 10% | 5 | % | |||||||||||||||||
Usage Factor | (7 | ) | 2% – 16% | 8 | % | |||||||||||||||||
Total assets | $ | 84 | ||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||
Physical and Financial Forwards and Futures: | ||||||||||||||||||||||
Natural Gas(2) | $ | 18 | Discounted Cash Flow | Market Price (per Dth) | (3 | ) | (1) – 18 | 3 | ||||||||||||||
Electricity | 1 | Discounted Cash Flow | Market Price (per MWh) | (3 | ) | 25 – 65 | 39 | |||||||||||||||
FTRs | 3 | Discounted Cash Flow | Market Price (per MWh) | (3 | ) | (1) – 18 | 0 | |||||||||||||||
Liquids(8) | 25 | Discounted Cash Flow | Market Price (per Gal) | (3 | ) | 1 – 3 | 2 | |||||||||||||||
Physical and Financial Options: | ||||||||||||||||||||||
Natural Gas(2) | 12 | Option Model | Market Price (per Dth) | (3 | ) | 3 – 8 | 5 | |||||||||||||||
Price Volatility | (4 | ) | 21% – 36% | 32 | % | |||||||||||||||||
Price Correlation | (5 | ) | 99% | 99 | % | |||||||||||||||||
Total liabilities | $ | 59 |
(1) | Averages weighted by volume. |
(2) | Includes basis. |
(3) | Represents market prices beyond defined terms for Levels 1 & 2. |
(4) | Represents volatilities unrepresented in published markets. |
(5) | Represents intra-price correlations for which markets do not exist. |
(6) | Converts block monthly loads to 24-hour load shapes. |
(7) | Represents expected increase (decrease) in sales volumes compared to historical usage. |
(8) | Includes NGLs. |
(9) | The range in market prices is the result of large variability in hourly power prices during peak and off-peak hours. |
Sensitivity of $50 million and a net asset of $14 million, respectively. A hypothetical 10% increasethe fair value measurements to changes in commodity prices would increase Dominion’s net liability by $69 million and decrease Virginia Power’s net asset by $2 million. A hypothetical 10% decrease in commodity prices would decrease Dominion’s net liability by $66 million and increase Virginia Power’s net asset by $2 million.the significant unobservable inputs is as follows:
Significant Unobservable Inputs | Position | Change to Input | Impact on Fair Value Measurement | |||||
Market Price | Buy | Increase (decrease) | Gain (loss) | |||||
Market Price | Sell | Increase (decrease) | Loss (gain) | |||||
Price Volatility | Buy | Increase (decrease) | Gain (loss) | |||||
Price Volatility | Sell | Increase (decrease) | Loss (gain) | |||||
Price Correlation | Buy | Increase (decrease) | Loss (gain) | |||||
Price Correlation | Sell | Increase (decrease) | Gain (loss) | |||||
Load Factor | Sell(1) | Increase (decrease) | Loss (gain) | |||||
Usage Factor | Sell(2) | Increase (decrease) | Gain (loss) |
(1) | Assumes the contract is in a gain position and load increases during peak hours. |
(2) | Assumes the contract is in a gain position. |
Nonrecurring Fair Value Measurements
Partnership investments held by Virginia Power’s nuclear decommissioning trust fundsMERCHANT POWER STATIONS
In the third quarter of 2012, Dominion decided to pursue the sale of Brayton Point and Dominion’s rabbi trust funds are accountedKincaid, as well as its 50% interest in Elwood, which is an equity method investment. Since Dominion is unlikely to operate the Brayton Point and Kincaid facilities
through their estimated useful lives, Dominion evaluated these power stations for recoverability under a probability weighted approach and concluded that the carrying values of these facilities were not impaired as cost method investments. These investments are only subjectof September 30, 2012.
At December 31, 2012, Dominion updated its recoverability analysis for Brayton Point and Kincaid to reflect bids received and an updated probability weighting. As a result of this updated evaluation, Dominion recorded an impairment charge of approximately $1.6 billion ($1.0 billion after-tax), which is included in other operations and maintenance expense in its Consolidated Statement of Income, to write down Brayton Point’s and Kincaid’s long-lived assets to their estimated fair value of approximately $216 million. Dominion used a market approach to estimate the fair value of Brayton Point’s and Kincaid’s long-lived assets. This was considered a Level 2 fair value measurement given it was based on a non-recurring basis when they have experienced an impairment, and are categorizedbids received.
Any sale of Brayton Point, Kincaid, or Dominion’s 50% interest in Elwood would be subject to the approval of Dominion’s Board of Directors, as Level 3 fair value measurements. During 2009, substantially all of these partnership investments experienced impairments. During 2010, these partnership investments did not experience material impairments, therefore no such nonrecurring fair value measurements occurred.
In connection with partnership investments, Dominion and Virginia Power (as a limited partner) make capital commitmentswell as applicable regulatory approvals.
In April 2011, Dominion announced it would pursue a sale of Kewaunee since it was not able to move forward with its original plan to grow its nuclear fleet in the Midwest to take advantage of economies of scale. Dominion was unable to find a buyer for the facility. In addition, the power purchase agreements for the two utilities that are called overcontract to buy Kewaunee’s generation will expire in December 2013 at a time asof projected low wholesale electricity prices in the general partner makes investments. Investment strategiesregion. At September 30, 2012, Dominion expected that it would permanently cease generation operations at Kewaunee in 2013 and commence decommissioning of the Companies’ partnership investments are primarily real estate and private equity-based. The typical term of these partnership investments is 10-15 years. The Companies have limited withdrawal or redemption rights during the term of the partnership. As a general rule, a limited partner’s interest can be sold in the secondary markets subject to the approval of the general partner. The secondary market tends to be illiquid especially during periods of market stress. Funds are returned to Dominion and Virginia Power as income, profits and capital are distributed over the term of the partnership.
Presented below are the fair values, unfunded commitments and estimated liquidation periods for partnership investments held by Virginia Power’s decommissioning trust funds and Dominion’s rabbi trust funds at December 31, 2009:
Fair Value of Investments | Unfunded Commitments | Estimated Period of Liquidation | ||||||||||
(millions) | (average years) | |||||||||||
Decommissioning trust funds | ||||||||||||
Other investments | $ | 78 | $ | 50 | 7 | |||||||
Real estate | 19 | 30 | 5 | |||||||||
Total | 97 | 80 | 6 | |||||||||
Rabbi trust funds | ||||||||||||
Other investments | 10 | 3 | 5 | |||||||||
Real estate | 7 | 7 | 4 | |||||||||
Total | 17 | 10 | 4 | |||||||||
Total decommissioning and rabbi trust funds | $ | 114 | $ | 90 | 6 |
During 2009, Dominion evaluated an equity method investment for impairment and recorded a $30 million impairment in other income in its Consolidated Statement of Income. The resulting fair value of $4 million was estimated using a discounted cash flow model and is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future equity distributions based on the investee’s future financing structure, contractual and market-based revenues and operating costs.
During 2010, Dominion evaluated State Line, a coal-fired merchant power station with minimal environmental controls, for impairment due to the station’s relatively low level of profitability combined with the EPA’s issuance in June 2010 of a new stringent 1-hour primary NAAQS for SO2 that will likely require significant environmental capital expenditures in the future.facility. As a result, Dominion evaluated Kewaunee for impairment since it was more likely than not that Kewaunee would be retired before the end of this evaluation, Dominion recorded an impairment charge of $163 million ($107 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down State Line’s long-lived assets to theirpreviously estimated fair value of $59 million.useful life. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion relied onused the income approach (discounted cash flows) to estimate the fair value of State Line’sKewaunee’s long-lived assets. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs including estimates of future power and other commodity prices.
As a result of this evaluation in September 2012, Dominion recorded impairment and other charges of $435 million ($281 million after-tax) largely reflected in other operations and maintenance expense in its Consolidated Statement of Income. This primarily reflects a $378 million ($244 million after-tax) charge for the full impairment of Kewaunee’s long-lived assets, a write down of materials and supplies inventories of $33 million ($21 million after-tax), and a $24 million ($16 million after-tax) charge related to severance costs.
The decision to decommission Kewaunee was approved by Dominion’s Board of Directors in October 2012 after consideration of the factors discussed above, which made it uneconomic for Kewaunee to continue operations. The station is expected to cease power production in the second quarter of 2013 and commence decommissioning activities. Following station shutdown, Dominion plans to meet its obligations to the two utilities that purchase Kewaunee’s generation through market purchases, until the power purchase agreements expire in December 2013.
In June 2010, Dominion evaluated State Line for impairment due to the station’s relatively low level of profitability combined with the EPA’s issuance of a new stringent 1-hour primary NAAQS for SO2 that would likely require significant environmental capital expenditures in the future. As a result of this evaluation, Dominion recorded an impairment charge of $163 million ($107 million after-tax), which is now reflected in loss from discontinued operations in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of $59 million.
During March 2011, Dominion determined that it was unlikely that State Line would participate in the May 2011 PJM capacity base residual auction that would commit State Line’s capacity from June 2014 through May 2015. This determination reflected an expectation that margins for coal-fired generation will remain compressed in the 2014 and 2015 period in combination with the expectation that State Line may be impacted during the same time period by environmental regulations that would likely require significant capital expenditures. As a result, Dominion evaluated State Line for impairment since it was more likely than
not that State Line would be retired before the end of its previously estimated useful life. As a result of this evaluation, Dominion recorded an impairment charge of $55 million ($39 million after-tax), which is now reflected in loss from discontinued operations in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of less than $1 million. State Line was retired in March 2012 and sold in the second quarter of 2012.
In December 2010, Dominion recorded an impairment charge of $31 million ($20 million after-tax), which is now reflected in otherloss from discontinued operations and maintenance expense in its Consolidated Statement of Income, to write down the long-lived assets of Salem Harbor to their estimated fair value of less than $1 million as a result of profitability issues.
As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion relied onused the income approach (discounted cash flows) to estimate the fair value of State Line’s and Salem Harbor’s long-lived assets. This wasassets in these impairment tests. These were considered a Level 3 fair value measurementmeasurements due to the use of significant unobservable inputs including estimates of future power and other commodity prices.
In the second quarter of 2012, an agreement was reached to sell Salem Harbor and the assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell. This resulted in a pre-tax charge of $27 million ($16 million after-tax), which is included in loss from discontinued operations in Dominion’s Consolidated Statements of Income. This was considered a Level 2 fair value measurement as it was based on the negotiated sales price. Salem Harbor was sold in the third quarter of 2012.
EMISSIONS ALLOWANCES
In September 2010, Virginia Power evaluated its SO2 emissions allowances not expected to be consumed by its generating units for potential impairment due to the significant decline in market prices since the July 2010 release of the EPA’s proposed replacement rule for CAIR, ultimately known as CSAPR. As a result of this evaluation, Virginia Power recorded an impairment charge of $13 million ($8 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down its SO2 emissions allowances not expected to be consumed to their estimated fair value of less than $1 million.
In the third quarter of 2011, Dominion and Virginia Power evaluated their SO2 emissions allowances not expected to be consumed by generating units for potential impairment due to the EPA’s issuance of CSAPR as discussed in Note 22. Prior to the issuance of CSAPR, Dominion and Virginia Power held $57 million and $43 million, respectively, of SO2 emissions allowances obtained for ARP and CAIR compliance. Due to CSAPR’s establishment of a new allowance program and the elimination of CAIR, Dominion and Virginia Power had more SO2 emissions allowances than needed for ARP compliance. As a result of this evaluation, Dominion and Virginia Power recorded an impairment charge of $57 million ($34 million after-tax) and $43 million ($26 million after-tax), respectively, in other operations and maintenance expense in their Consolidated Statements of
79
Combined Notes to Consolidated Financial Statements, Continued
Income, to write down these emissions allowances to their estimated fair value of less than $1 million.
To estimate the value of these emissions allowances in both impairment tests, Dominion utilized a market approach by obtaining broker quotes to validate CSAPR’s impact on emissions allowance prices. However, due to limited market activity for future SO2 vintage year allowances, these are considered a Level 3 fair value measurement.
Recurring Fair Value Measurements
Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion’s pension and other postretirement benefit plans are presented in Note 22.21.
Combined Notes to Consolidated Financial Statements, Continued
DOMINION
The following table presents Dominion’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
At December 31, 2010 | ||||||||||||||||||||||||||||||||
At December 31, 2012 | ||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||
Derivatives: | ||||||||||||||||||||||||||||||||
Commodity | $ | 62 | $ | 734 | $ | 47 | $ | 843 | $ | 12 | $ | 639 | $ | 84 | $ | 735 | ||||||||||||||||
Interest Rate | — | 54 | — | 54 | ||||||||||||||||||||||||||||
Interest rate | — | 93 | — | 93 | ||||||||||||||||||||||||||||
Investments(1): | ||||||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||
U.S.: | ||||||||||||||||||||||||||||||||
Large Cap | 1,709 | — | — | 1,709 | 1,973 | — | — | 1,973 | ||||||||||||||||||||||||
Other | 56 | — | — | 56 | 59 | — | — | 59 | ||||||||||||||||||||||||
Non-U.S.: | ||||||||||||||||||||||||||||||||
Large Cap | 12 | — | — | 12 | 12 | — | — | 12 | ||||||||||||||||||||||||
Fixed Income: | ||||||||||||||||||||||||||||||||
Corporate debt instruments | — | 327 | — | 327 | — | 325 | — | 325 | ||||||||||||||||||||||||
U.S. Treasury securities and agency debentures | 228 | 165 | — | 393 | 391 | 152 | — | 543 | ||||||||||||||||||||||||
State and municipal | — | 286 | — | 286 | — | 315 | — | 315 | ||||||||||||||||||||||||
Other | — | 19 | — | 19 | — | 7 | — | 7 | ||||||||||||||||||||||||
Cash equivalents and other | 25 | 97 | — | 122 | 13 | 67 | — | 80 | ||||||||||||||||||||||||
Restricted cash equivalents | — | 400 | — | 400 | — | 33 | — | 33 | ||||||||||||||||||||||||
Total assets | $ | 2,092 | $ | 2,082 | $ | 47 | $ | 4,221 | $ | 2,460 | $ | 1,631 | $ | 84 | $ | 4,175 | ||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||
Derivatives: | ||||||||||||||||||||||||||||||||
Commodity | $ | 12 | $ | 716 | $ | 97 | $ | 825 | $ | 8 | $ | 528 | $ | 59 | $ | 595 | ||||||||||||||||
Interest Rate | — | 5 | — | 5 | ||||||||||||||||||||||||||||
Interest rate | — | 66 | — | 66 | ||||||||||||||||||||||||||||
Total liabilities | $ | 12 | $ | 721 | $ | 97 | $ | 830 | $ | 8 | $ | 594 | $ | 59 | $ | 661 | ||||||||||||||||
At December 31, 2009 | ||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||
Derivatives: | ||||||||||||||||||||||||||||||||
Commodity | $ | 85 | $ | 1,058 | $ | 41 | $ | 1,184 | ||||||||||||||||||||||||
Interest Rate | — | 176 | — | 176 | ||||||||||||||||||||||||||||
Foreign Currency | — | 2 | — | 2 | ||||||||||||||||||||||||||||
Investments(1): | ||||||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||
U.S.: | ||||||||||||||||||||||||||||||||
Large Cap | 1,520 | — | — | 1,520 | ||||||||||||||||||||||||||||
Other | 43 | 1 | — | 44 | ||||||||||||||||||||||||||||
Non-U.S.: | ||||||||||||||||||||||||||||||||
Large Cap | 12 | — | — | 12 | ||||||||||||||||||||||||||||
Fixed Income: | ||||||||||||||||||||||||||||||||
Corporate debt instruments | — | 253 | — | 253 | ||||||||||||||||||||||||||||
U.S. Treasury securities and agency debentures | 216 | 78 | — | 294 | ||||||||||||||||||||||||||||
State and municipal | — | 434 | — | 434 | ||||||||||||||||||||||||||||
Other | — | 4 | — | 4 | ||||||||||||||||||||||||||||
Cash equivalents and other | — | 54 | — | 54 | ||||||||||||||||||||||||||||
Total assets | $ | 1,876 | $ | 2,060 | $ | 41 | $ | 3,977 | ||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||
Derivatives: | ||||||||||||||||||||||||||||||||
Commodity | $ | 17 | $ | 736 | $ | 107 | $ | 860 | ||||||||||||||||||||||||
Interest Rate | — | 1 | — | 1 | ||||||||||||||||||||||||||||
Total liabilities | $ | 17 | $ | 737 | $ | 107 | $ | 861 |
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(millions) | ||||||||||||||||
At December 31, 2011 | ||||||||||||||||
Assets: | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | 44 | $ | 828 | $ | 93 | $ | 965 | ||||||||
Interest rate | — | 105 | — | 105 | ||||||||||||
Investments(1): | ||||||||||||||||
Equity securities: | ||||||||||||||||
U.S.: | ||||||||||||||||
Large Cap | 1,718 | — | — | 1,718 | ||||||||||||
Other | 51 | — | — | 51 | ||||||||||||
Non-U.S.: | ||||||||||||||||
Large Cap | 10 | — | — | 10 | ||||||||||||
Fixed Income: | ||||||||||||||||
Corporate debt instruments | — | 332 | — | 332 | ||||||||||||
U.S. Treasury securities and agency debentures | 277 | 181 | — | 458 | ||||||||||||
State and municipal | — | 329 | — | 329 | ||||||||||||
Other | — | 23 | — | 23 | ||||||||||||
Cash equivalents and other | — | 60 | — | 60 | ||||||||||||
Restricted cash equivalents | — | 141 | — | 141 | ||||||||||||
Total assets | $ | 2,100 | $ | 1,999 | $ | 93 | $ | 4,192 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | 10 | $ | 714 | $ | 164 | $ | 888 | ||||||||
Interest rate | — | 269 | — | 269 | ||||||||||||
Total liabilities | $ | 10 | $ | 983 | $ | 164 | $ | 1,157 |
(1) | Includes investments held in the nuclear decommissioning and rabbi trusts. |
The following table presents the net change in Dominion’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
2010(1) | 2009(1) | 2008(1) | 2012 | 2011 | 2010 | |||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Balance at January 1, | $ | (66 | ) | $ | 99 | $ | (61 | ) | $ | (71 | ) | $ | (50 | ) | $ | (66 | ) | |||||||
Total realized and unrealized gains (losses): | ||||||||||||||||||||||||
Included in earnings | 43 | (148 | ) | (88 | ) | (15 | ) | (77 | ) | 43 | ||||||||||||||
Included in other comprehensive income (loss) | (49 | ) | (188 | ) | 274 | 101 | 14 | (49 | ) | |||||||||||||||
Included in regulatory assets/liabilities | 24 | 52 | (59 | ) | 30 | (42 | ) | 24 | ||||||||||||||||
Purchases, issuances and settlements | (38 | ) | 126 | 85 | ||||||||||||||||||||
Settlements | 47 | 88 | (38 | ) | ||||||||||||||||||||
Transfers out of Level 3 | 36 | (7 | ) | (52 | ) | (67 | ) | (4 | ) | 36 | ||||||||||||||
Balance at December 31, | $ | (50 | ) | $ | (66 | ) | $ | 99 | $ | 25 | $ | (71 | ) | $ | (50 | ) | ||||||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | $ | (4 | ) | $ | (3 | ) | $ | (28 | ) | $ | 42 | $ | 22 | $ | (4 | ) |
The following table presents Dominion’s gains and losses included in earnings in the Level 3 fair value category:
Operating Revenue | Electric Fuel and Energy Purchases | Purchased Gas | Total | |||||||||||||
(millions) | ||||||||||||||||
Year Ended December 31, 2010 | ||||||||||||||||
Total gains (losses) included in earnings | $ | (4 | ) | $ | 51 | $ | (4 | ) | $ | 43 | ||||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | (4 | ) | — | — | (4 | ) | ||||||||||
Year Ended December 31, 2009 |
| |||||||||||||||
Total gains (losses) included in earnings | $ | 29 | $ | (165 | ) | $ | (12 | ) | $ | (148 | ) | |||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | 1 | — | (4 | ) | (3 | ) | ||||||||||
Year Ended December 31, 2008 |
| |||||||||||||||
Total gains (losses) included in earnings | $ | (44 | ) | $ | (28 | ) | $ | (16 | ) | $ | (88 | ) | ||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | (6 | ) | (6 | ) | (16 | ) | (28 | ) |
Operating Revenue | Electric Fuel and Energy Purchases | Purchased Gas | Total | |||||||||||||
(millions) | ||||||||||||||||
Year Ended December 31, 2012 | ||||||||||||||||
Total gains (losses) included in earnings | $ | 35 | $ | (50 | ) | $ | — | $ | (15 | ) | ||||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | 42 | — | — | 42 | ||||||||||||
Year Ended December 31, 2011 | ||||||||||||||||
Total gains (losses) included in earnings | $ | (32 | ) | $ | (45 | ) | $ | — | $ | (77 | ) | |||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | 22 | — | — | 22 | ||||||||||||
Year Ended December 31, 2010 | ||||||||||||||||
Total gains (losses) included in earnings | $ | (4 | ) | $ | 51 | $ | (4 | ) | $ | 43 | ||||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | (4 | ) | — | — | (4 | ) |
VIRGINIA POWER
The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
At December 31, 2010 | ||||||||||||||||||||||||||||||||
At December 31, 2012 | ||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||
Derivatives: | ||||||||||||||||||||||||||||||||
Commodity | $ | — | $ | 12 | $ | 15 | $ | 27 | $ | — | $ | 1 | $ | 5 | $ | 6 | ||||||||||||||||
Investments(1): | ||||||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||
U.S.: | ||||||||||||||||||||||||||||||||
Large Cap | 676 | — | — | 676 | 779 | — | — | 779 | ||||||||||||||||||||||||
Other | 25 | — | — | 25 | 27 | — | — | 27 | ||||||||||||||||||||||||
Fixed Income: | ||||||||||||||||||||||||||||||||
Corporate debt instruments | — | 215 | — | 215 | — | 196 | — | 196 | ||||||||||||||||||||||||
U.S. Treasury securities and agency debentures | 80 | 63 | — | 143 | 168 | 66 | — | 234 | ||||||||||||||||||||||||
State and municipal | — | 102 | — | 102 | — | 118 | — | 118 | ||||||||||||||||||||||||
Other | — | 15 | — | 15 | — | 1 | — | 1 | ||||||||||||||||||||||||
Cash equivalents and other | 10 | 61 | — | 71 | 7 | 31 | — | 38 | ||||||||||||||||||||||||
Restricted cash equivalents | — | 169 | — | 169 | — | 10 | — | 10 | ||||||||||||||||||||||||
Total assets | $ | 791 | $ | 637 | $ | 15 | $ | 1,443 | $ | 981 | $ | 423 | $ | 5 | $ | 1,409 | ||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||
Derivatives: | ||||||||||||||||||||||||||||||||
Commodity | $ | — | $ | 5 | $ | 1 | $ | 6 | $ | — | $ | 6 | $ | 3 | $ | 9 | ||||||||||||||||
Interest rate | — | 25 | — | 25 | ||||||||||||||||||||||||||||
Total Liabilities | $ | — | $ | 5 | $ | 1 | $ | 6 | $ | — | $ | 31 | $ | 3 | $ | 34 | ||||||||||||||||
At December 31, 2009 | ||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||
Derivatives: | ||||||||||||||||||||||||||||||||
Commodity | $ | — | $ | 30 | $ | 2 | $ | 32 | ||||||||||||||||||||||||
Interest Rate | — | 86 | — | 86 | ||||||||||||||||||||||||||||
Foreign Currency | — | 2 | — | 2 | ||||||||||||||||||||||||||||
Investments(1): | ||||||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||
U.S.: | ||||||||||||||||||||||||||||||||
Large Cap | 615 | — | — | 615 | ||||||||||||||||||||||||||||
Other | 19 | — | — | 19 | ||||||||||||||||||||||||||||
Fixed Income: | ||||||||||||||||||||||||||||||||
Corporate debt instruments | — | 161 | — | 161 | ||||||||||||||||||||||||||||
U.S. Treasury securities and agency debentures | 90 | 8 | — | 98 | ||||||||||||||||||||||||||||
State and municipal | — | 189 | — | 189 | ||||||||||||||||||||||||||||
Other | — | 3 | — | 3 | ||||||||||||||||||||||||||||
Cash equivalents and other | — | 16 | — | 16 | ||||||||||||||||||||||||||||
Total assets | $ | 724 | $ | 495 | $ | 2 | $ | 1,221 | ||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||
Derivatives: | ||||||||||||||||||||||||||||||||
Commodity | $ | — | $ | 3 | $ | 12 | $ | 15 | ||||||||||||||||||||||||
Total Liabilities | $ | — | $ | 3 | $ | 12 | $ | 15 |
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(millions) | ||||||||||||||||
At December 31, 2011 | ||||||||||||||||
Assets: | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | — | $ | — | $ | 2 | $ | 2 | ||||||||
Investments(1): | ||||||||||||||||
Equity securities: | ||||||||||||||||
U.S.: | ||||||||||||||||
Large Cap | 679 | — | — | 679 | ||||||||||||
Other | 23 | — | — | 23 | ||||||||||||
Fixed Income: | ||||||||||||||||
Corporate debt instruments | — | 214 | — | 214 | ||||||||||||
U.S. Treasury securities and agency debentures | 107 | 63 | — | 170 | ||||||||||||
State and municipal | — | 125 | — | 125 | ||||||||||||
Other | — | 16 | — | 16 | ||||||||||||
Cash equivalents and other | — | 40 | — | 40 | ||||||||||||
Restricted cash equivalents | — | 32 | — | 32 | ||||||||||||
Total assets | $ | 809 | $ | 490 | $ | 2 | $ | 1,301 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives: | ||||||||||||||||
Commodity | $ | — | $ | 17 | $ | 30 | $ | 47 | ||||||||
Interest rate | — | 100 | — | 100 | ||||||||||||
Total Liabilities | $ | — | $ | 117 | $ | 30 | $ | 147 |
(1) | Includes investments held in the nuclear decommissioning and rabbi trusts. |
The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
2010(1) | 2009(1) | 2008(1) | ||||||||||
(millions) | ||||||||||||
Balance at January 1, | $ | (10 | ) | $ | (69 | ) | $ | (4 | ) | |||
Total realized and unrealized gains (losses): | ||||||||||||
Included in earnings | 51 | (165 | ) | (27 | ) | |||||||
Included in regulatory assets/liabilities | 24 | 53 | (59 | ) | ||||||||
Purchases, issuances and settlements | (51 | ) | 170 | 21 | ||||||||
Transfers out of Level 3 | — | 1 | — | |||||||||
Balance at December 31, | $ | 14 | $ | (10 | ) | $ | (69 | ) | ||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | $ | — | $ | — | $ | (5 | ) |
2012 | 2011 | 2010 | ||||||||||
(millions) | ||||||||||||
Balance at January 1, | $ | (28 | ) | $ | 14 | $ | (10 | ) | ||||
Total realized and unrealized gains (losses): | ||||||||||||
Included in earnings | (50 | ) | (45 | ) | 51 | |||||||
Included in regulatory assets/liabilities | 30 | (42 | ) | 24 | ||||||||
Settlements | 50 | 45 | (51 | ) | ||||||||
Transfers out of Level 3 | — | — | — | |||||||||
Balance at December 31, | $ | 2 | $ | (28 | ) | $ | 14 |
The gains and losses included in earnings in the Level 3 fair value category, including those attributable to the change in unrealized gains and losses relating to assets still held at the reporting date, were classified in electric fuel and other energy-related purchases expense in Virginia Power’s Consolidated Statements of Income for the years ended December 31, 2010, 20092012, 2011 and 2008.2010. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2012, 2011 and 2010.
Fair Value of Financial Instruments
Substantially all of Dominion’s and Virginia Power’s financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, customer and other receivables, short-term debt and accounts payable are representative of fair value because of the short-term nature of these instruments. For Dominion’s and VirginiaVir-
81
Combined Notes to Consolidated Financial Statements, Continued
ginia Power’s financial instruments that are not recorded at fair value, the carrying amounts and fair values are as follows:
At December 31, | 2010 | 2009 | 2012 | 2011 | ||||||||||||||||||||||||||||
Carrying Amount | Estimated Fair Value(1) | Carrying Amount | Estimated Fair Value(1) | Carrying Amount | Estimated Fair Value(1) | Carrying Amount | Estimated Fair Value(1) | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Dominion | ||||||||||||||||||||||||||||||||
Long-term debt, including securities due within one year(2) | $ | 14,520 | $ | 16,112 | $ | 14,867 | $ | 15,970 | $ | 16,841 | $ | 19,898 | $ | 16,264 | $ | 18,936 | ||||||||||||||||
Junior subordinated notes payable to affiliates | 268 | 261 | 268 | 255 | ||||||||||||||||||||||||||||
Enhanced junior subordinated notes | 1,467 | 1,560 | 1,483 | 1,487 | ||||||||||||||||||||||||||||
Long-term debt, including securities due within one year—VIE(3) | 860 | 864 | 890 | 892 | ||||||||||||||||||||||||||||
Junior subordinated notes | 1,373 | 1,430 | 1,719 | 1,786 | ||||||||||||||||||||||||||||
Subsidiary preferred stock | 257 | 249 | 257 | 251 | 257 | 255 | 257 | 256 | ||||||||||||||||||||||||
Virginia Power | ||||||||||||||||||||||||||||||||
Long-term debt, including securities due within one year(2) | $ | 6,717 | $ | 7,489 | $ | 6,458 | $ | 6,977 | $ | 6,669 | $ | 8,270 | $ | 6,862 | $ | 8,281 | ||||||||||||||||
Preferred stock(3) | 257 | 249 | 257 | 251 | ||||||||||||||||||||||||||||
Preferred stock(4) | 257 | 255 | 257 | 256 |
(1) | Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and |
Combined Notes to Consolidated Financial Statements, Continued
remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value. |
(2) | Includes amounts which represent the unamortized discount and premium. At December 31, |
(3) | Includes amounts which represent the unamortized premium. |
(4) | Includes deferred issuance expenses of $2 million at December 31, |
NOTE 8.7. DERIVATIVESAND HEDGE ACCOUNTING ACTIVITIES
Dominion and Virginia Power are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as currency exchange and interest rate risks of their business operations. The Companies use derivative instruments to manage exposure to these risks, and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes. As discussed in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivatives are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings. See Note 76 for further information about fair value measurements and associated valuation methods for derivatives.
DOMINION
The following table presents the volume of Dominion’s derivative activity as of December 31, 2010.2012. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting deals,transactions, for which they represent the absolute value of the net volume of their long and short positions.
Current | Noncurrent | Current | Noncurrent | |||||||||||||
Natural Gas (bcf): | ||||||||||||||||
Fixed price(1) | 358 | 98 | 249 | 68 | ||||||||||||
Basis(1) | 1,012 | 465 | 786 | 534 | ||||||||||||
Electricity (MWh): | ||||||||||||||||
Fixed price | 22,047,293 | 12,526,648 | ||||||||||||||
Fixed price(1) | 20,100,938 | 12,582,674 | ||||||||||||||
FTRs | 49,301,662 | 1,817,176 | 46,851,683 | — | ||||||||||||
Capacity (MW) | 1,383,800 | 4,020,050 | 151,025 | 148,461 | ||||||||||||
Liquids (gallons)(2) | 148,764,000 | 361,536,000 | 164,682,000 | 145,698,000 | ||||||||||||
Interest rate | $ | — | $ | 1,000,000,000 | $ | 1,500,000,000 | $ | 2,250,000,000 |
(1) | Includes options. |
(2) | Includes NGLs and oil. |
Selected information about Dominion’s hedge accounting activities follows:For the years ended December 31, 2012, 2011 and 2010, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||||
(millions) | ||||||||||||
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income: | ||||||||||||
Fair value hedges(1) | $ | 3 | $ | (4 | ) | $ | (6 | ) | ||||
Cash flow hedges(2) | (1 | ) | — | (4 | ) | |||||||
Net ineffectiveness | $ | 2 | $ | (4 | ) | $ | (10 | ) | ||||
Gains (losses) attributable to changes in the time value of options and change in the differences between spot prices and forward prices and excluded from the assessment of effectiveness(3): | ||||||||||||
Fair value hedges(4) | $ | — | $ | 23 | $ | 11 | ||||||
Total ineffectiveness and excluded amounts | $ | 2 | $ | 19 | $ | 1 |
The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at December 31, 2010:2012:
AOCI After-Tax | Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax | Maximum Term | AOCI After-Tax | Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax | Maximum Term | |||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Commodities: | ||||||||||||||||||||||||
Gas | $ | (24 | ) | $ | (13 | ) | 48 months | $ | (28 | ) | $ | (24 | ) | 27 months | ||||||||||
Electricity | 70 | 68 | 29 months | 68 | 17 | 36 months | ||||||||||||||||||
NGLs | (36 | ) | (15 | ) | 48 months | |||||||||||||||||||
Other | 8 | 2 | 53 months | 3 | 2 | 41 months | ||||||||||||||||||
Interest rate | 33 | (1 | ) | 336 months | (165 | ) | (21 | ) | 361 months | |||||||||||||||
Total | $ | 51 | $ | 41 | $ | (122 | ) | $ | (26 | ) |
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.
The sale of the majority of Dominion’s remaining E&P operations resulted in the discontinuance of hedge accounting for certain cash flow hedges in 2010, as discussed in Note 4.3.
In addition, changes to Dominion’s financing needs during the first and second quarters of 2010 resulted in the discontinuance of hedge accounting for certain cash flow hedges since it was determined that the forecasted interest payments would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a benefit recorded to interest and related charges reflecting the reclassification of gains
82 |
from AOCI to earnings of $110 million ($67 million after-tax) for 2010. The reclassification of gains from AOCI to earnings was partially offset by subsequent changes in fair value for these contracts of $37 million ($23 million after-tax) for 2010.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Dominion’s derivatives and where they are presented in its Consolidated Balance Sheets:
At December 31, 2010 | Fair Value - Derivatives under Hedge Accounting | Fair Value - Derivatives not under Hedge Accounting | Total Fair Value | |||||||||||||||||||||
At December 31, 2012 | Fair Value - Derivatives under Hedge Accounting | Fair Value - Derivatives not under Hedge Accounting | Total Fair Value | |||||||||||||||||||||
(millions) | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Commodity | $ | 291 | $ | 425 | $ | 716 | $ | 103 | $ | 379 | $ | 482 | ||||||||||||
Interest rate | 23 | — | 23 | 36 | — | 36 | ||||||||||||||||||
Total current derivative assets | 314 | 425 | 739 | 139 | 379 | 518 | ||||||||||||||||||
Noncurrent Assets | ||||||||||||||||||||||||
Commodity | 44 | 83 | 127 | 130 | 123 | 253 | ||||||||||||||||||
Interest rate | 31 | — | 31 | 57 | — | 57 | ||||||||||||||||||
Total noncurrent derivative assets(1) | 75 | 83 | 158 | 187 | 123 | 310 | ||||||||||||||||||
Total derivative assets | $ | 389 | $ | 508 | $ | 897 | $ | 326 | $ | 502 | $ | 828 | ||||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Commodity | $ | 178 | $ | 455 | $ | 633 | $ | 103 | $ | 341 | $ | 444 | ||||||||||||
Interest rate | 66 | — | 66 | |||||||||||||||||||||
Total current derivative liabilities | 169 | 341 | 510 | |||||||||||||||||||||
Noncurrent Liabilities | ||||||||||||||||||||||||
Commodity | 58 | 93 | 151 | |||||||||||||||||||||
Total noncurrent derivative liabilities(2) | 58 | 93 | 151 | |||||||||||||||||||||
Total derivative liabilities | $ | 227 | $ | 434 | $ | 661 | ||||||||||||||||||
At December 31, 2011 | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Commodity | $ | 176 | $ | 495 | $ | 671 | ||||||||||||||||||
Interest rate | 34 | — | 34 | |||||||||||||||||||||
Total current derivative assets | 210 | 495 | 705 | |||||||||||||||||||||
Noncurrent Assets | ||||||||||||||||||||||||
Commodity | 198 | 96 | 294 | |||||||||||||||||||||
Interest rate | 71 | — | 71 | |||||||||||||||||||||
Total noncurrent derivative assets(1) | 269 | 96 | 365 | |||||||||||||||||||||
Total derivative assets | $ | 479 | $ | 591 | $ | 1,070 | ||||||||||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Commodity | $ | 162 | $ | 530 | $ | 692 | ||||||||||||||||||
Interest rate | 222 | 37 | 259 | |||||||||||||||||||||
Total current derivative liabilities | 178 | 455 | 633 | 384 | 567 | 951 | ||||||||||||||||||
Noncurrent Liabilities | ||||||||||||||||||||||||
Commodity | 86 | 106 | 192 | 118 | 78 | 196 | ||||||||||||||||||
Interest rate | 5 | — | 5 | — | 10 | 10 | ||||||||||||||||||
Total noncurrent derivative liabilities(2) | 91 | 106 | 197 | 118 | 88 | 206 | ||||||||||||||||||
Total derivative liabilities | $ | 269 | $ | 561 | $ | 830 | $ | 502 | $ | 655 | $ | 1,157 |
(1) | Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion’s Consolidated Balance |
(2) | Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance |
At December 31, 2009 | Fair Value - Derivatives under Hedge Accounting | Fair Value - Derivatives not under Hedge Accounting | Total Fair Value | |||||||||
(millions) | ||||||||||||
ASSETS | ||||||||||||
Current Assets | ||||||||||||
Commodity | $ | 445 | $ | 507 | $ | 952 | ||||||
Interest rate | 174 | — | 174 | |||||||||
Foreign Currency | 2 | — | 2 | |||||||||
Total current derivative assets | 621 | 507 | 1,128 | |||||||||
Noncurrent Assets | ||||||||||||
Commodity | 132 | 100 | 232 | |||||||||
Interest rate | 2 | — | 2 | |||||||||
Total noncurrent derivative assets(1) | 134 | 100 | 234 | |||||||||
Total derivative assets | $ | 755 | $ | 607 | $ | 1,362 | ||||||
LIABILITIES | ||||||||||||
Current Liabilities | ||||||||||||
Commodity | $ | 147 | $ | 532 | $ | 679 | ||||||
Total current derivative liabilities | 147 | 532 | 679 | |||||||||
Noncurrent Liabilities | ||||||||||||
Commodity | 61 | 120 | 181 | |||||||||
Interest rate | 1 | — | 1 | |||||||||
Total noncurrent derivative liabilities(2) | 62 | 120 | 182 | |||||||||
Total derivative liabilities | $ | 209 | $ | 652 | $ | 861 |
The following tables present the gains and losses on Dominion’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
Year ended December 31, 2010 relationships | Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1) | Amount of Gain (Loss) Reclassified from AOCI to Income | Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2) | |||||||||
(millions) | ||||||||||||
Derivative Type and Location of Gains (Losses) | ||||||||||||
Commodity: | ||||||||||||
Operating revenue | $ | 557 | ||||||||||
Purchased gas | (155 | ) | ||||||||||
Electric fuel and other energy-related purchases | (8 | ) | ||||||||||
Purchased electric capacity | 3 | |||||||||||
Total commodity | $ | 139 | 397 | $ | (17 | ) | ||||||
Interest rate(3) | (3 | ) | 109 | (27 | ) | |||||||
Foreign currency(4) | — | 1 | (2 | ) | ||||||||
Total | $ | 136 | $ | 507 | $ | (46 | ) |
Combined Notes to Consolidated Financial Statements, Continued
Year ended December 31, 2009 Derivatives in cash flow hedging | Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1) | Amount of Gain (Loss) Reclassified from AOCI to Income | Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2) | |||||||||||||||||||||
Derivatives in cash flow hedging relationships Year Ended December 31, 2012 | Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1) | Amount of Gain (Loss) Reclassified from AOCI to Income | Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2) | |||||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Derivative Type and Location of Gains (Losses) | ||||||||||||||||||||||||
Commodity: | ||||||||||||||||||||||||
Operating revenue | $ | 188 | ||||||||||||||||||||||
Purchased gas | (75 | ) | ||||||||||||||||||||||
Electric fuel and other energy-related purchases | (17 | ) | ||||||||||||||||||||||
Total commodity | $ | 71 | $ | 96 | $ | 10 | ||||||||||||||||||
Interest rate(3) | (84 | ) | (2 | ) | (35 | ) | ||||||||||||||||||
Total | $ | (13 | ) | $ | 94 | $ | (25 | ) | ||||||||||||||||
Year Ended December 31, 2011 | ||||||||||||||||||||||||
Derivative Type and Location of Gains (Losses) | ||||||||||||||||||||||||
Commodity: | ||||||||||||||||||||||||
Operating revenue | $ | 153 | ||||||||||||||||||||||
Purchased gas | (78 | ) | ||||||||||||||||||||||
Electric fuel and other energy-related purchases | (2 | ) | ||||||||||||||||||||||
Purchased electric capacity | 1 | |||||||||||||||||||||||
Total commodity | $ | 137 | $ | 74 | $ | (20 | ) | |||||||||||||||||
Interest rate(3) | (252 | ) | (8 | ) | (143 | ) | ||||||||||||||||||
Total | $ | (115 | ) | $ | 66 | $ | (163 | ) | ||||||||||||||||
Year Ended December 31, 2010 | ||||||||||||||||||||||||
Derivative Type and Location of Gains (Losses) | ||||||||||||||||||||||||
Commodity: | ||||||||||||||||||||||||
Operating revenue | $ | 1,072 | $ | 557 | ||||||||||||||||||||
Purchased gas | (179 | ) | (155 | ) | ||||||||||||||||||||
Electric fuel and other energy-related purchases | (10 | ) | (8 | ) | ||||||||||||||||||||
Purchased electric capacity | 4 | 3 | ||||||||||||||||||||||
Total commodity | $ | 358 | $ | 887 | $ | 6 | $ | 139 | $ | 397 | $ | (17 | ) | |||||||||||
Interest rate(3) | 159 | (4 | ) | 87 | (3 | ) | 109 | (27 | ) | |||||||||||||||
Foreign currency(4) | — | 2 | (3 | ) | — | 1 | (2 | ) | ||||||||||||||||
Total | $ | 517 | $ | 885 | $ | 90 | $ | 136 | $ | 507 | $ | (46 | ) |
(1) | Amounts deferred into AOCI have no associated effect in Dominion’s Consolidated Statements of Income. |
(2) | Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income. |
(3) | Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges. |
(4) | Amounts recorded in Dominion’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases. |
Derivatives not designated as hedging instruments | Amount of Gain (Loss) Recognized in Income on Derivatives(1) | |||||||
Year ended December 31, | 2010 | 2009 | ||||||
(millions) | ||||||||
Derivative Type and Location of Gains (Losses) | ||||||||
Commodity | ||||||||
Operating revenue | $ | 67 | $ | 105 | ||||
Purchased gas | (41) | (66 | ) | |||||
Electric fuel and other energy-related purchases | 51 | (163 | ) | |||||
Interest rate(2) | (37) | — | ||||||
Total | $ | 40 | $ | (124 | ) |
83
Combined Notes to Consolidated Financial Statements, Continued
Derivatives not designated as hedging instruments | Amount of Gain (Loss) Recognized in Income on Derivatives(1) | |||||||||||
Year Ended December 31, | 2012 | 2011 | 2010 | |||||||||
(millions) | ||||||||||||
Derivative Type and Location of Gains (Losses) | ||||||||||||
Commodity: | ||||||||||||
Operating revenue | $ | 168 | $ | 111 | $ | 67 | ||||||
Purchased gas | (14 | ) | (35 | ) | (41 | ) | ||||||
Electric fuel and other energy-related purchases | (40 | ) | (45 | ) | 51 | |||||||
Interest rate(2) | 17 | (5 | ) | (37 | ) | |||||||
Total | $ | 131 | $ | 26 | $ | 40 |
(1) | Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income. |
(2) | Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges. |
VIRGINIA POWER
The following table presents the volume of Virginia Power’s derivative activity at December 31, 2010.2012. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting deals,transactions, for which they represent the absolute value of the net volume of their long and short positions.
Current | Noncurrent | Current | Noncurrent | |||||||||||||
Natural Gas (bcf): | ||||||||||||||||
Fixed price | 10 | — | 16 | — | ||||||||||||
Basis | 5 | — | 8 | — | ||||||||||||
Electricity (MWh): | ||||||||||||||||
Fixed price | 651,200 | — | 709,600 | — | ||||||||||||
FTRs | 48,141,239 | 1,817,176 | 43,570,739 | — | ||||||||||||
Capacity (MW) | 288,200 | 258,500 | 107,000 | 93,800 | ||||||||||||
Interest rate | $ | 500,000,000 | $ | 250,000,000 |
For the years ended December 31, 2010, 20092012, 2011 and 2008,2010, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to the time value of options and changes in the differences between spot prices and forward prices.
The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at December 31, 2010:
AOCI After-Tax | Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax | Maximum Term | ||||||||||
(millions) | ||||||||||||
Interest rate | $ | 3 | $ | — | 336 months | |||||||
Other | 1 | 1 | 41 months | |||||||||
Total | $ | 4 | $ | 1 |
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated interest payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:
At December 31, 2010 | Fair Value - Derivatives under Hedge Accounting | Fair Value - Derivatives not under Hedge Accounting | Total Fair Value | |||||||||||||||||||||
At December 31, 2012 | Fair Value - Derivatives under Hedge Accounting | Fair Value - Derivatives not under Hedge Accounting | Total Fair Value | |||||||||||||||||||||
(millions) | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Commodity | $ | 12 | $ | 15 | $ | 27 | $ | 1 | $ | 5 | $ | 6 | ||||||||||||
Total current derivative assets | 12 | 15 | 27 | |||||||||||||||||||||
Total current derivative assets(1) | 1 | 5 | 6 | |||||||||||||||||||||
Total derivative assets | $ | 12 | $ | 15 | $ | 27 | $ | 1 | $ | 5 | $ | 6 | ||||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Commodity | $ | 2 | $ | 1 | $ | 3 | $ | 5 | $ | 3 | $ | 8 | ||||||||||||
Total current derivative liabilities(1) | 2 | 1 | 3 | |||||||||||||||||||||
Interest rate | 25 | — | 25 | |||||||||||||||||||||
Total current derivative liabilities | 30 | 3 | 33 | |||||||||||||||||||||
Noncurrent Liabilities | ||||||||||||||||||||||||
Commodity | 3 | — | 3 | 1 | — | 1 | ||||||||||||||||||
Total noncurrent derivative liabilities(2) | 3 | — | 3 | 1 | — | 1 | ||||||||||||||||||
Total derivative liabilities | $ | 5 | $ | 1 | $ | 6 | $ | 31 | $ | 3 | $ | 34 | ||||||||||||
At December 31, 2009 | ||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||
At December 31, 2011 | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Commodity | $ | 20 | $ | 2 | $ | 22 | $ | — | $ | 2 | $ | 2 | ||||||||||||
Interest Rate | 86 | — | 86 | |||||||||||||||||||||
Foreign Currency | 2 | — | 2 | |||||||||||||||||||||
Total current derivative assets | 108 | 2 | 110 | |||||||||||||||||||||
Noncurrent Assets | ||||||||||||||||||||||||
Commodity | 10 | — | 10 | |||||||||||||||||||||
Total noncurrent derivative assets(3) | 10 | — | 10 | |||||||||||||||||||||
Total current derivative assets(1) | — | 2 | 2 | |||||||||||||||||||||
Total derivative assets | $ | 118 | $ | 2 | $ | 120 | $ | — | $ | 2 | $ | 2 | ||||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Commodity | $ | 1 | $ | 12 | $ | 13 | $ | 14 | $ | 31 | $ | 45 | ||||||||||||
Total current derivative liabilities(1) | 1 | 12 | 13 | |||||||||||||||||||||
Interest rate | 53 | 37 | 90 | |||||||||||||||||||||
Total current derivative liabilities | 67 | 68 | 135 | |||||||||||||||||||||
Noncurrent Liabilities | ||||||||||||||||||||||||
Commodity | 2 | — | 2 | 2 | — | 2 | ||||||||||||||||||
Interest rate | — | 10 | 10 | |||||||||||||||||||||
Total noncurrent derivative liabilities(2) | 2 | — | 2 | 2 | 10 | 12 | ||||||||||||||||||
Total derivative liabilities | $ | 3 | $ | 12 | $ | 15 | $ | 69 | $ | 78 | $ | 147 |
(1) | Current derivative |
(2) | Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance |
84 |
Combined Notes to Consolidated Financial Statements, Continued
The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
Derivatives in cash flow hedging relationships Year Ended December 31, 2010 | Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1) | Amount of Gain (Loss) Reclassified from AOCI to Income | Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2) | |||||||||||||||||||||
Derivatives in cash flow hedging relationships Year Ended December 31, 2012 | Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1) | Amount of Gain (Loss) Reclassified from AOCI to Income | Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2) | |||||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Derivative Type and Location of Gains (Losses) | ||||||||||||||||||||||||
Commodity | ||||||||||||||||||||||||
Commodity: | ||||||||||||||||||||||||
Electric fuel and other energy-related purchases | $ | (4 | ) | |||||||||||||||||||||
Total commodity | $ | (2 | ) | $ | (4 | ) | $ | 10 | ||||||||||||||||
Interest rate(3) | (6 | ) | — | (35 | ) | |||||||||||||||||||
Total | $ | (8 | ) | $ | (4 | ) | $ | (25 | ) | |||||||||||||||
Year Ended December 31, 2011 | ||||||||||||||||||||||||
Derivative Type and Location of Gains (Losses) | ||||||||||||||||||||||||
Commodity: | ||||||||||||||||||||||||
Electric fuel and other energy-related purchases | $ | (1 | ) | |||||||||||||||||||||
Purchased electric capacity | 1 | |||||||||||||||||||||||
Total commodity | $ | (3 | ) | $ | — | $ | (20 | ) | ||||||||||||||||
Interest rate(3) | (6 | ) | 1 | (143 | ) | |||||||||||||||||||
Total | $ | (9 | ) | $ | 1 | $ | (163 | ) | ||||||||||||||||
Year Ended December 31, 2010 | ||||||||||||||||||||||||
Derivative Type and Location of Gains (Losses) | ||||||||||||||||||||||||
Commodity: | ||||||||||||||||||||||||
Electric fuel and other energy-related purchases | $ | (1 | ) | $ | (1 | ) | ||||||||||||||||||
Purchased electric capacity | 4 | 4 | ||||||||||||||||||||||
Total commodity | $ | (1 | ) | 3 | $ | (17 | ) | $ | (1 | ) | $ | 3 | $ | (17 | ) | |||||||||
Interest rate(3) | (1 | ) | 9 | (27 | ) | (1 | ) | 9 | (27 | ) | ||||||||||||||
Foreign currency(4) | — | — | (2 | ) | — | — | (2 | ) | ||||||||||||||||
Total | $ | (2 | ) | $ | 12 | $ | (46 | ) | $ | (2 | ) | $ | 12 | $ | (46 | ) | ||||||||
Year Ended December 31, 2009 | ||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Derivative Type and Location of Gains (Losses) | ||||||||||||||||||||||||
Commodity | ||||||||||||||||||||||||
Electric fuel and other energy-related purchases | $ | (8 | ) | |||||||||||||||||||||
Purchased electric capacity | 5 | |||||||||||||||||||||||
Total commodity | $ | (3 | ) | (3 | ) | $ | 6 | |||||||||||||||||
Interest rate(3) | 15 | — | 87 | |||||||||||||||||||||
Foreign currency(4) | — | 1 | (3 | ) | ||||||||||||||||||||
Total | $ | 12 | $ | (2 | ) | $ | 90 |
(1) | Amounts deferred into AOCI have no associated effect in Virginia Power’s Consolidated Statements of Income. |
(2) | Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income. |
(3) | Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges. |
(4) | Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases. |
Derivatives not designated as hedging instruments | Amount of Gain (Loss) Recognized in Income on Derivatives(1) | Amount of Gain (Loss) Recognized in Income on Derivatives(1) | ||||||||||||||||||
Year Ended December 31, | 2010 | 2009 | 2012 | 2011 | 2010 | |||||||||||||||
(millions) | ||||||||||||||||||||
Derivative Type and Location of Gains (Losses) | ||||||||||||||||||||
Commodity(2) | $51 | $(165 | ) | $ | (50 | ) | $ | (45 | ) | $ | 51 | |||||||||
Interest rate(3) | (3 | ) | — | — | (5 | ) | (3 | ) | ||||||||||||
Total | $48 | $(165 | ) | $ | (50 | ) | $ | (50 | ) | $ | 48 |
(1) | Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income. |
(2) | Amounts recorded in Virginia Power’s Consolidated Statements of Income are |
(3) | Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges. |
NOTE 9.8. EARNINGS PER SHARE
The following table presents the calculation of Dominion’s basic and diluted EPS:
2010 | 2009 | 2008 | ||||||||||
(millions, except EPS) | ||||||||||||
Net income attributable to Dominion | $ | 2,808 | $ | 1,287 | $ | 1,834 | ||||||
Average shares of common stock outstanding—Basic | 588.9 | 593.3 | 577.8 | |||||||||
Net effect of potentially dilutive securities(1) | 1.2 | 0.4 | 3.0 | |||||||||
Average shares of common stock outstanding—Diluted | 590.1 | 593.7 | 580.8 | |||||||||
Earnings Per Common Share—Basic | $ | 4.77 | $ | 2.17 | $ | 3.17 | ||||||
Earnings Per Common Share—Diluted | $ | 4.76 | $ | 2.17 | $ | 3.16 |
2012 | 2011 | 2010 | ||||||||||
(millions, except EPS) | ||||||||||||
Net income attributable to Dominion | $ | 302 | $ | 1,408 | $ | 2,808 | ||||||
Average shares of common stock outstanding-Basic | 572.9 | 573.1 | 588.9 | |||||||||
Net effect of potentially dilutive securities(1) | 1.0 | 1.5 | 1.2 | |||||||||
Average shares of common stock outstanding-Diluted | 573.9 | 574.6 | 590.1 | |||||||||
Earnings Per Common Share-Basic | $ | 0.53 | $ | 2.46 | $ | 4.77 | ||||||
Earnings Per Common Share-Diluted | $ | 0.53 | $ | 2.45 | $ | 4.76 |
(1) | Potentially dilutive securities consist of options, goal-based stock and contingently convertible senior notes. |
Potentially dilutive securities with the right
85 |
Combined Notes to acquire approximately 1.2 million common shares for the year ended December 31, 2009 were not included in the calculation of diluted EPS because the exercise or purchase prices of those instruments were greater than the average market price of Dominion’s common shares. Consolidated Financial Statements, Continued
There were no potentially dilutive securities excluded from the calculation of diluted EPS for the years ended December 31, 20102012, 2011 and 2008.
NOTE 10.9. INVESTMENTS
DOMINION
Equity and Debt Securities
RABBI TRUST SECURITIES
Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled $93$95 million and $96$90 million at December 31, 20102012 and 2009,2011, respectively. Net unrealized gains on trading securities totaled $5 million and $11 million in 2010 and 2009, respectively, and net unrealized losses on trading securities totaled $26 million in 2008. Cost-method investments held in Dominion’s rabbi trusts totaled $18$14 million and $17 million at December 31, 20102012 and 2009,2011, respectively.
DECOMMISSIONING TRUST SECURITIES
Dominion holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below.below:
Amortized Cost | Total Unrealized Gains(1) | Total Unrealized Losses(1) | Fair Value (2) | Amortized Cost | Total Unrealized Gains(1) | Total Unrealized Losses(1) | Fair Value | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||||
Marketable equity securities: | ||||||||||||||||||||||||||||||||
U.S.: | ||||||||||||||||||||||||||||||||
Large Cap | $ | 1,161 | $ | 515 | $ | — | $ | 1,676 | $ | 1,210 | $ | 732 | $ | — | $ | 1,942 | ||||||||||||||||
Other | 39 | 11 | — | 50 | 40 | 13 | — | 53 | ||||||||||||||||||||||||
Marketable debt securities: | ||||||||||||||||||||||||||||||||
Corporate debt instruments | 310 | 18 | (1 | ) | 327 | 295 | 30 | — | 325 | |||||||||||||||||||||||
U.S. Treasury securities and agency debentures | 380 | 12 | (1 | ) | 391 | 523 | 19 | (2 | ) | 540 | ||||||||||||||||||||||
State and municipal | 244 | 7 | (4 | ) | 247 | 248 | 26 | — | 274 | |||||||||||||||||||||||
Other | 19 | — | — | 19 | 6 | 1 | — | 7 | ||||||||||||||||||||||||
Cost method investments | 108 | — | — | 108 | 117 | — | — | 117 | ||||||||||||||||||||||||
Cash equivalents and other | 79 | — | — | 79 | ||||||||||||||||||||||||||||
Cash equivalents and other(2) | 72 | — | — | 72 | ||||||||||||||||||||||||||||
Total | $ | 2,340 | $ | 563 | $ | (6 | )(3) | $ | 2,897 | $ | 2,511 | $ | 821 | $ | (2 | )(3) | $ | 3,330 | ||||||||||||||
2009 | ||||||||||||||||||||||||||||||||
2011 | ||||||||||||||||||||||||||||||||
Marketable equity securities: | ||||||||||||||||||||||||||||||||
U.S.: | ||||||||||||||||||||||||||||||||
Large Cap | $ | 1,171 | $ | 321 | $ | — | $ | 1,492 | $ | 1,152 | $ | 537 | $ | — | $ | 1,689 | ||||||||||||||||
Other | 20 | 17 | — | 37 | 36 | 10 | — | 46 | ||||||||||||||||||||||||
Marketable debt securities: | ||||||||||||||||||||||||||||||||
Corporate debt instruments | 241 | 13 | (1 | ) | 253 | 314 | 19 | (1 | ) | 332 | ||||||||||||||||||||||
U.S. Treasury securities and agency debentures | 281 | 13 | (1 | ) | 293 | 437 | 20 | (1 | ) | 456 | ||||||||||||||||||||||
State and municipal | 371 | 21 | (3 | ) | 389 | 264 | 24 | — | 288 | |||||||||||||||||||||||
Other | 4 | — | — | 4 | 23 | 1 | — | 24 | ||||||||||||||||||||||||
Cost method investments | 97 | — | — | 97 | 118 | — | — | 118 | ||||||||||||||||||||||||
Cash equivalents and other | 60 | — | — | 60 | ||||||||||||||||||||||||||||
Cash equivalents and other(2) | 46 | — | — | 46 | ||||||||||||||||||||||||||||
Total | $ | 2,245 | $ | 385 | $ | (5 | )(3) | $ | 2,625 | $ | 2,390 | $ | 611 | $ | (2 | )(3) | $ | 2,999 |
(1) | Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2. |
(2) | Includes pending purchases of securities of |
(3) | The fair value of securities in an unrealized loss position was |
The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at December 31, 20102012 by contractual maturity is as follows:
Amount | ||||
(millions) | ||||
Due in one year or less | $ | 50 | ||
Due after one year through five years | 306 | |||
Due after five years through ten years | 277 | |||
Due after ten years | 351 | |||
Total | $ | 984 |
Amount | ||||
(millions) | ||||
Due in one year or less | $ | 116 | ||
Due after one year through five years | 304 | |||
Due after five years through ten years | 357 | |||
Due after ten years | 369 | |||
Total | $ | 1,146 |
Presented below is selected information regarding Dominion’s marketable equity and debt securities held in nuclear decommissioning trust funds.funds:
Year Ended December 31, | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Proceeds from sales | 1,814 | (1) | 1,478 | (2) | 916 | $ | 1,356 | $ | 1,757 | $ | 1,814 | (1) | ||||||||||||
Realized gains | 111 | 215 | 140 | 98 | 79 | 111 | ||||||||||||||||||
Realized losses | 63 | 211 | 404 | 33 | 92 | 63 | ||||||||||||||||||
(1) |
|
86 |
Combined Notes to Consolidated Financial Statements, Continued
|
(2) |
Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2. |
Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:
Year Ended December 31, | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Total other-than-temporary impairment losses(1) | $ | 59 | $ | 175 | $ | 344 | $ | 26 | $ | 75 | $ | 59 | ||||||||||||
Losses recorded to decommissioning trust regulatory liability | (21 | ) | (80 | ) | (105 | ) | (10 | ) | (24 | ) | (21 | ) | ||||||||||||
Losses recognized in other comprehensive income (before taxes) | (3 | ) | (3 | ) | — | (2 | ) | (3 | ) | (3 | ) | |||||||||||||
Net impairment losses recognized in earnings | $ | 35 | $ | 92 | $ | 239 | $ | 14 | $ | 48 | $ | 35 |
(1) | Amounts include other-than-temporary impairment losses for debt securities of |
Equity Method Investments
Investments that Dominion accounts for under the equity method of accounting are as follows:
Company | Ownership% | Investment Balance | Description | Ownership% | Investment Balance | Description | ||||||||||||||||||||||||
As of December 31, | 2010 | 2009 | 2012 | 2011 | ||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||
Fowler I Holdings LLC | 50 | % | $ | 180 | $ | 193 | | Wind-powered merchant generation facility | | 50 | % | $ | 158 | $ | 166 | Wind-powered merchant generation facility | ||||||||||||||
NedPower Mount Storm LLC | 50 | % | 149 | 157 | | Wind-powered merchant generation facility | | 50 | % | 137 | 146 | Wind-powered merchant generation facility | ||||||||||||||||||
Elwood Energy LLC | 50 | % | 117 | 108 | Natural gas-fired merchant generation peaking facility | |||||||||||||||||||||||||
Iroquois Gas Transmission System, LP | 24.72 | % | 106 | 102 | Gas transmission system | 24.72 | % | 102 | 104 | Gas transmission system | ||||||||||||||||||||
Elwood Energy LLC | 50 | % | 98 | 90 |
| Natural gas-fired merchant generation peaking facility |
| |||||||||||||||||||||||
Other | various | 38 | 53 | |||||||||||||||||||||||||||
Blue Racer Midstream LLC | 50 | % | 39 | — | Midstream gas and related services | |||||||||||||||||||||||||
Other(1) | various | 5 | 29 | |||||||||||||||||||||||||||
Total | $ | 571 | $ | 595 | $ | 558 | $ | 553 |
(1) |
Dominion’s equity earnings on these investments totaled $25 million, $35 million and $42 million in both2012, 2011 and 2010, and 2009 and $52 million in 2008. Excluding the 2009 distribution from Fowler Ridge,respectively. Dominion received distributions from these investments of $58 million, $55 million and $60 million $63 millionin 2012, 2011, and $12 million in 2010, 2009, and 2008, respectively. As of December 31, 20102012 and 2009,2011, the carrying amount of Dominion’s investments exceeded Dominion’s share of underlying equity in net assets by approximately $7$30 million and $19$32 million, respectively. Excluding the impairment losses discussed below, theThe differences relate to Dominion’s investments in wind projects and primarily reflect its capitalized interest during construction and the excess of its cash contributions over the book value of development assets contributed by Dominion’s partners for these projects. The differences are generally being amortized over the
useful lives of the underlying assets.
During 2009,BLUE RACER
In December 2012, Dominion recognized total impairment lossesformed a joint venture with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of $30Pennsylvania. The joint venture, Blue Racer, is an equal partner-
ship between Dominion and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital. In return for its December 2012 contribution of assets to the joint venture, Dominion received a 50% interest in Blue Racer and received $115 million in connectioncash proceeds, resulting in a gain of $72 million ($43 million after-tax), net of transaction fees of $9 million, which is recorded in other operations and maintenance expense in Dominion’s Consolidated Statement of Income. The joint venture will leverage Dominion’s existing presence in the Utica region with significant additional new capacity designed to meet producer needs as the Utica Shale acreage is developed. Midstream services offered will include gathering, processing, fractionation, and NGL transportation and marketing. In addition to the assets already contributed, Dominion expects to contribute additional gathering assets, the Natrium extraction plant and related NGL Pipeline, and a decline in estimated fair value of one of its equity method investments as discussed in Note 7. During 2008, Dominion recognized a $7 million gain on the sale of one of its equity method investments.DTI pipeline connecting East Ohio’s gathering system to Natrium.
VIRGINIA POWER
Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below.below:
Amortized Cost | Total Unrealized Gains(1) | Total Unrealized Losses(1) | Fair Value (2) | |||||||||||||
(millions) | ||||||||||||||||
2010 | ||||||||||||||||
Marketable equity securities: | ||||||||||||||||
U.S.: | ||||||||||||||||
Large Cap | $ | 469 | $ | 207 | $ | — | $ | 676 | ||||||||
Other | 20 | 5 | — | 25 | ||||||||||||
Marketable debt securities: | ||||||||||||||||
Corporate debt instruments | 205 | 10 | — | 215 | ||||||||||||
U.S. Treasury securities and agency debentures | 141 | 2 | — | 143 | ||||||||||||
State and municipal | 103 | 1 | (2 | ) | 102 | |||||||||||
Other | 15 | — | — | 15 | ||||||||||||
Cost method investments | 108 | — | — | 108 | ||||||||||||
Cash equivalents and other | 35 | — | — | 35 | ||||||||||||
Total | $ | 1,096 | $ | 225 | $ | (2 | )(3) | $ | 1,319 | |||||||
2009 | ||||||||||||||||
Marketable equity securities: | ||||||||||||||||
U.S.: | ||||||||||||||||
Large Cap | $ | 489 | $ | 126 | $ | — | $ | 615 | ||||||||
Other | 10 | 9 | — | 19 | ||||||||||||
Marketable debt securities: | ||||||||||||||||
Corporate debt instruments | 153 | 9 | (1 | ) | 161 | |||||||||||
U.S. Treasury securities and agency debentures | 95 | 3 | — | 98 | ||||||||||||
State and municipal | 181 | 9 | (1 | ) | 189 | |||||||||||
Other | 3 | — | — | 3 | ||||||||||||
Cost method investments | 97 | — | — | 97 | ||||||||||||
Cash equivalents and other | 22 | — | — | 22 | ||||||||||||
Total | $ | 1,050 | $ | 156 | $ | (2 | )(3) | $ | 1,204 |
Amortized Cost | Total Unrealized Gains(1) | Total Unrealized Losses(1) | Fair Value | |||||||||||||
(millions) | ||||||||||||||||
2012 | ||||||||||||||||
Marketable equity securities: | ||||||||||||||||
U.S.: | ||||||||||||||||
Large Cap | $ | 481 | $ | 298 | $ | — | $ | 779 | ||||||||
Other | 20 | 7 | — | 27 | ||||||||||||
Marketable debt securities: | ||||||||||||||||
Corporate debt instruments | 179 | 17 | — | 196 | ||||||||||||
U.S. Treasury securities and agency debentures | 231 | 4 | (1 | ) | 234 | |||||||||||
State and municipal | 106 | 11 | — | 117 | ||||||||||||
Other | 1 | — | — | 1 | ||||||||||||
Cost method investments | 117 | — | — | 117 | ||||||||||||
Cash equivalents and other(2) | 44 | — | — | 44 | ||||||||||||
Total | $ | 1,179 | $ | 337 | $ | (1 | )(3) | $ | 1,515 | |||||||
2011 | ||||||||||||||||
Marketable equity securities: | ||||||||||||||||
U.S.: | ||||||||||||||||
Large Cap | $ | 460 | $ | 218 | $ | — | $ | 678 | ||||||||
Other | 18 | 5 | — | 23 | ||||||||||||
Marketable debt securities: | ||||||||||||||||
Corporate debt instruments | 204 | 11 | (1 | ) | 214 | |||||||||||
U.S. Treasury securities and agency debentures | 166 | 4 | — | 170 | ||||||||||||
State and municipal | 114 | 10 | — | 124 | ||||||||||||
Other | 16 | 1 | (1 | ) | 16 | |||||||||||
Cost method investments | 118 | — | — | 118 | ||||||||||||
Cash equivalents and other(2) | 27 | — | — | 27 | ||||||||||||
Total | $ | 1,123 | $ | 249 | $ | (2 | )(3) | $ | 1,370 |
(1) | Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2. |
87 |
Combined Notes to Consolidated Financial Statements, Continued
(2) | Includes pending |
(3) | The fair value of securities in an unrealized loss position was |
The fair value of Virginia Power’s debt securities at December 31, 2010,2012, by contractual maturity is as follows:
Amount | Amount | |||||||
(millions) | ||||||||
Due in one year or less | $ | — | $ | 18 | ||||
Due after one year through five years | 151 | 156 | ||||||
Due after five years through ten years | 167 | 217 | ||||||
Due after ten years | 157 | 157 | ||||||
Total | $ | 475 | $ | 548 |
Presented below is selected information regarding Virginia Power’s marketable equity and debt securities.
Year Ended December 31, | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Proceeds from sales | $ | 1,192 | (1) | $ | 715 | (2) | $ | 410 | $ | 626 | $ | 1,030 | $ | 1,192 | ||||||||||
Realized gains | 52 | 104 | 45 | 42 | 34 | 52 | ||||||||||||||||||
Realized losses | 23 | 99 | 143 | 11 | 34 | 23 |
(1) |
Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2. |
Virginia Power recorded other-than-temporary impairment losses on investments as follows:
Year Ended December 31, | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Total other-than-temporary impairment losses(1) | $ | 25 | $ | 94 | $ | 123 | $ | 11 | $ | 29 | $ | 25 | ||||||||||||
Losses recorded to decommissioning trust regulatory liability | (21 | ) | (80 | ) | (105 | ) | (10 | ) | (24 | ) | (21 | ) | ||||||||||||
Losses recorded in other comprehensive income (before taxes) | (1 | ) | — | — | — | (1 | ) | (1 | ) | |||||||||||||||
Net impairment losses recognized in earnings | $ | 3 | $ | 14 | $ | 18 | $ | 1 | $ | 4 | $ | 3 |
(1) | Amounts include other-than-temporary impairment losses for debt securities of |
Other InvestmentsOTHER INVESTMENTS
Dominion and Virginia Power hold restricted cash and cash equivalent balances that primarily consist of money market fund investments held in trust for the purpose of funding certain qualifyingqual-
ifying construction projects. At December 31, 20102012 and 2009,2011, Dominion had $415$37 million and $18$147 million, respectively, and Virginia Power had $169$10 million and $4$32 million, respectively, of restricted cash and cash equivalents. These balances are presented in Other Current Assets and Investments in the Consolidated Balance Sheets.
NOTE 11.10. PROPERTY, PLANTAND EQUIPMENT
Major classes of property, plant and equipment and their respective balances for the Companies are as follows:
At December 31, | 2010 | 2009 | 2012 | 2011 | ||||||||||||
(millions) | ||||||||||||||||
Dominion | ||||||||||||||||
Utility: | ||||||||||||||||
Generation | $ | 11,381 | $ | 11,105 | $ | 13,707 | $ | 11,793 | ||||||||
Transmission | 5,793 | 5,003 | 7,799 | 6,604 | ||||||||||||
Distribution | 9,883 | 9,415 | 11,071 | 10,401 | ||||||||||||
Storage | 1,892 | 1,837 | 2,137 | 2,060 | ||||||||||||
Nuclear fuel | 1,058 | 994 | 1,277 | 1,193 | ||||||||||||
Gas gathering and processing | 535 | 492 | 803 | 727 | ||||||||||||
General and other | 730 | 737 | 803 | 778 | ||||||||||||
Other—including plant under construction | 3,933 | 3,110 | ||||||||||||||
Other-including plant under construction | 2,232 | 3,597 | ||||||||||||||
Total utility | 35,205 | 32,693 | 39,829 | 37,153 | ||||||||||||
Nonutility: | ||||||||||||||||
Proved E&P properties being amortized | 103 | 1,904 | ||||||||||||||
Unproved E&P properties not being amortized | — | 8 | ||||||||||||||
Merchant generation—nuclear | 1,217 | 1,107 | 1,163 | 1,108 | ||||||||||||
Merchant generation—other | 1,451 | 1,657 | ||||||||||||||
Merchant generation—other(1) | 1,289 | 2,780 | ||||||||||||||
Nuclear fuel | 762 | 720 | 775 | 847 | ||||||||||||
Other—including plant under construction | 1,117 | 947 | ||||||||||||||
Other-including plant under construction | 1,265 | 1,102 | ||||||||||||||
Total nonutility | 4,650 | 6,343 | 4,492 | 5,837 | ||||||||||||
Total property, plant and equipment | $ | 39,855 | $ | 39,036 | $ | 44,321 | $ | 42,990 | ||||||||
Virginia Power | ||||||||||||||||
Utility: | ||||||||||||||||
Generation | $ | 11,381 | $ | 11,105 | $ | 13,707 | $ | 11,793 | ||||||||
Transmission | 3,080 | 2,511 | 4,261 | 3,823 | ||||||||||||
Distribution | 7,879 | 7,568 | 8,701 | 8,231 | ||||||||||||
Nuclear fuel | 1,058 | 994 | 1,277 | 1,193 | ||||||||||||
General and other | 591 | 591 | 659 | 631 | ||||||||||||
Other—including plant under construction | 3,610 | 2,866 | ||||||||||||||
Other-including plant under construction | 2,017 | 2,946 | ||||||||||||||
Total utility | 27,599 | 25,635 | 30,622 | 28,617 | ||||||||||||
Nonutility—other | 8 | 8 | ||||||||||||||
Nonutility-other | 9 | 9 | ||||||||||||||
Total property, plant and equipment | $ | 27,607 | $ | 25,643 | $ | 30,631 | $ | 28,626 |
Costs of unproved properties capitalized under the full cost method of accounting that were excluded from amortization at December 31, 2010 and 2009 were not material. There were no significant E&P properties under development, as defined by the SEC, excluded from amortization at December 31, 2010 and 2009.
(1) | Amount includes $957 million due to consolidation of a VIE. |
88 |
Combined Notes to Consolidated Financial Statements, Continued
Volumetric Production Payment Transactions
During 2007, in conjunction with the sale of Dominion’s non-Appalachian E&P operations, Dominion paid $250 million to terminate their existing VPP agreements and retained the VPP royalty interests formerly associated with these agreements. Production from VPP royalty interests declined significantly in 2009, reflecting the expiration of these interests in February 2009.
Assignment of Marcellus Acreage
In 2008, Dominion completed a transaction with Antero to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania.
Dominion received proceeds of approximately $347 million. The net proceeds were credited to Dominion’s full cost pool, reducing property, plant and equipment in the Consolidated Balance Sheet, as the transaction did not significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil. Under the agreement, Dominion received a 7.5% overriding royalty interest on future natural gas production from the assigned acreage and retained the drilling rights in traditional formations both above and below the Marcellus Shale. However, as a result of the sale of substantially all of Dominion’s Appalachian E&P operations, the overriding royalty interest was transferred to CONSOL.
Jointly-Owned Power Stations
Dominion’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 20102012 is as follows:
Bath County Pumped Storage Station(1) | North Anna Power Station(1) | Clover Power Station(1) | Millstone Unit 3(2) | Bath County Pumped Storage Station(1) | North Anna Units 1 and 2(1) | Clover Power Station(1) | Millstone Unit 3(2) | |||||||||||||||||||||||||
(millions, except percentages) | ||||||||||||||||||||||||||||||||
Ownership interest | 60.0 | % | 88.4 | % | 50.0 | % | 93.5 | % | 60 | % | 88.4 | % | 50 | % | 93.5 | % | ||||||||||||||||
Plant in service | $ | 1,022 | $ | 2,294 | $ | 562 | $ | 1,001 | $ | 1,024 | $ | 2,392 | $ | 568 | $ | 993 | ||||||||||||||||
Accumulated depreciation | (474 | ) | (1,047 | ) | (178 | ) | (212 | ) | (521 | ) | (1,072 | ) | (192 | ) | (236 | ) | ||||||||||||||||
Nuclear fuel | — | 491 | — | 302 | — | 502 | — | 456 | ||||||||||||||||||||||||
Accumulated amortization of nuclear fuel | — | (366 | ) | — | (206 | ) | — | (390 | ) | — | (272 | ) | ||||||||||||||||||||
Plant under construction | 1 | 246 | 8 | 56 | 27 | 77 | 6 | 36 |
(1) |
(2) | Unit jointly owned by Dominion. |
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.
NOTE 12.11. GOODWILLAND INTANGIBLE ASSETS
Goodwill
In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The sale resulted in an after-tax loss of approximately $140 million, which included a $79 million write-off of goodwill.
In April 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. The transaction resulted in an after-tax gain of approximately $1.4 billion, which included a $134 million write-off of goodwill.
In December 2009, Dominion made the decision to retain Hope and include it with 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 in 2009 as no events occurred that would more-likely-than-not reduce the reporting units’ fair values below their carrying values.
The changes in Dominion’s carrying amount and segment allocation of goodwill are presented below:
Dominion Generation | Dominion Energy | DVP | Corporate and Other | Total | ||||||||||||||||
(millions) | ||||||||||||||||||||
Balance at December 31, 2008(1) | $ | 1,455 | $ | 861 | $ | 1,091 | $ | 96 | $ | 3,503 | ||||||||||
Reallocation due to segment realignment | — | 15 | — | (15 | ) | — | ||||||||||||||
Business acquisition adjustment | (117 | ) | (30 | ) | — | (2 | ) | (149 | ) | |||||||||||
Balance at December 31, 2009(1) | $ | 1,338 | $ | 846 | $ | 1,091 | $ | 79 | $ | 3,354 | ||||||||||
Business disposition adjustment | — | (134 | ) | — | (79 | ) | (213 | ) | ||||||||||||
Balance at December 31, 2010(1) | $ | 1,338 | $ | 712 | $ | 1,091 | $ | — | $ | 3,141 |
Dominion Generation | Dominion Energy | DVP | Corporate and Other | Total | ||||||||||||||||
(millions) | ||||||||||||||||||||
Balance at December 31, 2010(1) | $ | 1,338 | $ | 712 | $ | 1,091 | $ | — | $ | 3,141 | ||||||||||
Impairments/adjustments | — | — | — | — | — | |||||||||||||||
Balance at December 31, 2011(1) | $ | 1,338 | $ | 712 | $ | 1,091 | $ | — | $ | 3,141 | ||||||||||
Asset disposition adjustment | — | (11 | ) | — | — | (11 | ) | |||||||||||||
Balance at December 31, 2012(1) | $ | 1,338 | $ | 701 | $ | 1,091 | $ | — | $ | 3,130 |
(1) | Goodwill amounts do not contain any accumulated impairment losses. |
Other Intangible Assets
Dominion’s and Virginia Power’s other intangible assets are subject to amortization over their estimated useful lives. Dominion’s amortization expense for intangible assets was $82 million, $78 million and $107 million $155 millionfor 2012, 2011 and $95 million for 2010, 2009 and 2008, respectively. In 2010,2012, Dominion acquired $61 million of intangible assets, primarily representing software and emissions allowances, with estimated weighted-average amortization periods of approximately 5 years and 1 year, respectively. Amortization expense for Virginia Power’s intangible assets was $26 million, $26 million, and $28 million for 2010, 2009 and 2008, respectively. In 2010, Virginia Power acquired $20$102 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 5approximately 19 years. Amortization expense for Virginia Power’s intangible assets was $22 million, $22 million and $26 million for 2012, 2011, and 2010, respectively. In 2012, Virginia Power acquired $53 million of intangible assets, primarily representing software, with an esti-
mated weighted-average amortization period of 31 years. The components of intangible assets are as follows:
At December 31, | 2010 | 2009 | 2012 | 2011 | ||||||||||||||||||||||||||||
Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Dominion | ||||||||||||||||||||||||||||||||
Software and software licenses | $ | 651 | $ | 295 | $ | 657 | $ | 325 | ||||||||||||||||||||||||
Software, licenses and other | $ | 859 | $ | 327 | $ | 888 | $ | 278 | ||||||||||||||||||||||||
Emissions allowances | 134 | 50 | 229 | 74 | 5 | 1 | 80 | 53 | ||||||||||||||||||||||||
Other | 241 | 39 | 237 | 31 | ||||||||||||||||||||||||||||
Total | $ | 1,026 | $ | 384 | $ | 1,123 | $ | 430 | $ | 864 | $ | 328 | $ | 968 | $ | 331 | ||||||||||||||||
Virginia Power | ||||||||||||||||||||||||||||||||
Software and software licenses | $ | 251 | $ | 124 | $ | 265 | $ | 149 | ||||||||||||||||||||||||
Emissions allowances | 48 | 3 | 68 | 5 | ||||||||||||||||||||||||||||
Other | 56 | 16 | 53 | 15 | ||||||||||||||||||||||||||||
Software, licenses and other | $ | 303 | $ | 122 | $ | 285 | $ | 102 | ||||||||||||||||||||||||
Total | $ | 355 | $ | 143 | $ | 386 | $ | 169 | $ | 303 | $ | 122 | $ | 285 | $ | 102 |
Annual amortization expense for these intangible assets is estimated to be as follows:
2011 | 2012 | 2013 | 2014 | 2015 | 2013 | 2014 | 2015 | 2016 | 2017 | |||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
Dominion | $ | 81 | $ | 57 | $ | 46 | $ | 34 | $ | 27 | $ | 65 | $ | 56 | $ | 43 | $ | 37 | $ | 25 | ||||||||||||||||||||
Virginia Power | $ | 21 | $ | 20 | $ | 14 | $ | 11 | $ | 6 | $ | 20 | $ | 18 | $ | 12 | $ | 8 | $ | 5 |
89 |
Combined Notes to Consolidated Financial Statements, Continued
NOTE 13.12. REGULATORY ASSETSAND LIABILITIES
Regulatory assets and liabilities include the following:
At December 31, | 2010 | 2009 | ||||||
(millions) | ||||||||
Dominion | ||||||||
Regulatory assets: | ||||||||
Deferred cost of fuel used in electric generation(1) | $ | 174 | $ | 41 | ||||
Deferred transmission costs(2) | 76 | — | ||||||
PIPP(3) | 44 | — | ||||||
Unrecovered gas costs(4) | 39 | 52 | ||||||
Virginia sales taxes(5) | 35 | 34 | ||||||
Other | 39 | 43 | ||||||
Regulatory assets-current | 407 | 170 | ||||||
Unrecognized pension and other postretirement benefit costs(6) | 987 | 968 | ||||||
Deferred cost of fuel used in electric generation(1) | 153 | — | ||||||
PIPP(3) | — | 143 | ||||||
Income taxes recoverable through future rates(7) | 90 | 75 | ||||||
Deferred transmission costs(2) | 49 | 61 | ||||||
Other postretirement benefit costs(8) | 29 | 36 | ||||||
Other | 138 | 107 | ||||||
Regulatory assets-non-current | 1,446 | 1,390 | ||||||
Total regulatory assets | $ | 1,853 | $ | 1,560 | ||||
Regulatory liabilities: | ||||||||
Provision for rate proceedings(9) | $ | 79 | $ | 473 | ||||
Other | 56 | 63 | ||||||
Regulatory liabilities-current | 135 | 536 | ||||||
Decommissioning trust(10) | 391 | 324 | ||||||
Provision for future cost of removal and AROs(11) | 830 | 766 | ||||||
Derivatives(12) | 68 | 105 | ||||||
Other | 103 | 20 | ||||||
Regulatory liabilities-non-current | 1,392 | 1,215 | ||||||
Total regulatory liabilities | $ | 1,527 | $ | 1,751 | ||||
Virginia Power | ||||||||
Regulatory assets: | ||||||||
Deferred cost of fuel used in electric generation(1) | $ | 174 | $ | 41 | ||||
Deferred transmission costs(2) | 76 | — | ||||||
Virginia sales taxes(5) | 35 | 34 | ||||||
Other | 33 | 41 | ||||||
Regulatory assets-current | 318 | 116 | ||||||
Deferred cost of fuel used in electric generation(1) | 153 | — | ||||||
Income taxes recoverable through future rates(7) | 76 | 67 | ||||||
Deferred transmission costs(2) | 49 | 61 | ||||||
Other | 92 | 72 | ||||||
Regulatory assets-non-current | 370 | 200 | ||||||
Total regulatory assets | $ | 688 | $ | 316 | ||||
Regulatory liabilities: | ||||||||
Provision for rate proceedings(9) | $ | 79 | $ | 473 | ||||
Other | 30 | 18 | ||||||
Regulatory liabilities-current | 109 | 491 | ||||||
Provision for future cost of removal(11) | 622 | 562 | ||||||
Decommissioning trust(10) | 391 | 324 | ||||||
Derivatives(12) | 68 | 105 | ||||||
Other | 93 | 4 | ||||||
Regulatory liabilities-non-current | 1,174 | 995 | ||||||
Total regulatory liabilities | $ | 1,283 | $ | 1,486 |
At December 31, | 2012 | 2011 | ||||||
(millions) | ||||||||
Dominion | ||||||||
Regulatory assets: | ||||||||
Unrecovered gas costs(1) | $ | 59 | $ | 48 | ||||
Deferred rate adjustment clause costs(2) | 55 | 113 | ||||||
Virginia sales taxes(3) | 37 | 32 | ||||||
Plant retirement(4) | 25 | 27 | ||||||
Deferred cost of fuel used in electric generation(5) | — | 249 | ||||||
Derivatives(6) | — | 45 | ||||||
Other | 27 | 27 | ||||||
Regulatory assets-current | 203 | 541 | ||||||
Unrecognized pension and other postretirement benefit costs(7) | 1,210 | 887 | ||||||
Deferred rate adjustment clause costs(2) | 173 | 107 | ||||||
Income taxes recoverable through future rates(8) | 140 | 121 | ||||||
Derivatives(6) | 105 | 49 | ||||||
Other postretirement benefit costs(9) | 21 | 26 | ||||||
Plant retirement(4) | 11 | 25 | ||||||
Deferred cost of fuel used in electric generation(5) | — | 122 | ||||||
Other | 57 | 45 | ||||||
Regulatory assets-non-current | 1,717 | 1,382 | ||||||
Total regulatory assets | $ | 1,920 | $ | 1,923 | ||||
Regulatory liabilities: | ||||||||
PIPP(10) | $ | 100 | $ | 58 | ||||
Provision for rate proceedings(11) | 8 | 150 | ||||||
Other | 28 | 35 | ||||||
Regulatory liabilities-current | 136 | 243 | ||||||
Provision for future cost of removal and AROs(12) | 985 | 901 | ||||||
Decommissioning trust(13) | 501 | 399 | ||||||
Other | 28 | 24 | ||||||
Regulatory liabilities-non-current | 1,514 | 1,324 | ||||||
Total regulatory liabilities | $ | 1,650 | $ | 1,567 | ||||
Virginia Power | ||||||||
Regulatory assets: | ||||||||
Deferred rate adjustment clause costs(2) | $ | 51 | $ | 113 | ||||
Virginia sales taxes(3) | 37 | 32 | ||||||
Plant retirement(4) | 25 | 27 | ||||||
Deferred cost of fuel used in electric generation(5) | — | 249 | ||||||
Derivatives(6) | — | 45 | ||||||
Other | 6 | 13 | ||||||
Regulatory assets-current | 119 | 479 | ||||||
Deferred rate adjustment clause costs(2) | 127 | 70 | ||||||
Income taxes recoverable through future rates(8) | 110 | 100 | ||||||
Derivatives(6) | 105 | 49 | ||||||
Plant retirement(4) | 11 | 25 | ||||||
Deferred cost of fuel used in electric generation(5) | — | 122 | ||||||
Other | 43 | 33 | ||||||
Regulatory assets-non-current | 396 | 399 | ||||||
Total regulatory assets | $ | 515 | $ | 878 | ||||
Regulatory liabilities: | ||||||||
Provision for rate proceedings(11) | $ | 7 | $ | 150 | ||||
Other | 25 | 28 | ||||||
Regulatory liabilities-current | 32 | 178 | ||||||
Provision for future cost of removal(12) | 763 | 687 | ||||||
Decommissioning trust(13) | 501 | 399 | ||||||
Other | 21 | 9 | ||||||
Regulatory liabilities-non-current | 1,285 | 1,095 | ||||||
Total regulatory liabilities | $ | 1,317 | $ | 1,273 |
(1) |
Combined Notes to Consolidated Financial Statements, Continued
Reflects unrecovered gas costs at Dominion’s regulated gas operations, which are recovered through quarterly or annual filings with the applicable regulatory authority. |
| Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for more information. |
(3) | Amounts to be recovered through an annual surcharge to reimburse Virginia Power for incremental sales taxes being incurred due to the repeal of the public service company sales tax exemption in Virginia. |
(4) | Reflects costs anticipated to be recovered in base rates for certain coal units expected to be retired. |
(5) | Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power’s generation operations. See Note 13 for more information. |
(6) | As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers. |
(7) | Represents unrecognized pension and other postretirement benefit costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain of Dominion’s rate-regulated subsidiaries. |
| Amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes. |
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Under PIPP, eligible customers can receive energy assistance based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rider according to East Ohio tariff provisions. See Note 13 for more information regarding PIPP. |
(11) | Reflects a reserve associated with the |
Rates charged to customers by the Companies’ regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement. |
(13) | Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related ARO. |
At December 31, 2010,2012, approximately $81$319 million of Dominion’s and $22$240 million of Virginia Power’s regulatory assets represented past expenditures on which they do not currently earn a return. Dominion’s expenditures primarily include unrecovered gas costs. The aboveThese expenditures are expected to be recovered within the next two years.
NOTE 14.13. REGULATORY MATTERS
Regulatory Matters Involving Potential Loss Contingencies
As a result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to esti-
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mate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss does not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on Dominion’s or Virginia Power’s financial position, liquidity or results of operations. The following is a discussion of Dominion’s and Virginia Power’s material pending and recent regulatory matters.
FERC—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.
Rates
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
In July 2008, Virginia Power filed an application with FERC requesting a revision to its revenue 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 1.5% for four of the projects (including the Meadow Brook-to-Loudoun and Carson-to-Suffolk lines, which were completed in 2011) and an incentive of 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008, the incentives were included in the PJM Tariff, and billing for the incentives was made accordingly. In 2012, PJM canceled one of the eleven projects with an estimated cost of $7 million. The total cost for the other ten projects included in Virginia Power’s formula rate for 2013 is $852 million and the remaining projects were completed in 2012. Numerous parties sought rehearing of the FERC order in August 2008, and in May 2012 FERC denied
rehearing. In July 2012, the North Carolina Commission filed an appeal of the FERC orders granting the incentives with the Fourth Circuit Court of Appeals. Although Virginia Power cannot predict the outcome of the appeal, 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 establish 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. In February 2012, Virginia Power submitted to FERC a settlement agreement to resolve all issues set for hearing. All transmission customer parties to the proceeding joined the settlement. The Virginia Commission, North Carolina Commission and Public Staff of the North Carolina Commission, while not parties to the settlement, have agreed to not oppose the settlement. The settlement was accepted by FERC in May 2012 and provides for payment by Virginia Power to the transmission customer parties collectively of $250,000 per year for ten years and resolves all matters other than allocation of the incremental cost of certain underground transmission facilities, which has been briefed pursuant to FERC’s May 2012 order and awaits FERC action. While Virginia Power cannot predict the outcome of the briefing, it is not expected to have a material effect on results of operations.
PJM
In November 2011, PJM issued a formal notification that it would recalculate certain ancillary service revenues that had previously been paid during 2009, 2010 and 2011. Also in November 2011, PJM requested FERC permission to suspend its rebilling and repayment obligations associated with the recalculation of such revenues and petitioned FERC to establish a proceeding to determine the appropriate recalculations for the revenues during this period. In December 2011, FERC permitted the suspension of rebilling and repayment by PJM, subject to the outcome of FERC’s proceedings to determine the appropriate revenue recalculation. In April 2012, FERC issued an Order Establishing Hearing and Settlement Judge Procedures to address the appropriate recalculation of the ancillary service credits PJM will be required to collect from Virginia Power. In August 2012, PJM filed a settlement on behalf of itself, Virginia Power and the PJM Market Monitor. In November 2012, FERC approved the settlement resolving all issues in the proceeding. As of September 30, 2012, Virginia Power had accrued a liability of $33 million, and in January 2013, Virginia Power paid PJM approximately $33 million, resolving the matter.
Other Regulatory Matters
Electric Regulation in Virginia
Prior toThe enactment of the Regulation Act whichin 2007 significantly changed electricityelectric service regulation in Virginia Virginia Power’s Virginia jurisdictional base rates wereby instituting a modified cost-of-service rate model. With respect to be capped at 1999 levels until December 31, 2010, at which time Virginia was to convertmost classes of customers, the Regulation Act ended Virginia’s planned transition to retail competition for its electric supply service.
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Combined Notes to Consolidated Financial Statements, Continued
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 ActIt provides for enhanced returns on capital expenditures on specific new generation projects, including but not limited to combined cycle gas generation, 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. Legislation was enacted in February 2013 that amends the Regulation Act prospectively. SeeFuture Issues and Other Matters in Item 7. MD&A for a discussion of this legislation.
If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.
2011 Biennial Review
Pursuant to the Regulation Act and the Virginia Settlement Approval Order, in March 2011, Virginia Power submitted its base rate filing and accompanying schedules in support of the first biennial review of its base rates, terms and conditions, as well as of its earnings for the 2009 and 2010 test period. The biennial review included a determination of whether Virginia Power’s earnings for the 2009 and 2010 combined test years were within 50 basis points of the authorized ROE of 11.9% established in the Virginia Settlement Approval Order, as well as authorization of an ROE which will be applicable to base rates and rate adjustment clauses and which will be used to measure base rate earnings during the 2013 biennial review proceeding. As a result of the Virginia Settlement Approval Order and the Regulation Act, Virginia Power’s base rates are not subject to change based on the 2011 biennial review. In November 2011, the Virginia Commission entered an orderissued the Biennial Review Order.
In the Biennial Review Order, the Virginia Commission declined to award a performance incentive for generating plant performance, customer service or operating efficiency 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 to2009-2010 biennial review. Instead, in March 2012, the Virginia Commission during 2009. issued an order initiating a rulemaking proceeding to develop specific performance metrics and nationally recognized standards for determining positive or negative performance incentives for electric utilities. Such incentive criteria would be applied in future biennial review proceedings.
In February 2010, Virginia Power filed a revised Stipulation and Recommendation withSeptember 2012, the Virginia Commission which hadissued an Order for Notice and Hearing in the support of all ofseparate rulemaking proceeding to develop specific performance standards based on nationally recognized standards for the interested parties, includingVirginia Commission’s consideration in determining positive or negative performance incentives for electric utilities. The Virginia Commission modified the proposed rules and regulations for performance incentives filed by the Staff of the Virginia Commission. Virginia Power’s fourth quarter 2009 results includedCommission, allowed for further comments by November 2012 on the proposed rules and regulations as modified, and held a charge of $782 million ($477 million after-tax) representing its best estimate at the time of the probable outcome of the 2009 Base Rate Review.public hearing in November 2012. In March 2010,January 2013, the Virginia Commission issued its order adopting revised performance incentive rules and regulations effective February 1, 2013.
Base ROE
The Virginia Commission determined that Virginia Power’s new authorized ROE is 10.9%, inclusive of a performance incentive of 50 basis points for meeting certain RPS targets. As discussed below, this ROE will serve as the ROE against which Virginia Power’s earned return will be compared for the test periods in the 2013 biennial review proceeding. The Virginia Commission ordered that the 50 basis point RPS performance incentive will not be included in the ROE applicable to any rate adjustment clauses.
In December 2011, Virginia Power filed a petition with the Virginia Commission seeking rehearing or reconsideration of the Biennial Review Order, to confirm the effective date of the newly authorized 10.9% base ROE. Virginia Power’s petition requested the Virginia Commission to confirm that the 10.9% ROE authorized in the Biennial Review Order would apply prospectively, effective following the date of the Biennial Review Order on November 30, 2011, and that Virginia Power’s previously-approved 11.9% base ROE authorized in the Virginia Settlement Approval Order that concludedwould be used to measure base rate earnings for the 2009 Base Rate Review and resolved open issues relatingperiod January 1, 2011 through November 30, 2011. In March 2012, the Virginia Commission issued an order denying Virginia Power’s petition seeking rehearing or reconsideration. Contrary to Virginia Power’s fuel factorposition, the Virginia Commission ruled that the new 10.9% ROE will be used to measure earnings for the entire 2011-2012 test period in the next biennial review in 2013, which is expected to be filed in March 2013.
Also in March 2012, Virginia Power filed Petitions for Appeal with the Supreme Court of Virginia regarding the Biennial Review Order and Rider T. An the March 2012 Order. In May 2012, the Supreme Court of Virginia granted review of Virginia Power’s appeals from the Biennial Review Order and the March 2012 Order denying Virginia Power’s petition seeking rehearing or reconsideration, and heard oral argument on both appeals in September 2012. In November 2012, the Supreme Court of Virginia affirmed the Biennial Review Order and the March 2012 Order denying Virginia Power’s petition seeking rehearing or reconsideration.
ROE issue relatingApplicable to Riders C1, C2, R, and S
Effective December 1, 2011, the ROE applicable to Riders C1 and C2 was also resolved.is 10.4%. For Riders R and S, effective December 1, 2011, the ROE is 11.4%, inclusive of a statutory enhancement of 100 basis points.
Earned Return for 2009 and 2010
The Virginia Commission determined that Virginia Power earned an ROE of approximately 13.3% during the 2009 and 2010 combined test years, which exceeded the authorized ROE earnings band of 11.4% to 12.4% established in the Virginia Settlement Approval Order includedOrder. Based on the following provisions:determination that Virginia Power had excess earnings, the Virginia Commission ordered Virginia Power to refund 60% of earnings above the upper end of the authorized ROE earnings band, or approximately $78 million, to its customers, which was provided in the form of credits to customers’ bills amortized over a six-month period during 2012. A charge for the refund was recognized in operating revenues in the 2011 Consolidated Statement of Income. The actual
Credits from 2008 Revenues
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aggregate refund amount totaled approximately $81 million, taking into account refunds to be paid to certain non-jurisdictional customers pursuant to their customer contracts.
Base Rates and Existing Riders T, C1, and C2
As a result of the Virginia Commission’s determination that credits will be applied to customers’ bills, the Virginia Commission, as required by the Regulation Act, directed Virginia Power to combine its existing Riders T, C1, and C2 with Virginia Power’s base costs, revenues and investments, and to file revised tariffs reflecting such combination pursuant to the Biennial Review Order. These Riders will thereafter be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings.
In April 2012, the Virginia Commission held that Riders C1 and C2 are now to be combined in Virginia Power’s base rates and are to be considered as part of its future biennial reviews. The Virginia Commission rejected Virginia Power’s requests to identify and separately track the revenues for these existing riders in base rates, and to preserve deferral accounting for these revenues in base rates, stating that such deferral accounting ceased December 1, 2011 for existing Riders C1 and C2. In August 2012, the Virginia Commission confirmed that existing Rider T had been combined in base rates, and ruled that transmission costs would continue to be tracked separately to permit deferral accounting and dollar-for-dollar recovery of costs through Rider T and through Rider T1, a new increment/decrement rate adjustment clause to recover the difference in the revenue requirement for rate year costs and the revenues collected under Rider T. |
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FTR CreditsEarnings Test Adjustments
The Virginia Commission ruled on numerous contested proposals to adjust Virginia Power’s earnings for the 2009 and 2010 combined test periods. Among other adjustments, the Virginia Commission approved Virginia Power’s ratemaking treatment of fuel inventories held by its wholly-owned subsidiaries. As a result of this finding, Virginia Power included in rate base approximately $188 million in fuel inventory costs for 2010. The Virginia Commission also adopted Virginia Power’s treatment that includes, for regulatory earnings purposes, its AIP and LTIP expenses up to a 100% payout ratio. The Virginia Commission excluded from expense approximately $21 million in incentive plan costs that exceeded a payout ratio of 100%, allowing a net recovery of approximately $95 million of incentive compensation expense for the biennial review period. The Virginia Commission denied Virginia Power’s ratemaking treatment that expensed the entire cost of its 2010 voluntary separation plan in 2010, ruling instead to amortize the cost through the end of 2011. This matched the costs of the plan with the period of realization of savings, which reduced 2010 operating costs (and in turn, increased 2011 operating costs) by approximately $103 million for purposes of the earnings test. Other than influencing the amount earned above the authorized ROE earnings band, the earnings test adjustments above did not have an impact to the Consolidated Financial Statements.
In addition, the Virginia Commission required Virginia Power to recognize a gain, for purposes of the earnings test, of approximately $44 million on the settlement of certain interest rate hedging contracts in 2010, as opposed to amortizing the gains over the forecasted term of planned debt instruments that were not issued. Virginia Power determined that it was no longer probable that these derivative gains would be included in future base rates as the Virginia Commission would not allow the amortization of these amounts in future periods. As a result, Virginia Power removed approximately $50 million in December 2011 from regulatory liabilities and recognized the deferred derivative settlement gains in interest and related charges in the Consolidated Statements of Income. |
Virginia Fuel Expenses
In May 2012, Virginia Power submitted its annual fuel factor filing to the Virginia Commission, proposing a decrease of approximately $389 million in fuel revenue for the rate year beginning July 1, 2012. In September 2012, after a public hearing, the Virginia Commission issued an order approving Virginia Power’s filing.
Generation Riders R and S
In connection with the Bear Garden and Virginia City Hybrid Energy Center projects, in March 2011, the Virginia Commission approved annual updates for Riders R and S with revenue requirements of $78 million and $199 million, respectively, for the April 1, 2011 to March 31, 2012 rate year, utilizing the 12.3% placeholder ROE (inclusive of a 100 basis point statutory enhancement) pending the Virginia Commission’s ROE determination in the 2011 biennial review.
In March 2012, the Virginia Commission approved annual updates for Riders R and S for the April 1, 2012 to March 31, 2013 rate year, utilizing an 11.4% ROE (inclusive of a 100 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order. The Virginia Commission’s approvals authorized an approximately $74 million revenue requirement for Rider R, and an approximately $226 million revenue requirement for Rider S, comprised of approximately $52 million for the pre-commercial operation period and approximately $174 million for the commercial operation period.
In June 2012, Virginia Power requested Virginia Commission approval of its annual updates for Riders R and S for the next two consecutive rate years, utilizing an 11.4% ROE (inclusive of a 100 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order and subject to true-up based on changes in the authorized ROE in future biennial review proceedings. For Rider R, Virginia Power proposed an approximately $81 million revenue requirement for the rate year beginning April 1, 2013 and an approximately $75 million revenue requirement for the rate year beginning April 1, 2014. For Rider S, an approximately $249 million revenue requirement was proposed for the rate year beginning April 1, 2013 and an approximately $229 million revenue requirement was proposed for the rate year beginning April 1, 2014. Virginia Power has agreed to certain adjustments supported by Virginia Commission Staff reducing the Rider R revenue requirements to approximately $78 million for the rate year beginning April 1, 2013, and approximately $72 million for the rate year beginning April 1, 2014. In February 2013, the Virginia Commission approved these cost recovery periods and amounts for Rider R, as well as a multi-year approach in which Virginia Power would file its next
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Combined Notes to Consolidated Financial Statements, Continued update filing for Rider R in 2014. In January 2013, Virginia Power filed a proposed stipulation agreement reached with the Virginia Commission Staff supporting a revised revenue requirement for Rider S of approximately $248 million for the rate year beginning April 1, 2013. Virginia Power and the Staff of the Virginia Commission also agreed that Virginia Power would file a Rider S case in 2013 instead of a multi-year approach. The Rider S update proceeding is pending. Construction of the Virginia City Hybrid Energy Center was completed and the facility commenced commercial operations in July 2012. |
DSM Riders C1A and C2A
In April 2012, the Virginia Commission approved a revenue requirement of $5 million for Rider C1A and $17 million for Rider C2A. This approval incorporated four new energy efficiency DSM programs as a bundle for residential customers for a five-year period starting June 1, 2012, subject to a total $90 million cost cap. The Virginia Commission also approved two new energy efficiency DSM programs as a bundle for commercial customers for the same five-year period, subject to a total $45 million cost cap, as well as a new peak-shaving DSM program for commercial customers for the same five-year period, subject to an approximately $14 million cost cap.
In August 2012, Virginia Power requested extension of two DSM programs (the Residential Air Conditioner Cycling Program and the Residential Low Income Program) by five years and two years, respectively, beyond their current April 30, 2013 termination date, as well as approval of a process whereby the Staff could administratively approve limited modifications to the designs of previously approved DSM programs. Virginia Power’s proposed revenue requirements for Riders C1A and C2A for the May 1, 2013 to April 30, 2014 rate year are $4 million and $23 million, respectively. This case is pending.
Transmission Riders T and T1
In May 2011, Virginia Power filed its annual update to Rider T with the Virginia Commission. The proposed $481 million annual revenue requirement, effective September 1, 2011, represented an increase of approximately $144 million over the revenue requirement associated with the Rider T customer rates previously in effect. In July 2011, the Virginia Commission issued an order approving a revenue requirement of $466 million for the September 1, 2011 to August 31, 2012 rate year. As discussed above, previously implemented Rider T will be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings. The Virginia Commission has initiated a proceeding to address further implementation of this directive.
In May 2012, Virginia Power filed Rider T1 with the Virginia Commission to recover costs of transmission service and demand response programs for the September 1, 2012 to August 31, 2013 rate year. The proposed Rider T1 reduction of approximately $100 million produces a total annual revenue requirement of approximately $373 million when netted with the revenue requirement of approximately $473 million associated with the Rider T customer rates currently in effect, and now combined in Virginia Power’s base rates. Virginia Power’s filing stated that Rider T costs combined in base rates should be identified and separately tracked, with the continuation of deferral accounting and dollar-for-dollar recovery for these costs. Virginia Power’s
proposed revenue requirement was supported by the Staff of the Virginia Commission, although the Staff concurrently proposed an alternative methodology for the Rider T1 revenue requirement which would represent an increase of approximately $18 million from the current Rider T customer rates. The Staff’s alternative methodology would have precluded deferral accounting and dollar-for-dollar recovery for Rider T in future periods.
In August 2012, the Virginia Commission approved Virginia Power’s proposed Rider T1 to recover costs of transmission service and demand response programs for the September 1, 2012 to August 31, 2013 rate year, ordering a Rider T1 reduction of approximately $100 million versus the Rider T customer rates currently in effect, and now combined in Virginia Power’s base rates. The Virginia Commission agreed with the approach recommended by Virginia Power and supported by the Staff of the Virginia Commission in this case. Rider T, which is now combined in base rates, along with Rider T1, and is being tracked separately to permit deferral accounting and dollar-for-dollar recovery.
Generation Rider W
In May 2011, Virginia Power requested approval from the Virginia Commission to construct and operate Warren County, as well as approval of Rider W. In February 2012, the Virginia Commission approved Certificates of Public Convenience and Necessity for Warren County and related transmission facilities. The Virginia Commission also approved a revenue requirement of $34 million for the April 1, 2012 to March 31, 2013 rate year, reflecting an ROE of 11.4%, inclusive of a statutory enhancement of 100 basis points for Rider W, consistent with the Biennial Review Order. In addition, the Virginia Commission approved an ROE enhancement of 100 basis points for Rider W for a period of 10 years following commercial operations. The facility is expected to start commercial operations in late 2014.
In June 2012, Virginia Power requested Virginia Commission approval of its annual update for Rider W for the April 1, 2013 to March 31, 2014 rate year. Virginia Power proposed an approximately $86 million revenue requirement, utilizing an 11.4% ROE (inclusive of a 100 basis point statutory enhancement) also consistent with the base ROE authorized in the Biennial Review Order. In December, 2012, Virginia Power filed a proposed partial stipulation agreement reached with the Virginia Commission Staff supporting a revised revenue requirement for Rider W of approximately $83 million for the rate year commencing April 1, 2013. In February 2013, the Virginia Commission approved this revised revenue requirement. Generation Rider B In June 2011, Virginia Power filed applications with the Virginia Commission seeking regulatory approval to convert three of its coal-fired power stations to biomass. The applications included a request for approval of Rider B. To qualify for federal production tax credits associated with renewable energy generation, the power stations must commence operation as biomass generation facilities by December 31, 2013. Virginia Power requested Virginia Commission approval of the biomass conversions on a schedule that will enable qualification for these tax credits. In March 2012, the Virginia Commission approved the conversion of the Altavista, Hopewell, and Southampton power stations to biomass. These conversions will increase Dominion’s |
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DSM Riders C1renewable generation by more than 150 MW and C2are expected to be completed by the end of 2013.
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Commencing in 2011,As part of its approval, the Virginia Commission also approved Rider B. The approved revenue requirement for Rider B is approximately $6 million for the April 1, 2012 to March 31, 2013 rate year, utilizing a 12.4% ROE (inclusive of a 200 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order. The renewable generating unit statutory enhancement of 200 basis points will conduct biennial reviewsapply during construction and the first five years of the service lives of the converted facilities.
In June 2012, Virginia Power requested Virginia Commission approval of its annual update for Rider B for the April 1, 2013 to March 31, 2014 rate year. Virginia Power proposed an approximately $12 million revenue requirement, utilizing a 12.4% ROE (inclusive of a 200 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order. In January 2013, Virginia Power filed a proposed stipulation agreement reached with the Virginia Commission Staff supporting approval of a revenue requirement for the pre-commercial operations date period and the post-commercial operations date period, resulting in an average recovery amount of approximately $12 million for the rate year commencing April 1, 2013. This case is pending.
Brunswick County Power Station and Generation Rider BW
In November 2012, Virginia Power requested approval from the Virginia Commission to construct and operate Brunswick County. The application included a request for approval of associated transmission facilities and Rider BW. Virginia Power’s proposed revenue requirement for Rider BW is approximately $45 million for the September 1, 2013 to August 31, 2014 rate year, reflecting an ROE of 11.4%, inclusive of a statutory enhancement of 100 basis points for Rider BW, consistent with the Biennial Review Order. Virginia Power requested an ROE enhancement of 100 basis points for Rider BW for a period of 15 years following commercial operations. The facility is expected to begin commercial operations in spring 2016. This case is pending.
Bremo Power Station
In August 2012, Virginia Power requested approval from the Virginia Commission of an amended and reissued Certificate of Public Convenience and Necessity that would allow Virginia Power to convert Bremo Units 3 and 4 from coal to natural gas as their fuel source. The proposed conversion would preserve 227 MW (net) of existing capacity and is expected to be complete in 2014. Cost recovery would occur through base rates, terms and conditions. not through a rate adjustment clause. This case is pending.
Solar Distributed Generation Demonstration Program
In the biennial review, as in the 2009 Base Rate Review, Virginia Power’s authorized ROE can be no lower than the average of that 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 Power’s earnings are more than 50 basis points above the authorized level, such earnings will be shared with customers.
October 2011, Virginia Power previously filed with the Virginia Commission an application for approvalto conduct a solar distributed generation demonstration program, consisting of up to a combined 30 MW of Company-owned solar distributed generation facilities to be located at selected commercial, industrial and cost recovery of eleven DSM programs, including one peak-shaving program and ten energy efficiency programs.community locations throughout its Virginia service territory. Virginia Power plansproposed to use DSM, alongconstruct and operate the Company-owned facilities in two phases, with its traditionalPhase I (up to 10 MW) from the date of approval through the end of 2013 and renewable supply-side resources,Phase II (up to meet its projected load growth over20 MW)
from the next 15 years. The DSM programs providebeginning of 2014 to the first steps toward achieving Virginia’s goalend of reducing, by 2022, the electric energy consumption2015. Virginia Power did not seek a rate adjustment clause for Phase I facilities with this filing; Phase I costs will be recovered as part of base rates in a future biennial review. Virginia Power’s retail customers by ten percent of what was consumed in 2006. Power indicated that it may seek a rate adjustment clause at a future time for Phase II costs.
In March 2010,November 2012, the Virginia Commission approved the recoveryvoluntary solar distributed generation demonstration program for Company-owned solar distributed generation facilities subject to a total cost cap of approximately $28$80 million for five of the DSM programs through initiation of Riders C1(including capital, financing, and C2, effectiveoperation and maintenance costs) which can be increased subject to future application based upon program experience, results, and data.
In May 1, 2010. With respect to the other six DSM programs for which approval was sought,2012, Virginia Power filed with the Virginia Commission made a finding that they were not inpetition to implement a special tariff for a combined 3 MW of customer-owned solar distributed generation facilities. Under the public interest at that time, but allowedproposed tariff, Rate Schedule SP, Virginia Power would purchase 100% of the opportunityenergy output from these facilities, including all environmental attributes and associated renewable energy credits, at a fixed price of $0.15 per kWh for further evaluationfive years. As proposed, the costs 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 revenue requirements included in Riders C1 and C2 customer rates currently in effect. In February 2011, an evidentiary hearing was held bypurchases under Rate Schedule SP would not be recovered from all customers. Following comments, the Virginia Commission onissued an order in November 2012 setting this matter for public hearing in February 2013. This case is pending.
Electric Transmission Projects
Portions of the Mt. Storm-to-Doubs line and certain associated facilities are approaching 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, 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. In September 2011, the Virginia Commission approved Virginia Power’s updateapplication to rebuild its portion of Riders C1 and C2.the Mt. Storm-to-Doubs line. The approval of the West Virginia Commission was not required. Subject to applicable state and federal regulatory approvals, Virginia Power’s portion of the rebuild project is requiredexpected to issue its orderbe completed by March 30, 2011. Virginia Power plans to seekJune 2015.
In June 2010, the Virginia Commission approval for several DSM programs in 2011.
In connection withauthorized the Bear Gardenconstruction of the Hayes-to-Yorktown line along the proposed eight-mile route utilizing existing easements and Virginia City Hybrid Energy Center projects, 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 Rproperty previously acquired for the April 1, 2011 to March 31, 2012 rate year. Due to the application of accelerated tax depreciation provisionstransmission line right-of-way. The Hayes-to-Yorktown line was placed in the Small Business Jobs Act of 2010, passedservice 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 $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 the rate year ending March 31, 2012 is approximately $200 million, which represents an increase of $46 million over the revenue requirement associated with the Rider S customer rates currently in effect. The ROE included in both rider filings is 12.3%, consistent with the terms of the Virginia Settlement Approval Order. December 2012.
In July 2010, the Virginia Commission issued
orders with respectauthorized Virginia Power to Riders R and S, which adopted a placeholder ROE of 11.3% (not includingconstruct the 100 basis point statutory enhancement) for use until the ROE is determined in the context of Virginia Power’s upcoming biennial review. Evidentiary hearings were held by the Virginia Commission on Riders R and S in December and November 2010, respectively.Radnor Heights Project. The Virginia Commission is required to issue its orders onstated that these proceedingslines and substation must be constructed and in service by MarchJune 30, 2011.
With respect to Virginia Power’s costs of transmission service, in June 2010, the Virginia Commission approved Virginia Power’s annual update to Rider T which was effective September 1, 2010, reflecting the revenue requirement of approximately $338 million recommended by the Virginia Commission Staff2012, and agreed to by Virginia Power. The $338 million revenue requirement reflects an increase of approximately $118 million over the previous revenue requirement.
In April 2010,that Virginia Power filed its Virginia fuel factor application with the Virginia Commission. The application requested an annual decrease in fuel expense recovery of approximately $82 millioncould apply to extend this date for the period July 1, 2010 through June 30, 2011. The proposed fuel factor went into effect on July 1, 2010 on an interim basis. An evidentiary hearing on Virginia Power’s application was held in September 2010, and ingood cause shown. In October 2010,2012, the Virginia Commission issued its finalan order approvingextending this construction and the reductionin-service date to July 31, 2013.
In January 2012, the Virginia Commission authorized the replacement at higher voltage of approximately 43 miles of existing transmission lines between the Dooms and Bremo substations. The Dooms-to-Bremo line is expected to be completed by May 2014.
In December 2011, Virginia Power submitted an application to the Virginia Commission for approval of the Waxpool-Brambleton-BECO line. This project is required to provide requested service to
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Combined Notes to Consolidated Financial Statements, Continued
a new data center campus in Loudoun County, Virginia. In December 2012, PJM authorized the Waxpool-Brambleton-BECO line as part of the 2012 RTEP and the Virginia Power’s fuel factor as proposed in its application.Commission authorized construction of the line. In January 2013, a notice of appeal was filed with the Supreme Court of Virginia by a private party regarding the December 2012 Order. Subject to the receipt of applicable state and federal regulatory approvals, the Waxpool-Brambleton-BECO line is expected to be completed by November 2013.
IfIn June 2012, Virginia Power requested Virginia Commission approval of the Surry-to-Skiffes Creek-to-Whealton lines. Subject to the receipt of applicable state and federal regulatory approvals, the Surry-to-Skiffes Creek-to-Whealton lines are expected to be completed by May 2015. Virginia Power also presented for the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s upcoming biennial review and rate adjustment clause filings, differ materiallyconsideration an approximately 37 mile alternate route for the 500 kV line from Virginia Power’s expectations,existing Chickahominy Substation to the proposed Skiffes Creek Switching Station.
In August 2012, Virginia Power requested Virginia Commission approval of the Harrisonburg-to-Endless Caverns line. In December 2012, the Virginia Commission authorized construction of the new line. Subject to the receipt of applicable state and federal regulatory approvals, the Harrisonburg-to-Endless Caverns line is expected to be completed by May 2015.
In November 2012, Virginia Power submitted an application to the Virginia Commission for approval to rebuild the Dooms-to-Lexington line in Virginia. Portions of the Dooms-to-Lexington line and certain associated facilities are approaching 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 as part of the 2012 RTEP to rebuild the 39 mile line in Rockbridge and Augusta Counties, Virginia. Subject to applicable state and federal regulatory approvals, the rebuild project is expected to be completed by May 2016.
North Anna Power Station
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. However, Virginia Power has not yet committed to building a new nuclear unit at North Anna and continues to evaluate its options regarding a new nuclear unit.
If Virginia Power decides to build a new unit, it could adverselymust first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power has applied for and continues to pursue the COL from the NRC. Based on the current NRC schedule, the COL is expected no earlier than late 2015. Virginia Power also continues to pursue engineering and preliminary site development work, in addition to holding an Early Site Permit. In December 2011, Virginia Power acquired ODEC’s interest in the project, thereby terminating ODEC’s involvement in the development of a potential third unit at North Anna. In January 2013, the NRC approved the transfer of ODEC’s interest in the Early Site Permit to Virginia Power.
The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the ASLB of the NRC permitted BREDL to intervene in the proceeding. In April 2011, BREDL’s then last remaining contention was dismissed by the ASLB, and following a decision by the NRC in June 2012, subsequently resulted in termination of the contested portion of the proceed-
ing. In September 2011, BREDL submitted a new proposed contention seeking to litigate issues related to the August 2011 Mineral, Virginia earthquake. In October 2011, the ASLB granted a motion filed by Virginia Power, with the consent of BREDL and the NRC staff to hold any ruling on this proposed contention in abeyance until Virginia Power completes an assessment of this earthquake. The NRC’s June 2012 decision referred this new proposed contention to the ASLB to consider whether the contested portion of the proceeding should be reopened. In July 2012, the ASLB granted BREDL a period of 60 days to submit a motion to reopen the proceeding from the time Virginia Power informs the NRC and parties that its seismic assessment is complete.
In addition, in June 2012, BREDL filed a petition with the NRC seeking to suspend the COL proceeding based on a June 2012 ruling of the U.S. Court of Appeals for the District of Columbia Circuit reversing and remanding a 2010 NRC rulemaking that generically assessed the environmental impacts of spent fuel storage. Virginia Power opposed the petition. In July 2012, BREDL filed a motion with the NRC to reopen the contested portion of the COL proceeding to admit a contention pertaining to the same subject. Substantially identical suspension petitions and contentions were filed by various intervenor groups in other licensing proceedings pending before the NRC. In August 2012, the NRC issued a memorandum and order applicable to all pending licensing proceedings, including the North Anna COL proceeding. The NRC indicated that final licenses would not be issued until the issues raised in the court’s decision had been addressed. The NRC indicated that this determination extends only to final license issuance and that all licensing reviews and proceedings should continue to move forward. The NRC also directed that pending contentions on the topic be held in abeyance pending further NRC order. The NRC’s August 2012 decision is not expected to affect its resultsthe schedule for issuance of operations, financial conditionthe COL.
No other persons have sought to intervene in the proceeding. If a new contention is not admitted, the mandatory NRC hearing will be uncontested with respect to other issues. Virginia Power continues to pursue various environmental permits that would be needed to support future construction and cash flows.operation of a third nuclear unit at North Anna.
North Carolina Regulation
In December 2011, the North Carolina Commission issued an order approving a settlement agreement among Virginia Power, the Public Staff of the North Carolina Commission and other interested parties in Virginia Power’s fuel case for its North Carolina base rates have been subject toservice territory. The settlement agreement provided for a five-year base rate moratorium,$36 million increase in Virginia Power’s fuel revenues for one year, effective as of April 2005. Fuel rates continued to be subject to annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveriesJanuary 1, 2012, including approximately $13 million in under recovery of fuel costs.expenses for the previous fuel period.
In February 2010, in preparation for the end of the five-year base rate moratorium,March 2012, Virginia Power filed an application with the North Carolina Commission to 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. non-fuel revenues by approximately $64 million, with January 1, 2013 as the proposed effective date for the permanent rate revision.
In August 2010,2012, Virginia Power filed its annual fuel expense recovery 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,testimony with the North Carolina Commission issued the North Carolina Settlement Approval Order. The North Carolina Settlement Approval Order authorizes an increase in base revenuesrequesting a total annual fuel revenue decrease of approximately $8$27 million from the fuel and fuel-related costs currently in effect. Virginia Power’s filing also sought to implement a one-year decrease in combined fuel revenues of approximately $32 million when compared to revenues produced fromtemporary voluntary rider, Rider A1, effective
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current rates. November 1, 2012 to December 31, 2012, to reduce projected over-collection of fuel expense in the second half of 2012.
In addition,August 2012 and October 2012, Virginia Power filed supplemental testimony in the base rate proceeding which had the cumulative effect of updating Virginia Power’s requested overall base non-fuel revenue increase to $53 million. In September 2012, the North Carolina Settlement Approval Order permitsCommission staff filed testimony recommending a non-fuel revenue increase of $24 million. In October 2012, the recovery through fuelNorth Carolina Commission issued a public notice stating that Virginia Power would begin billing under its proposed rates of 85% of the net energy costs of power purchases from both PJM and other wholesale suppliers and from the non-utility generatorsbeginning November 1, 2012 on an interim basis, subject to economic dispatch that do not provide actual cost data. Therefund with interest.
In December 2012, the North Carolina Settlement Approval Order authorizesCommission approved a $36 million increase in Virginia Power’s annual non-fuel base revenues based on an authorized ROE of 10.7%10.2%, and a capital structure composed$14 million decrease in annual base fuel revenues for a combined total base revenue increase of 49% long-term debt and 51% common equity. The new base and fuel rates$22 million. These rate changes became effective on January 1, 2011.2013 and are being appealed to the North Carolina Supreme Court by multiple parties. In December 2012, Virginia Power established net regulatory assets of $17 million to be recovered over five to ten years in connection with these new rates.
Also, in December 2012, the North Carolina Commission approved a $17 million decrease in Virginia Power’s annual non-base fuel Experience Modification Factor revenues. The rate decrease is the result of the Commission’s approval of the Fuel-Related Stipulation of Settlement between the Public Staff and Virginia Power. The rate change was approved by the Commission after review of Virginia Power’s fuel expenses during the 12-month period ended June 30, 2012, and represents changes experienced by Virginia Power with respect to its reasonable costs of fuel and fuel component of purchased power.
Ohio and West Virginia Regulation
PIR Program
In March 2011, East Ohio filed a request with the fourth quarterOhio Commission to accelerate the PIR program by nearly doubling its PIR spending to more than $200 million annually. East Ohio identified 1,450 miles of 2008,pipeline that need to be replaced, in addition to the pipeline originally identified in the PIR project scope. East Ohio plans to accelerate the pace of the program by investing more resources in its infrastructure in the near term, in an effort to promote ongoing public safety and reduce operating costs over the longer term. In August 2011, the Ohio Commission approved an approximately $41 million annual revenue increase forthe stipulation by East Ohio, and a return on rate base that incorporates an ROEthe Staff of 10.38%. These changes were reflected in revised base rates commencing December 22, 2008.
In October 2008, the Ohio Commission approvedand other interested parties in East Ohio’s accelerated PIR proceeding. The stipulation provides for an increase in annual PIR capital investment from the current level of approximately $120 million stepping up to approximately $160 million by 2013. In addition, the stipulation provides for cost recovery for an initialover a five-year period commencing upon the approval of East Ohio’s 25-year PIR program to replace approximately 20% of its 21,000-mile pipeline system. the Ohio Commission.
In August 2010,February 2012, East Ohio filed its second annualsubmitted an application with the Ohio Commission to adjust the cost recovery charge for costs associated with itsPIR investments for the six months ended December 31, 2011. The filing was made in accordance with changes to the PIR program for actual costsapproved by the Ohio Commission in August 2011 and effects a return on investments made throughtransition from a fiscal year ending June 30 2010.to a calendar year for annual filings thereafter. The application reflectedappli-
cation includes total gross plant investment for the six-month July 1-December 31, 2011 transition period of $73 million, cumulative gross plant investment of $362 million, and a revenue requirement of approximately $28$47 million. In November 2010, the Ohio Commission approved a settlement agreement filedA stipulation was submitted by East Ohio, and the Staff of the Ohio Commission reflectingand the Ohio Consumers’ Counsel that supports the rates filed by East Ohio. The Ohio Commission issued an order approving the stipulation in April 2012.
In November 2012, East Ohio filed a revenue requirementnotice to adjust the PIR Cost Recovery Charge for 2012 costs. East Ohio expects to file its application to adjust the PIR Recovery Charge in the first quarter of approximately $27 million. Other interested parties to the case neither supported nor objected to the settlement agreement.2013.
PIPP Plus Program
Under the Ohio PIPP Plus 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 would be in effect. The PIPP 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 reducessets the customer’s monthly payments from 10% toat 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.
In July 2012, the Ohio Commission approved East Ohio’s annual update of the PIPP Rider, which reflects the refund of an over-recovery of accumulated arrearages of approximately $70 million over the next two years and recovery of projected deferred program costs of approximately $104 million for the 12-month period from April 2012 to March 2013.
UEX Rider
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 the PIPP Plus.Plus Program. The UEX
Rider is adjusted annually to achieve dollar-for-dollar recovery of East Ohio’s actual write-offs of uncollectable amounts.
In 2010,July 2012, the Ohio Commission approved East Ohio deferred approximately $55 millionOhio’s annual update of the UEX Rider, which reflects the elimination of accumulated unrecovered bad debt expense of approximately $1 million as of March 31, 2012, and recovery of prospective bad debt expense projected to total approximately $23 million for the 12-month period from April 2012 to March 2013.
House Bill 95
Ohio enacted utility reform legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery throughfrom ratepayers in the UEX Rider.future. In December 2011, East Ohio filed an application requesting authority to implement a capital expenditure program under the new law, which, if approved, would enable East Ohio to defer as a regulatory asset carrying costs, depreciation and property tax associated with approximately $95 million in capital expenditures incurred between October
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2011 and December 2012 for assets placed in service but not yet reflected in rates. The Ohio Commission approved East Ohio’s application in December 2012.
In October 2008, HopeDecember 2012, East Ohio filed an application requesting authority to implement a request with the West Virginia Commissioncapital expenditure program 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 $342013 capital expenditures totaling $93 million, annually. In November 2009, the West Virginia Commission authorized an approximately $9 million increase in base rates. In June 2010, the West Virginia Commission authorized an additional base rate increase of less than $1 million to correct a miscalculation of rates attachedsubject to the November 2009 order.provisions approved for the initial application. This case is pending.
Federal Regulation
FERC—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 and Cove Point. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.
In May 2005,2011, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective July 1, 2011. In June 2011, FERC accepted a July 1, 2011 effective date for all proposed rates but two, for which the effective date was suspended from July 1 to December 1, 2011. In April 2012, Cove Point filed a stipulation and agreement among Cove Point, FERC trial staff and the other active parties in the rate case resolving all issues set for hearing by FERC and establishing the mechanism for operational purchases of LNG. In July 2012, FERC issued an order findingapproving the stipulation and agreement, including the settlement rates that PJM’s existing transmission service rate design may not be just and reasonable, and ordered an investigation and hearings onare effective April 1, 2012. The settlement was considered final in August 2012. Pursuant to 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 the issue of existing facilities back to FERC for further proceedings. Although Dominion and Virginia Power cannot predict the outcometerms of the FERC proceedings on remand, the impactsettlement, future operational purchases of any PJM rate design changes on the Companies’ results of operations is not expected to be material.
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
In July 2008, Virginia Power filed an application with FERC requesting a revision to its revenue 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 1.5% for four of the projects (including the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line) and an incentive of 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, 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 establish 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 RPM Buyers filed a complaint with 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. In November 2009, the Court transferred the appeal to the Court of Appeals for the District 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.
Dominion and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion and Virginia Power employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. Dominion and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new 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 based on actual field conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power is evaluating its transmission facilities for any discrepancies between design and actual field conditions.
In addition, NERC has requested the industry to increase the number of assets subject to NERC reliability standards that are designated as critical assets, including cyber security assets. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above NERC requirements and initiatives, such expensesLNG are not expected to significantly affect Cove Point’s net results of operations.
Dominion Transmission Rates
In December 2007, DTI Cove Point and the IOGA entered intosettling customers will be subject to a settlement agreement on DTI’s gathering and processing rates, which DTI and IOGA agreed in May 2010 to extendrate moratorium through December 31, 2014. DTI, at2016. Cove Point is required to file its option, may electnext rate case in 2016 with rates to extend the agreement for an additional year through December 31, 2015. The settlement extension 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. DTI will file the negotiated rates associated with the agreement extension with FERC in December 2011.be effective January 1, 2017.
NOTE 15.14. ASSET RETIREMENT OBLIGATIONS
AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of Dominion’s and Virginia Power’s long-lived assets. Dominion’s and Virginia Power’s AROs are primarily associated with the decommissioning of their nuclear generation facilities. In addition, Dominion’s AROs include plugging and abandonment of gas and oil wells, interim retirements of natural gas gathering, transmission, distribution and storage pipeline components, and the future abatement of asbestos expected to be disturbed in the Companies’ generation facilities.
The Companies have also identified, but not recognized, AROs related to retirement of Dominion’s LNG facility, Dominion’s gas storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in the Companies’ generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be
extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to
Combined Notes to Consolidated Financial Statements, Continued
identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 20092011 and 20102012 were as follows:
Amount | Amount | |||||||
(millions) | ||||||||
Dominion | ||||||||
AROs at December 31, 2008(1) | $ | 1,822 | ||||||
AROs at December 31, 2010(1) | $ | 1,591 | ||||||
Obligations incurred during the period | 14 | 16 | ||||||
Obligations settled during the period | (13 | ) | (16 | ) | ||||
Revisions in estimated cash flows(2) | (304 | ) | (277 | ) | ||||
Accretion | 88 | 84 | ||||||
Other | 7 | |||||||
AROs at December 31, 2009(1) | $ | 1,614 | ||||||
AROs at December 31, 2011(1) | $ | 1,398 | ||||||
Obligations incurred during the period | 1 | 24 | ||||||
Obligations settled during the period | (9 | ) | (13 | ) | ||||
Revisions in estimated cash flows | 5 | |||||||
Revisions in estimated cash flows(3) | 242 | |||||||
Accretion | 85 | 77 | ||||||
Obligations relieved due to sale of Appalachian E&P operations | (105 | ) | ||||||
AROs at December 31, 2010(1) | $ | 1,591 | ||||||
Other | (23 | ) | ||||||
AROs at December 31, 2012(1) | $ | 1,705 | ||||||
Virginia Power | ||||||||
AROs at December 31, 2008(3) | $ | 717 | ||||||
AROs at December 31, 2010(4) | $ | 672 | ||||||
Obligations incurred during the period | 10 | |||||||
Obligations settled during the period | (3 | ) | ||||||
Revisions in estimated cash flows(2) | (115 | ) | (90 | ) | ||||
Accretion | 35 | 36 | ||||||
AROs at December 31, 2009(3) | $ | 637 | ||||||
AROs at December 31, 2011(4) | $ | 625 | ||||||
Obligations incurred during the period | 18 | |||||||
Obligations settled during the period | (1 | ) | ||||||
Revisions in estimated cash flows(5) | 41 | |||||||
Accretion | 35 | 34 | ||||||
AROs at December 31, 2010(3) | $ | 672 | ||||||
Other | (12 | ) | ||||||
AROs at December 31, 2012 | $ | 705 |
(1) | Includes |
(2) | Primarily reflects |
(3) | Primarily reflects the accelerated timing of the decommissioning of Kewaunee to begin in 2013. |
(4) | Includes |
(5) | Primarily reflects the effect of higher anticipated nuclear decommissioning costs. |
Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 20102012 and 2009,2011, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $2.9$3.3 billion and $2.6$3.0 billion, respectively. At December 31, 20102012 and 2009,2011, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.3$1.5 billion and $1.2$1.4 billion, respectively.
NOTE 16.15. VARIABLE INTEREST ENTITIES
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant
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variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
Virginia Power has long-term power and capacity contracts with four non-utility generators with an aggregate summer generation capacity of approximately 974870 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $1.5$1.1 billion as of December 31, 2010.2012. Virginia Power paid $213$214 million, $210$211 million, and $205$213 million for electric capacity and $164$83 million, $117$125 million, and $196$164 million for electric energy to these entities for the years ended December 31, 2012, 2011 and 2010, 2009 and 2008, respectively.
As discussed in Note 25, DCI held an investment in the subordinated notes of a third-party CDO entity. Dominion previously concluded that the CDO entity was a VIE and that DCI was the primary beneficiary of the CDO entity, which Dominion consolidated at December 31, 2007. In March 2008, Dominion entered into an agreement to sell its remaining interest in the subordinated notes effectively eliminating the variability of its interest, and therefore deconsolidated the CDO entity as of March 31, 2008.
Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $465$328 million, $416$389 million, and $397$465 million for the years ended December 31, 2010, 20092012, 2011 and 2008,2010, respectively. Virginia Power determined that it is not the most closely associated entity with DRS and therefore not the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power. Virginia Power has no obligation to absorb more than its allocated share of DRS costs.
Dominion leases the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. Dominion makes annual lease payments of approximately $53 million. The lease expires in 2013 and, at that time, Dominion may renew the lease on terms mutually agreeable to Dominion and Juniper based on original project costs and current market conditions; purchase Fairless for approximately $923 million or sell Fairless, on behalf of Juniper, 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 the 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. Dominion expects to purchase Fairless when the lease expires in the third quarter of 2013.
Juniper was formed in 2003 as a limited partnership and was organized for the purpose of acquiring and constructing a number of assets for lease. Such assets were financed with proceeds from the issuance of bank debt, privately placed long-term debt and partnership capital received from Juniper’s general and limited
partners. Dominion has no voting equity interest in Juniper. Because Juniper had been subject to the business scope exception, Dominion was not required to evaluate whether Juniper was a VIE prior to October 2011.
Through September 30, 2011, Juniper held various power plant leases, including Fairless. In October 2011, the last lease other than Fairless expired and the related asset was sold by Juniper. With Fairless being its sole remaining asset, Juniper no longer qualified as a business as of October 2011, which required that Dominion determine whether Juniper is a VIE. Dominion concluded Juniper is a VIE because the entity’s capitalization is insufficient to support its operations, the power to direct the most significant activities of the entity is not held by the equity holders, and Dominion, through its residual value guarantee discussed above, guarantees a portion of the residual value of Fairless. The activities that most significantly impact Juniper’s economic performance relate to the operation of Fairless. The decisions related to the operations of Fairless are made by Dominion and as such, Dominion is considered the primary beneficiary.
NOTE 17.16. SHORT-TERM DEBTAND CREDIT AGREEMENTS
Dominion and Virginia Power use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties. Dominion and Virginia Power replaced certain of their existing credit facilities in September 2010, as noted below.
99
Combined Notes to Consolidated Financial Statements, Continued
DOMINION
Commercial paper bank loans, and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:
At December 31, | Facility Limit | Out- standing Commercial Paper | Out- standing Bank Borrowings | Out- standing Letters of Credit | Facility Capacity Available | |||||||||||||||
(millions) | ||||||||||||||||||||
2010 | ||||||||||||||||||||
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 | (6) | $ | — | $ | 136 | $ | 1,978 | |||||||||
2009 | ||||||||||||||||||||
Five-year joint revolving credit facility(3) | $ | 2,872 | $ | 442 | $ | — | $ | 153 | $ | 2,277 | ||||||||||
Five-year Dominion credit facility(4) | 1,700 | 353 | 500 | 19 | 828 | |||||||||||||||
Five-year Dominion bilateral facility(5) | 200 | — | — | 32 | 168 | |||||||||||||||
Total | $ | 4,772 | $ | 795 | (6) | $ | 500 | (7) | $ | 204 | $ | 3,273 |
At December 31, | Facility Limit | Outstanding Commercial Paper | Outstanding Letters of Credit | Facility Capacity Available | ||||||||||||
(millions) | ||||||||||||||||
2012 | ||||||||||||||||
Joint revolving credit facility(1) | $ | 3,000 | $ | 2,412 | $ | — | $ | 588 | ||||||||
Joint revolving credit facility(2) | 500 | — | 26 | 474 | ||||||||||||
Total | $ | 3,500 | $ | 2,412 | (3) | $ | 26 | $ | 1,062 | |||||||
2011 | ||||||||||||||||
Joint revolving credit facility(1) | $ | 3,000 | $ | 1,814 | $ | — | $ | 1,186 | ||||||||
Joint revolving credit facility(2) | 500 | — | 36 | 464 | ||||||||||||
Total | $ | 3,500 | $ | 1,814 | (3) | $ | 36 | $ | 1,650 |
(1) |
(2) |
(3) |
The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were |
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 and Virginia Power and for other general corporate purposes.
Virginia Power’s share of commercial paper bank loans, and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion, were as follows:
At December 31, | Facility Sub-limit | Outstanding Commercial Paper | Outstanding Letters of Credit | Facility Capacity Available | ||||||||||||
(millions) | ||||||||||||||||
2010 | ||||||||||||||||
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 |
At December 31, | Facility Sub-limit | Outstanding Commercial Paper | Outstanding Letters of Credit | Facility Sub-Limit Capacity Available | ||||||||||||
(millions) | ||||||||||||||||
2012 | ||||||||||||||||
Joint revolving credit facility(1) | $ | 1,000 | $ | 992 | $ | — | $ | 8 | ||||||||
Joint revolving credit facility(2) | 250 | — | 2 | 248 | ||||||||||||
Total | $ | 1,250 | $ | 992 | (3) | $ | 2 | $ | 256 | |||||||
2011 | ||||||||||||||||
Joint revolving credit facility(1) | $ | 1,000 | $ | 894 | $ | — | $ | 106 | ||||||||
Joint revolving credit facility(2) | 250 | — | 15 | 235 | ||||||||||||
Total | $ | 1,250 | $ | 894 | (3) | $ | 15 | $ | 341 |
(1) |
(2) |
(3) | The weighted-average interest |
At December 31, 2009, Virginia Power had $442 million of commercial paper and $104 million of letters of credit outstanding under a five-year, $2.8 billion joint credit facility with Dominion and the weighted-average interest rate of its outstanding commercial paper was 0.28%. This credit facility was entered into in February 2006 and terminated in September 2010. This credit facility was used to support bank borrowings, commercial paper and letter of credit issuances.
In addition to the credit facility commitments mentioned above, Virginia Power also has a three-year $120 million credit facility thatfacility. Effective September 2012, the maturity date was entered into inextended from September 2010. The2016 to September 2017. This facility which terminates in September 2013, supports certain tax-exempt financings of Virginia Power.
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Combined Notes to Consolidated Financial Statements, Continued
NOTE 18.17. LONG-TERM DEBT
At December 31, | 2010 Weighted- average Coupon(1) | 2010 | 2009 | 2012 Weighted- average Coupon(1) | 2012 | 2011 | ||||||||||||||||||
(millions, except percentages) | ||||||||||||||||||||||||
Virginia Electric and Power Company(2): | ||||||||||||||||||||||||
Virginia Electric and Power Company: | ||||||||||||||||||||||||
Unsecured Senior Notes: | ||||||||||||||||||||||||
4.5% to 5.25%, due 2010 to 2015 | 5.01 | % | $ | 1,200 | $ | 1,430 | ||||||||||||||||||
3.45% to 8.875%, due 2016 to 2038 | 6.12 | % | 4,694 | 4,408 | ||||||||||||||||||||
Tax-Exempt Financings:(3) | ||||||||||||||||||||||||
4.75% to 8.625%, due 2012 to 2017 | 5.50 | % | $ | 1,706 | $ | 2,321 | ||||||||||||||||||
2.95% to 8.875%, due 2018 to 2038 | 5.83 | % | 4,008 | 3,558 | ||||||||||||||||||||
Tax-Exempt Financings(2): | ||||||||||||||||||||||||
Variable rates, due 2016 to 2041 | 1.25 | % | 219 | 119 | 1.14 | % | 454 | 454 | ||||||||||||||||
7.65%, due 2010 | — | 1 | ||||||||||||||||||||||
1.375% to 6.5%, due 2017 to 2040 | 4.25 | % | 608 | 503 | ||||||||||||||||||||
1.5% to 6.5%, due 2017 to 2040 | 3.65 | % | 508 | 533 | ||||||||||||||||||||
Virginia Electric and Power Company total principal | $ | 6,721 | $ | 6,461 | $ | 6,676 | $ | 6,866 | ||||||||||||||||
Securities due within one year(4) | 7.74 | % | (15 | ) | (245 | ) | ||||||||||||||||||
Securities due within one year | 4.88 | % | (418 | ) | (616 | ) | ||||||||||||||||||
Unamortized discount and premium, net | (4 | ) | (3 | ) | (7 | ) | (4 | ) | ||||||||||||||||
Virginia Electric and Power Company total long-term debt | $ | 6,702 | $ | 6,213 | $ | 6,251 | $ | 6,246 | ||||||||||||||||
Dominion Resources, Inc.: | ||||||||||||||||||||||||
Unsecured Senior Notes: | ||||||||||||||||||||||||
2.25% to 8.125%, due 2010 to 2015 | 5.14 | % | $ | 1,901 | $ | 2,029 | ||||||||||||||||||
5.2% to 8.875%, due 2016 to 2038(5) | 6.34 | % | 4,193 | 4,193 | ||||||||||||||||||||
Variable rate, due 2010 | — | 300 | ||||||||||||||||||||||
Unsecured Convertible Senior Notes, 2.125%, due 2023(6) | 202 | 202 | ||||||||||||||||||||||
Variable rate, due 2013 | 0.41 | % | $ | 400 | $ | — | ||||||||||||||||||
1.4% to 7.195%, due 2012 to 2017 | 3.72 | % | 3,041 | 3,545 | ||||||||||||||||||||
2.75% to 8.875%, due 2018 to 2042(3) | 5.71 | % | 5,099 | 4,399 | ||||||||||||||||||||
Unsecured Convertible Senior Notes, 2.125%, due 2023(4) | 82 | 143 | ||||||||||||||||||||||
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031 | 7.85 | % | 268 | 268 | 7.85 | % | 268 | 268 | ||||||||||||||||
Enhanced Junior Subordinated Notes, 6.3% to 8.375%, due 2064 and 2066 | 7.51 | % | 1,469 | 1,485 | ||||||||||||||||||||
Unsecured Debentures and Senior Notes(7): | ||||||||||||||||||||||||
5.0% to 6.85%, due 2010 to 2014 | 5.58 | % | 1,091 | 1,291 | ||||||||||||||||||||
Enhanced Junior Subordinated Notes: | ||||||||||||||||||||||||
7.5% and 8.375%, due 2064 and 2066 | 8.11 | % | 985 | 985 | ||||||||||||||||||||
Variable rate, due 2066(5) | 2.77 | % | 380 | 468 | ||||||||||||||||||||
Unsecured Debentures and Senior Notes(6): | ||||||||||||||||||||||||
5.0% and 6.625%, due 2013 and 2014 | 5.06 | % | 622 | 622 | ||||||||||||||||||||
6.8% and 6.875%, due 2026 and 2027 | 6.81 | % | 89 | 89 | 6.81 | % | 89 | 89 | ||||||||||||||||
Dominion Energy, Inc.(8): | ||||||||||||||||||||||||
Secured Senior Note, 7.33%, due 2020(9) | 171 | 183 | ||||||||||||||||||||||
Tax-Exempt Financings, 5.0% and 5.75%, due 2033 to 2042 | 5.30 | % | 124 | 124 | ||||||||||||||||||||
Dominion Energy, Inc.: | ||||||||||||||||||||||||
Secured Senior Notes: | ||||||||||||||||||||||||
5.03% to 5.78%, due 2013(7) | 5.07 | % | 842 | 842 | ||||||||||||||||||||
7.33%, due 2020(8) | 145 | 159 | ||||||||||||||||||||||
Tax-Exempt Financings(9): | ||||||||||||||||||||||||
2.25% to 5.75%, due 2033 to 2042 | 3.34 | % | 284 | 284 | ||||||||||||||||||||
Variable rate, due 2041 | 1.16 | % | 75 | 75 | ||||||||||||||||||||
Virginia Electric and Power Company total principal (from above) | 6,721 | 6,461 | 6,676 | 6,866 | ||||||||||||||||||||
Dominion Resources, Inc. total principal | $ | 16,229 | $ | 16,625 | $ | 18,988 | $ | 18,745 | ||||||||||||||||
Fair value hedge valuation(10) | 49 | 23 | 93 | 105 | ||||||||||||||||||||
Securities due within one year(11) | 6.35 | % | (497 | ) | (1,137 | ) | 4.53 | % | (2,223 | ) | (1,479 | ) | ||||||||||||
Unamortized discount and premium, net | (23 | ) | (30 | ) | (7 | ) | 23 | |||||||||||||||||
Dominion Resources, Inc. total long-term debt | $ | 15,758 | $ | 15,481 | $ | 16,851 | $ | 17,394 |
(1) | Represents weighted-average coupon rates for debt outstanding as of December 31, |
(2) |
These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. Certain variable rate tax-exempt financings are supported by a $120 million |
At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 and $600 million of Dominion’s 8.875% senior notes due 2019 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015 and January 2014, respectively. |
Convertible into a combination of cash and shares of Dominion’s common stock at any time when the closing price of common stock equals 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter. At the option of holders on December 15, |
In September 2011, the $500 million 6.3% September 2006 hybrids began bearing interest at the three-month LIBOR plus 2.3%, reset quarterly. |
(6) | Represents debt assumed by Dominion from the merger of its former CNG subsidiary. |
Represents debt associated with Kincaid. The debt is non-recourse to Dominion and is secured by the facility’s assets ($ |
(9) | Includes debt issued by the Massachusetts Development Finance Agency on behalf of Brayton Point. Dominion announced in the third quarter of 2012 that it was pursuing the sale of Brayton Point. |
(10) | Represents the valuation of certain fair value hedges associated with Dominion’s |
(11) | Includes |
101 |
Combined Notes to Consolidated Financial Statements, Continued
Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2010,2012, were as follows:
2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | 2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | Total | |||||||||||||||||||||||||||||||||||||||||||
(millions, except percentages) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Virginia Power | $ | 15 | $ | 616 | $ | 418 | $ | 17 | $ | 219 | $ | 5,436 | $ | 6,721 | $ | 418 | $ | 17 | $ | 211 | $ | 476 | $ | 679 | $ | 4,875 | $ | 6,676 | ||||||||||||||||||||||||||||
Weighted-average Coupon | 7.74 | % | 5.17 | % | 4.88 | % | 7.73 | % | 5.43 | % | 5.69 | % | 4.88 | % | 7.73 | % | 5.39 | % | 5.27 | % | 5.44 | % | 5.26 | % | ||||||||||||||||||||||||||||||||
Dominion | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Secured Senior Notes | $ | 13 | $ | 13 | $ | 11 | $ | 15 | $ | 18 | $ | 101 | $ | 171 | $ | 852 | $ | 15 | $ | 18 | $ | 20 | $ | 22 | $ | 60 | $ | 987 | ||||||||||||||||||||||||||||
Unsecured Senior Notes | 484 | 1,470 | 690 | 665 | 960 | 9,101 | 13,370 | 1,090 | 1,065 | 960 | 1,351 | 1,303 | 9,278 | 15,047 | ||||||||||||||||||||||||||||||||||||||||||
Tax-Exempt Financings | — | — | — | — | 8 | 943 | 951 | — | — | — | 19 | 75 | 1,227 | 1,321 | ||||||||||||||||||||||||||||||||||||||||||
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts | — | — | — | — | — | 268 | 268 | 258 | — | — | — | — | 10 | 268 | ||||||||||||||||||||||||||||||||||||||||||
Enhanced Junior Subordinated Notes | — | — | — | — | — | 1,469 | 1,469 | — | — | — | — | — | 1,365 | 1,365 | ||||||||||||||||||||||||||||||||||||||||||
Total | $ | 497 | $ | 1,483 | $ | 701 | $ | 680 | $ | 986 | $ | 11,882 | $ | 16,229 | $ | 2,200 | $ | 1,080 | $ | 978 | $ | 1,390 | $ | 1,400 | $ | 11,940 | $ | 18,988 | ||||||||||||||||||||||||||||
Weighted-average Coupon | 6.35 | % | 5.62 | % | 5.01 | % | 5.27 | % | 4.52 | % | 6.15 | % | 4.53 | % | 3.99 | % | 4.50 | % | 4.27 | % | 4.60 | % | 5.54 | % |
Dominion’s and Virginia Power’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2010,2012, there were no events of default under these covenants.
In January 2013, Virginia Power issued $250 million of 1.2% and $500 million of 4.0% senior notes that mature in 2018 and 2043, respectively.
Convertible Securities
At December 31, 2010,2012, Dominion had $202$82 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominion’s common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. At issuance, the notes were valued at a conversion rate of 27.173 shares of common stock per $1,000 principal amount of senior notes, which represented a conversion price of $36.80. The conversion rate is subject to adjustment without limitation upon certain events such as subdivisions, splits, combinations of common stock or the issuance to all common stock holders of certain common stock rights, warrants or options and certain dividend increases. As of December 31, 2010,2012, the conversion rate had been adjusted to 28.503229.3863 shares, primarily due to individual dividend payments above the level paid at issuance. If the outstanding notes as of December 31, 2012 were all converted, it would result in the issuance of approximately 900 thousand additional shares. In December 2012, Dominion’s Board of Directors declared dividends payable March 20, 2013 of 56.25 cents per share of common stock which will increase the conversion rate to 29.5147 effective as of February 26, 2013.
The number of shares included in the denominator of the diluted EPS calculation is calculated as the net shares issuable for the reporting period based upon the average market price for the period. This results in an increase in the average shares outstanding used in the calculation of Dominion’s diluted EPS when the conversion price is lower than the average market price of Dominion’s common stock over the period, and results in no adjustment when the conversion price exceeds the average market price.
The senior notes are convertible by holders into a combination of cash and shares of Dominion’s common stock under any of the following circumstances:
(1) | The closing price of Dominion’s common stock equals 120% of the applicable conversion price ($40.66 as of February 26, |
2013) or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter; |
(2) | The senior notes are called for redemption by Dominion; |
(3) | The occurrence of specified corporate transactions; or |
(4) | The credit rating assigned to the senior notes by Moody’s is below Baa3 and by Standard & Poor’s is below BBB- or the ratings are discontinued for any reason. |
During the first three quarters of 2010, theThe senior notes were not eligible for conversion. However, as of September 30, 2010,conversion during 2012 since the closing price of Dominion’s common stock was equal to $42.24 per share120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days; therefore, the senior notes were eligible for conversion during the fourth quarterdays of 2010.each quarter. During 2010, less than $12012, approximately $61 million of the contingent convertible senior notes were converted by holders. The senior notes were not eligible for conversion during 2009. As of December 31, 2010,2012, the closing price of Dominion’s common stock was not equal to $42.10$40.84 per share or higher for at least 20 out of the last 30 consecutive trading days; therefore, the senior notes are not eligible for conversion during the first quarter of 2011.2013. Beginning in 2007, the notes have been eligible for contingent interest if the average trading price as defined in the indenture equals or exceeds 120% of the principal amount of the senior notes. Holders have the right to require Dominion to purchase these senior notes for cash at 100% of the principal amount plus accrued interest in December 2011, 2013 or 2018, or if Dominion undergoes certain fundamental changes. The senior notes have been callable by Dominion since December 15, 2011.
Junior Subordinated Notes Payable to Affiliated Trusts
In previous years, Dominion and Virginia Power established several subsidiary capital trusts, each as a finance subsidiary of the respective parent company,Dominion, which holdholds 100% of the voting interests. The trusts sold trust preferredcapital securities representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trusts. In exchange for the funds realized from the sale of the trust preferredcapital securities and common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trusts, Dominion and Virginia Power issued various junior subordinated notes. The junior subordinated notes constitute 100% of each capital trust’s assets. Each trust must redeem its trust preferredcapital securities when their respective junior subordinated notes are repaid at maturity or if redeemed prior to maturity.
In May 2008, Virginia Power repaid its $412 million 7.375% unsecured junior subordinated notes and redeemed all 16 million units of the $400 million 7.375% Virginia Power Capital Trust II
102 |
Combined Notes to Consolidated Financial Statements, Continued
preferredIn November 2012, Dominion provided notice of redemption for its $258 million 7.83% unsecured junior subordinated debentures and all 250 thousand units of the $250 million 7.83% Dominion Resources Capital Trust I capital securities due July 30, 2042. TheseDecember 1, 2027. At December 31, 2012, the debentures were included in securities weredue within one year in the Consolidated Balance Sheets. In January 2013, Dominion redeemed the securities at a price of $25$1,019.58 per preferredcapital security plus accrued and unpaid distributions.
The following table provides summary information about the trust preferredcapital securities and junior subordinated notes outstanding as of December 31, 2010:2012:
Date Established | Capital Trusts | Units | Rate | Trust Preferred Securities Amount | Common Securities Amount | Capital Trusts | Units | Rate | Capital Securities Amount | Common Securities Amount | ||||||||||||||||||||||||||
(thousands) | (millions) | (thousands) | (millions) | |||||||||||||||||||||||||||||||||
December 1997 | Dominion Resources Capital Trust I(1) | 250 | 7.83 | % | $ | 250 | $ | 7.7 | Dominion Resources Capital Trust I(1) | 250 | 7.83 | % | $ | 250 | $ | 7.7 | ||||||||||||||||||||
January 2001 | Dominion Resources Capital Trust III(2) | 10 | 8.4 | % | 10 | 0.3 | Dominion Resources Capital Trust III(2) | 10 | 8.4 | 10 | 0.3 |
Junior subordinated notes/debentures held as assets by each capital trust were as follows:
(1) | $258 million—Dominion Resources, Inc. 7.83% Debentures due 12/1/2027. |
(2) | $10 million—Dominion Resources, Inc. 8.4% Debentures due 1/15/2031. |
The following table presents interestInterest charges related to the Companies’Dominion’s junior subordinated notes payable to affiliated trusts:trusts were $21 million for the years ended December 31, 2012, 2011 and 2010.
2010 | 2009 | 2008 | ||||||||||
(millions) | ||||||||||||
Dominion | $ | 21 | $ | 21 | $ | 33 | ||||||
Virginia Power | — | — | $ | 12 |
Distribution payments on the trust preferredcapital securities are considered to be fully and unconditionally guaranteed by the respective parent company that issued the debt instruments held by each trust when all of the related agreements are taken into consideration.Dominion. Each guarantee agreement only provides for the guarantee of distribution payments on the relevant trust preferredcapital securities to the extent that the trust has funds legally and immediately available to make distributions. The trust’s ability to pay amounts when they are due on the trust preferredcapital securities is dependent solely upon the payment of amounts by Dominion when they are due on the junior subordinated notes. Dominion may defer interest payments on the junior subordinated notes on one or more occasions for up to five consecutive years and the related trusts must also defer distributions. If the payment on the junior subordinated notes is deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments.payments, during the deferral period. Also, during any deferral period, Dominion may not make any payments on, redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the junior subordinated notes.
Enhanced Junior Subordinated Notes
In June 2006 and September 2006, Dominion issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids will bear interest at 7.5% per year until June 30, 2016. Thereafter, they will bear interest at the three-month LIBOR plus 2.825%, reset quarterly. TheBeginning September 30, 2011, the September 2006 hybrids will bear interest at 6.3% per year until September 30, 2011. Thereafter, they will bear interest at the three-month LIBOR plus 2.3%, reset quarterly. Previously, interest was fixed at 6.3% per year.
In June 2009, Dominion issued $685 million (including $60 million related to the underwriter’s option to purchase additional
notes to cover over-allotments) of 8.375% June 2009 hybrids. The June 2009 hybrids are listed on the New York Stock ExchangeNYSE under the symbol DRU.
In April 2010, Dominion purchased and cancelled $16 million of the September 2006 hybrids. These purchases were conducted in compliance with the RCCs.
Dominion may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments.payments during the deferral period. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.
Dominion executed RCCs in connection with its issuance of all of the hybrids described above. Under the terms of the RCCs, Dominion covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. In September 2011, Dominion amended the RCCs of the June 2006 hybrids and September 2006 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock issuances from 180 days to 365 days. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.
In both December 2011 and April 2010, Dominion purchased and canceled approximately $16 million of the September 2006 hybrids. In February 2012, Dominion launched a tender offer to purchase up to $150 million of additional September 2006 hybrids. In the first quarter of 2012, Dominion purchased and canceled approximately $86 million of the September 2006 hybrids primarily as a result of this tender offer, which expired in March 2012. In the second quarter of 2012, Dominion purchased and canceled approximately $2 million of the September 2006 hybrids. All purchases were conducted in compliance with the RCC.
From time to time, Dominion may reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity and repurchases in the open market, in privately negotiated transactions, through additional tender offers or otherwise.
NOTE 19.18. PREFERRED STOCK
Dominion is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 20102012 or 2009.2011.
Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference, and had 2.59 million preferred shares issued and outstanding at December 31, 20102012 and 2009.2011. Upon involuntary liquidation,
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Combined Notes to Consolidated Financial Statements, Continued
dissolution or winding-up of Virginia Power, each share would be entitled to receive $100 plus accrued cumulative dividends.
Holders of Virginia Power’s outstanding preferred stock are not entitled to voting rights except under certain provisions of the amended and restated articles of incorporation and related provisions of Virginia law restricting corporate action, upon default in dividends or in special statutory proceedings and as required by Virginia law (such as mergers, consolidations, sales of assets, dissolution and changes in voting rights or priorities of preferred stock).
Presented below are the series of Virginia Power preferred stock that were outstanding as of December 31, 2010:2012:
Dividend | Issued and Outstanding Shares | Entitled Per Share Upon Liquidation | Issued and Outstanding Shares | Entitled Per Share Upon Liquidation | ||||||||||||
(thousands) | (thousands) | |||||||||||||||
$5.00 | 107 | $ | 112.50 | 107 | $ | 112.50 | ||||||||||
4.04 | 13 | 102.27 | 13 | 102.27 | ||||||||||||
4.20 | 15 | 102.50 | 15 | 102.50 | ||||||||||||
4.12 | 32 | 103.73 | 32 | 103.73 | ||||||||||||
4.80 | 73 | 101.00 | 73 | 101.00 | ||||||||||||
7.05 | 500 | 101.06 | (1) | 500 | 100.36 | (1) | ||||||||||
6.98 | 600 | 101.05 | (2) | 600 | 100.35 | (2) | ||||||||||
Flex Money Market Preferred 12/02, Series A | 1,250 | 100.00 | (3) | 1,250 | 100.00 | (3) | ||||||||||
Total | 2,590 | 2,590 |
(1) | Through 7/31/ |
(2) | Through 8/31/ |
(3) | Dividend rate |
NOTE 20.19. SHAREHOLDERS’ EQUITY
Issuance of Common Stock
DOMINION
Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2012, Dominion began issuing new common shares for these direct stock purchase plans.
During 2010,2012, Dominion issued 2.3approximately 6.4 million shares of common stock forthrough various programs. Dominion received cash proceeds of $74 million. The$265 million from the issuance of 5.3 million of such shares issued and cash proceeds received during 2010 were through Dominion Direct,®, employee savings plans, and the exercise of employee stock options.
In February 2010,January 2012, Dominion began purchasing itsfiled a new SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock onthrough an at the open market program. Dominion entered into four separate Sales Agency Agreements to effect sales under the program. However, with proceeds receivedthe exception of issuing approximately $318 million in equity through Dominion Direct® and employee savings plans, rather than having additional newdirect stock purchase and dividend reinvestment plans, converted securities and other employee and director benefit plans, Dominion did not issue common shares issued.stock in 2012.
VIRGINIA POWER
In 2012 and 2011, Virginia Power did not issue any shares of its common stock to Dominion. In 2010, Virginia Power issued 33,013 shares of its common stock to Dominion for approximately $1 billion. The proceeds were used to pay downbillion, for the purpose of retiring short-term demand note borrowings from Dominion.
Shares Reserved for Issuance
At December 31, 2010,2012, Dominion had approximately 5248 million shares reserved and available for issuance for Dominion Direct®, employee stock awards, employee savings plans, director stock compensation plans and contingent convertible senior notes.
Repurchase of Common Stock
In March 2010, Dominion began repurchasing common shares in anticipation of proceeds from the sale of its Appalachian E&P operations. During 2010,2011, Dominion repurchased 21.4approximately 13 million shares of its common stock for approximately $900 million.
On January 28, 2011, Dominion announced that it intends to repurchase between $400$601 million and $700 million of common stock with cash tax savings resulting from the extension of the bonus depreciation allowance discussed in Note 6. In the first quarter of 2011, Dominion began repurchasing shares on the open market, under this program.at an average price of $46.37 per share. Dominion did not repurchase any shares in 2012 and does not plan to repurchase shares during 2013, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization.
Accumulated Other Comprehensive Income (Loss)
Presented in the table below is a summary of AOCI by component:
At December 31, | 2010 | 2009 | ||||||
(millions) | ||||||||
Dominion | ||||||||
Net unrealized gains on derivatives-hedging activities, net of tax of $(27) and $(170) | $ | 51 | $ | 281 | ||||
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(142) and $(97) | 226 | 151 | ||||||
Net unrecognized pension and other postretirement benefit costs, net of tax of $446 and $444 | (607 | ) | (643 | ) | ||||
Total AOCI | $ | (330 | ) | $ | (211 | ) | ||
Virginia Power | ||||||||
Net unrealized gains on derivatives-hedging activities, net of tax of $(2) and $(8) | $ | 4 | $ | 13 | ||||
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(13) and $(9) | 20 | 13 | ||||||
Total AOCI | $ | 24 | $ | 26 |
At December 31, | 2012 | 2011 | ||||||
(millions) | ||||||||
Dominion | ||||||||
Net unrealized losses on derivatives-hedging activities, net of tax of $87 and $48 | $ | (122 | ) | $ | (54 | ) | ||
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(206) and $(154) | 326 | 243 | ||||||
Net unrecognized pension and other postretirement benefit costs, net of tax of $745 and $568 | (1,081 | ) | (799 | ) | ||||
Total AOCI | $ | (877 | ) | $ | (610 | ) | ||
Virginia Power | ||||||||
Net unrealized losses on derivatives-hedging activities, net of tax of $3 and $2 | $ | (6 | ) | $ | (3 | ) | ||
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(19) and $(14) | 31 | 22 | ||||||
Total AOCI | $ | 25 | $ | 19 |
Stock-Based Awards
The 2005 Incentive Compensation Plan permits stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of both plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. At December 31, 2010,2012, approximately 3332 million shares were available for future grants under these plans.
Dominion measures and recognizes compensation expense relating to share-based payment transactions over the vesting
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period based on the fair value of the equity or liability instruments issued. Dominion’s results for the years ended December 31, 2012, 2011 and 2010 2009 and 2008 include $40$25 million, $44$39 million, and $46$40 million, respectively, of compensation costs and $15$8 million, $17$13 million, and $17$15 million, respectively of income tax benefits related to Dominion’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. Benefits ofExcess tax deductions in excess of the compensation cost recognized for stock-based compensation (excess tax benefits)benefits are classified as a financing cash flow. During the years ended December 31, 2010, 20092012, 2011 and 2008,2010, Dominion realized $10 million, $5$2 million, and $7$10 million, respectively, of excess tax benefits from the vesting of restricted stock awards and exercise of stock options.
STOCK OPTIONS
The following table provides a summary of changes in amounts of stock options outstanding as of and for the years ended December 31, 2010, 20092012, 2011 and 2008.2010. No options were granted under any plan in 2010, 20092012, 2011 or 2008.2010.
Shares | Weighted - average Exercise Price | Weighted - average Remaining Contractual Life | Aggregated Intrinsic Value(1) | Shares | Weighted - average Exercise Price | Weighted - average Remaining Contractual Life | Aggregated Intrinsic Value(1) | |||||||||||||||||||||||||
(thousands) | (years) | (millions) | (thousands) | (years) | (millions) | |||||||||||||||||||||||||||
Outstanding and exercisable at December 31, 2007 | 7,021 | $ | 30.46 | |||||||||||||||||||||||||||||
Exercised | (1,458 | ) | $ | 30.20 | $ | 17 | ||||||||||||||||||||||||||
Forfeited/expired | (5 | ) | $ | 28.85 | ||||||||||||||||||||||||||||
Outstanding and exercisable at December 31, 2008 | 5,558 | $ | 30.53 | $ | 30 | |||||||||||||||||||||||||||
Exercised | (1,706 | ) | $ | 28.93 | $ | 10 | ||||||||||||||||||||||||||
Forfeited/expired | (30 | ) | $ | 28.89 | ||||||||||||||||||||||||||||
Outstanding and exercisable at December 31, 2009 | 3,822 | $ | 31.25 | $ | 29 | 3,822 | $ | 31.25 | 29 | |||||||||||||||||||||||
Exercised | (1,983 | ) | $ | 30.81 | $ | 22 | (1,983 | ) | $ | 30.81 | $ | 22 | ||||||||||||||||||||
Forfeited/expired | (29 | ) | $ | 29.84 | (29 | ) | $ | 29.84 | ||||||||||||||||||||||||
Outstanding and exercisable at December 31, 2010 | 1,810 | $ | 31.76 | 1.1 | $ | 20 | 1,810 | $ | 31.76 | $ | 20 | |||||||||||||||||||||
Exercised | (1,174 | ) | $ | 32.46 | $ | 17 | ||||||||||||||||||||||||||
Forfeited/expired | (8 | ) | $ | 31.57 | ||||||||||||||||||||||||||||
Outstanding and exercisable at December 31, 2011 | 628 | $ | 30.81 | $ | 14 | |||||||||||||||||||||||||||
Exercised | (622 | ) | $ | 30.79 | $ | 13 | ||||||||||||||||||||||||||
Forfeited/expired | (6 | ) | $ | 32.26 | ||||||||||||||||||||||||||||
Outstanding and exercisable at December 31, 2012 | — | $ | — | — | $ | — |
(1) | Intrinsic value represents the difference between the exercise price of the option and the market value of Dominion’s stock. |
Combined Notes to Consolidated Financial Statements, Continued
Dominion issues new shares to satisfy stock option exercises. Dominion received cash proceeds from the exercise of stock options of approximately $63$19 million, $49$38 million, and $43$63 million in the years ended December 31, 2012, 2011 and 2010, 2009 and 2008, respectively.
RESTRICTED STOCK
Restricted stock grants are made to officers under Dominion’s LTIP and may also be granted to certain key contributors from time to time. The fair value of Dominion’s restricted stock awards is equal to the market price of Dominion’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2010, 20092012, 2011 and 2008:2010:
Shares | Weighted - average Grant Date Fair Value | Shares | Weighted - average Grant Date Fair Value | |||||||||||||
(thousands) | (thousands) | |||||||||||||||
Nonvested at December 31, 2007 | 2,014 | $ | 35.31 | |||||||||||||
Granted | 546 | 40.99 | ||||||||||||||
Vested | (935 | ) | 32.09 | |||||||||||||
Cancelled and forfeited | (69 | ) | 39.51 | |||||||||||||
Converted from goal-based stock to restricted stock | 200 | 34.77 | ||||||||||||||
Nonvested at December 31, 2008 | 1,756 | $ | 38.55 | |||||||||||||
Granted | 533 | 33.84 | ||||||||||||||
Vested | (913 | ) | 34.81 | |||||||||||||
Cancelled and forfeited | (77 | ) | 38.32 | |||||||||||||
Converted from goal-based stock to restricted stock | 185 | 44.18 | ||||||||||||||
Nonvested at December 31, 2009 | 1,484 | $ | 39.88 | 1,484 | $ | 39.88 | ||||||||||
Granted | 463 | 38.80 | 463 | 38.80 | ||||||||||||
Vested | (618 | ) | 43.54 | (618 | ) | 43.54 | ||||||||||
Cancelled and forfeited | (39 | ) | 36.92 | (39 | ) | 36.92 | ||||||||||
Converted from goal-based stock to restricted stock | 186 | 40.84 | 186 | 40.84 | ||||||||||||
Nonvested at December 31, 2010 | 1,476 | $ | 38.20 | 1,476 | $ | 38.20 | ||||||||||
Granted | 299 | 43.68 | ||||||||||||||
Vested | (617 | ) | 40.72 | |||||||||||||
Cancelled and forfeited | (25 | ) | 36.29 | |||||||||||||
Converted from goal-based stock to restricted stock | 168 | 30.99 | ||||||||||||||
Nonvested at December 31, 2011 | 1,301 | $ | 37.37 | |||||||||||||
Granted | 390 | 51.14 | ||||||||||||||
Vested | (596 | ) | 33.31 | |||||||||||||
Cancelled and forfeited | (10 | ) | 42.99 | |||||||||||||
Nonvested at December 31, 2012 | 1,085 | $ | 44.46 |
As of December 31, 2010,2012, unrecognized compensation cost related to nonvested restricted stock awards totaled $21$23 million and is expected to be recognized over a weighted-average period of 1.62.1 years. The fair value of restricted stock awards that vested was $30 million, $28 million, and $26 million $29 million,in 2012, 2011 and $40 million in 2010, 2009 and 2008, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion stock and the applicable federal, state and local tax withholding rates.
GOAL-BASED STOCK
Goal-based stock awards have beenare granted under Dominion’s LTIP to key contributors who are non-officer employees and to certain officers who have not achieved a certain targeted level of share ownership, in lieu of cash-based performance grants. Goal-based stock awards may also be made to certain key non-officer employees from time to time. Current outstanding goal-based shares include awards granted to officers in February 2009, April 20092011 and February 2010.2012.
The issuance of awards is based on the achievement of multipletwo performance metrics during a two-year period, including ROIC, BVP (for awards made in 2008 and 2009) and TSR relative to that of a peer group of companies.companies and ROIC for 2011 and, for 2012, the two metrics of TSR relative to that of companies listed as members of the Philadelphia Stock Exchange Utility Index as of the end of the performance period and ROIC. The actual number of
shares issued will vary between zero and 200% of targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is equal to the market price of Dominion’s stock on the date of grant. Goal-based stock awards granted to key non-officer employees convert to restricted stock at the end
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Combined Notes to Consolidated Financial Statements, Continued
of the two-year performance period and generally vest three years from the original grant date. Awards to officers vest at the end of the two-year performance period. All goal-based stock awards are settled by issuing new shares.
After the performance period for the April 20072009 grants ended on December 31, 2008,2010, the CGN Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 127132 thousand shares of the outstanding goal-based stock awards granted in April 20072009 were converted to 185168 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2010.2012. For awards to officers, 2720 thousand shares of the outstanding goal-based stock awards were converted to 3825 thousand non-restricted shares and issued to the officers.
After the performance period for the April 20082010 grants ended on December 31, 2009,2011, the CGN Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 147 thousand shares of the outstanding goal-based stock awards granted in April 2008 were converted to 186 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2011. For awards to officers, 129 thousand shares of the outstanding goal-based stock awards were converted to 15 thousand non-restricted shares and issued to the officers.
The following table provides a summary of goal-based stock activity for the years ended December 31, 2010, 20092012, 2011 and 2008:2010:
Targeted Number of Shares | Weighted - average Grant Date Fair Value | Targeted Number of Shares | Weighted - average | |||||||||||||
(thousands) | (thousands) | |||||||||||||||
Nonvested at December 31, 2007 | 289 | $ | 39.16 | |||||||||||||
Granted | 164 | 40.97 | ||||||||||||||
Vested | (1 | ) | 43.78 | |||||||||||||
Cancelled and forfeited | (7 | ) | 43.33 | |||||||||||||
Converted from goal-based stock to restricted stock | (130 | ) | 34.77 | |||||||||||||
Nonvested at December 31, 2008 | 315 | $ | 42.56 | |||||||||||||
Granted | 165 | 31.43 | ||||||||||||||
Vested | (28 | ) | 44.38 | |||||||||||||
Cancelled and forfeited | (2 | ) | 37.24 | |||||||||||||
Converted from goal-based stock to restricted stock | (127 | ) | 44.18 | |||||||||||||
Nonvested at December 31, 2009 | 323 | $ | 36.12 | 323 | $ | 36.12 | ||||||||||
Granted | 9 | 37.46 | 9 | 37.46 | ||||||||||||
Vested | (16 | ) | 39.31 | (16 | ) | 39.31 | ||||||||||
Cancelled and forfeited | (8 | ) | 30.99 | (8 | ) | 30.99 | ||||||||||
Converted from goal-based stock to restricted stock | (147 | ) | 40.84 | (147 | ) | 40.84 | ||||||||||
Nonvested at December 31, 2010 | 161 | $ | 31.79 | 161 | $ | 31.79 | ||||||||||
Granted | 3 | 43.54 | ||||||||||||||
Vested | (20 | ) | 34.62 | |||||||||||||
Converted from goal-based stock to restricted stock | (132 | ) | 30.99 | |||||||||||||
Nonvested at December 31, 2011 | 12 | $ | 39.19 | |||||||||||||
Granted | 1 | 52.48 | ||||||||||||||
Vested | (9 | ) | 37.46 | |||||||||||||
Nonvested at December 31, 2012 | 4 | $ | 45.60 |
At December 31, 2010,2012, the targeted number of shares expected to be issued under the February 2009, April 2009,2011 and February 20102012 awards was approximately 1614 thousand. In January 2011,2013, the CGN Committee determined the actual performance against metrics established for the February 2009 and April
20092011 awards with a performance period that ended December 31, 2010.2012. Based on that determination, the total number of shares to be issued under the February 2011 goal-based stock awards was approximately 2022 thousand.
As of December 31, 2010,2012, unrecognized compensation cost related to nonvested goal-based stock awards totaled $2 million and is expected to be recognized over a weighted-average period of 1.1 years.was not material.
CASH-BASED PERFORMANCE GRANTRANTS
Cash-based performance grants are made to Dominion’s officers under Dominion’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.
The targeted amount of the cash-based performance grant
made to officers in April 20072009 was $11 million, but the actual payout of the award in February 20092011 determined by the CGN Committee was $16$14 million ($11 million of which was paid in December 2010), based on the level of performance metrics achieved.
The targeted amount of the cash-based performance grant made to officers in April 2008 was $12 million, but the actual payout of the award inIn February 2010, determined by the CGN Committee was $15 million, based on the level of performance metrics achieved. At December 31, 2009, a liability of $15 million had been accrued for this award.
In February 2009, a cash-based performance grant was made to officers. A portion of the grant, representing the $11$14 million targeted amount as of December 31, 2010, was paid in December 2010, based on the achievement of three performance metrics during 2009 and 2010: ROIC, BVP and TSR relative to that of a peer group of companies. The total expected award under the grant is $14 million and the remaining portion of the grant will be paid by March 15, 2011. At December 31, 2010, a liability of $3 million had been accrued for the remaining portion of the award.
In February 2010, a cash-based performance grant was made to officers. Payout of the performance grant will occur by March 15, 20122011, based on the achievement of two performance metrics during 2010 and 2011: ROIC and TSR relative to that of a peer group of companies. The total amount of the award under the grant was $20 million and the remaining $6 million of the grant was paid in February 2012. At December 31, 2010,2011, a liability of $5 million had been accrued for the remaining portion of the award.
In February 2011, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $6 million was paid in December 2012, based on the achievement of two performance metrics during 2011 and 2012: TSR relative to that of a peer group of companies and ROIC. The total expected award under the grant is $8 million and the remaining portion of the grant is expected to be paid by March 15, 2013. At December 31, 2012, a liability of $2 million had been accrued for the remaining portion of the award.
In February 2012, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2014 based on the achievement of two performance metrics during 2012 and 2013: TSR relative to that of companies listed as members of the Philadelphia Stock Exchange Utility Index as of the end of the performance period and ROIC. At December 31, 2012, the targeted amount of the grant was $12 million and a liability of $6 million had been accrued for this award.
NOTE 21.20. DIVIDEND RESTRICTIONS
The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2010,2012, 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’s or Virginia Power’s ability to pay dividends or receive dividends from their subsidiaries at December 31, 2010.2012.
See Note 1817 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes.
NOTE 22.21. EMPLOYEE BENEFIT PLANS
DOMINION
Dominion provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit plans, Dominion reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.
Dominion maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the
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employee’s compensation. Dominion’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension program also provides benefits to certain retired executives under a company-sponsored nonqualified employee benefit plan. The nonqualified plan is funded through contributions to a grantor trust.
Dominion also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service. In January 2011, Dominion amended its retiree healthcare and life benefits to change the eligibility age for the majority of nonunion employees from 55 with 10 years of service to 58 with 10 years of service, resulting in an approximately $71 million reduction to the other postretirement benefit plan obligation. The eligibility requirements for nonunion employees hired on or after January 1, 2008, who benefit under the Retiree Medical Account design, as well as for union employees are not affected by this plan design change.
Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and the rate of compensation increases.
Dominion uses December 31 as the measurement date for all of its employee benefit plans. Dominion uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.
Dominion’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Aggregate actual returns for Dominion’s pension and other postretirement plan assets were $624$743 million in 20102012 and $777$273 million in 2009,2011, versus expected returns of $479$509 million and $462$519 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the 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.
Combined NotesIn January 2011, Dominion amended its retiree healthcare and life benefits to Consolidated Financial Statements, Continuedchange the eligibility age, effective January 1, 2012, for the majority of nonunion employees from 55 with 10 years of service to 58 with 10 years of service, resulting in an approximately $71 million reduction to the other postretirement benefit plan obligation. The eligibility requirements for nonunion employees hired on or after January 1, 2008, who benefit under the Retiree Medical Account design, as well as for union employees were not affected by this plan design change.
The Medicare Act introduced a federal subsidy to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Dominion determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D. In 2010 and 2009, Dominion received a federal subsidy of $5 million for each of 2012 and $4 million, respectively, and expects2011. In December 2011, Dominion elected to continue to receivechange its method of receiving the subsidy offered under Medicare Part D for retiree prescription drug coverage
from the Retiree Drug Subsidy to the EGWP. This change became effective January 1, 2013. As a result of this change, Dominion recognized a decrease in its other postretirement benefit obligations of approximately $170 million as of December 31, 2011. As a result of the adoption of the EGWP, beginning in 2013 Dominion will receive an increased level of Medicare Act.Part D subsidies, in the form of reduced costs rather than a direct reimbursement.
Funded Status
The following table summarizes the changes in Dominion’s pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status:
Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||||
Year Ended December 31, | 2010 | 2009 | 2010 | 2009 | 2012 | 2011 | 2012 | 2011 | ||||||||||||||||||||||||
(millions, except percentages) | ||||||||||||||||||||||||||||||||
Changes in benefit obligation: | ||||||||||||||||||||||||||||||||
Benefit obligation at beginning of year | $ | 4,126 | $ | 3,893 | $ | 1,555 | $ | 1,554 | $ | 4,981 | $ | 4,490 | $ | 1,493 | $ | 1,707 | ||||||||||||||||
Service cost | 102 | 106 | 56 | 60 | 116 | 108 | 44 | 48 | ||||||||||||||||||||||||
Interest cost | 266 | 250 | 101 | 100 | 268 | 258 | 79 | 94 | ||||||||||||||||||||||||
Benefits paid | (211 | ) | (179 | ) | (82 | ) | (77 | ) | (208 | ) | (215 | ) | (88 | ) | (83 | ) | ||||||||||||||||
Actuarial (gains) losses during the year | 210 | 54 | 36 | (85 | ) | 967 | 340 | 191 | (210 | ) | ||||||||||||||||||||||
Transfer(1) | (48 | ) | — | — | — | |||||||||||||||||||||||||||
Plan amendments | 1 | 1 | — | (1 | ) | 1 | — | 1 | (70 | ) | ||||||||||||||||||||||
Settlements and curtailments(2) | 34 | 1 | 35 | — | ||||||||||||||||||||||||||||
Special termination benefits(3) | 10 | — | 1 | — | ||||||||||||||||||||||||||||
Settlements and curtailments | — | — | (6 | ) | (1 | ) | ||||||||||||||||||||||||||
Medicare Part D reimbursement | — | — | 5 | 4 | — | — | 5 | 5 | ||||||||||||||||||||||||
Early Retirement Reimbursement Program | — | — | — | 3 | ||||||||||||||||||||||||||||
Benefit obligation at end of year | $ | 4,490 | $ | 4,126 | $ | 1,707 | $ | 1,555 | $ | 6,125 | $ | 4,981 | $ | 1,719 | $ | 1,493 | ||||||||||||||||
Changes in fair value of plan assets: | ||||||||||||||||||||||||||||||||
Fair value of plan assets at beginning of year | $ | 4,226 | $ | 3,757 | $ | 918 | $ | 747 | $ | 5,145 | $ | 5,106 | $ | 1,042 | $ | 1,031 | ||||||||||||||||
Actual return on plan assets | 532 | 633 | 92 | 144 | 611 | 247 | 132 | 26 | ||||||||||||||||||||||||
Employer contributions | 665 | 15 | 56 | 64 | 5 | 7 | 16 | 19 | ||||||||||||||||||||||||
Benefits paid | (211 | ) | (179 | ) | (35 | ) | (37 | ) | (208 | ) | (215 | ) | (34 | ) | (34 | ) | ||||||||||||||||
Transfer(1) | (106 | ) | — | — | — | |||||||||||||||||||||||||||
Fair value of plan assets at end of year | $ | 5,106 | $ | 4,226 | $ | 1,031 | $ | 918 | $ | 5,553 | $ | 5,145 | $ | 1,156 | $ | 1,042 | ||||||||||||||||
Funded status at end of year | $ | 616 | $ | 100 | $ | (676 | ) | $ | (637 | ) | $ | (572 | ) | $ | 164 | $ | (563 | ) | $ | (451 | ) | |||||||||||
Amounts recognized in the Consolidated Balance Sheets at December 31: | ||||||||||||||||||||||||||||||||
Assets held for sale(4) | $ | — | $ | 47 | $ | — | $ | — | ||||||||||||||||||||||||
Noncurrent pension and other postretirement benefit assets | 710 | 695 | 2 | 7 | 701 | 677 | 1 | 4 | ||||||||||||||||||||||||
Liabilities held for sale(4) | — | — | — | (11 | ) | |||||||||||||||||||||||||||
Other current liabilities | (4 | ) | (13 | ) | (3 | ) | (2 | ) | (2 | ) | (3 | ) | (4 | ) | (3 | ) | ||||||||||||||||
Noncurrent pension and other postretirement benefit liabilities | (90 | ) | (629 | ) | (675 | ) | (631 | ) | (1,271 | ) | (510 | ) | (560 | ) | (452 | ) | ||||||||||||||||
Net amount recognized | $ | 616 | $ | 100 | $ | (676 | ) | $ | (637 | ) | $ | (572 | ) | $ | 164 | $ | (563 | ) | $ | (451 | ) | |||||||||||
Significant assumptions used to determine benefit obligations as of December 31: | ||||||||||||||||||||||||||||||||
Discount rate | 5.90 | % | 6.60 | % | 5.90 | % | 6.60 | % | 4.4 | % | 5.5 | % | 4.4 | % | 5.5 | % | ||||||||||||||||
Weighted average rate of increase for compensation | 4.61 | % | 4.76 | % | 4.62 | % | 4.79 | % | 4.21 | % | 4.21 | % | 4.22 | % | 4.22 | % |
107
Combined Notes to Consolidated Financial Statements, Continued
The ABO for all of Dominion’s defined benefit pension plans was $4.1$5.5 billion and $3.6$4.5 billion at December 31, 20102012 and 2009,2011, respectively.
Under its funding policies, Dominion evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion determines the amount of contributions for the current year, if any, at that time. During 2010,2012, Dominion contributed $650 million to its qualified defined benefit pension plans. Nomade no contributions to its qualified defined benefit pension plans and no contributions are currently expected in 2011. 2013. In July 2012, the Moving Ahead for Progress in the 21st Century Act was signed into law. This Act includes an increase in the interest rates used to determine plan sponsors’ pension contributions for required funding purposes. These new interest rates are expected to reduce required pension contributions for 2013 through 2015. Dominion believes that required pension contributions will rise subsequent to 2015, resulting in little net impact to cumulative required contributions over a 10-year period.
Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion’s subsidiaries fund other postretirement benefit costs through VEBAs. Dominion’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion expects to contribute approximately $22$14 million to the Dominion VEBAs in 2011.2013.
Dominion does not expect any pension or other postretirement plan assets to be returned to the Company during 2011.2013.
The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets:
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
As of December 31, | 2010 | 2009 | 2010 | 2009 | ||||||||||||
(millions) | ||||||||||||||||
Benefit obligation | $ | 121 | (1) | $ | 3,537 | $ | 1,583 | $ | 1,430 | |||||||
Fair value of plan assets | 27 | (1) | 2,902 | 905 | 786 |
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
As of December 31, | 2012 | 2011 | 2012 | 2011 | ||||||||||||
(millions) | ||||||||||||||||
Benefit obligation | $ | 5,462 | $ | 4,416 | $ | 1,591 | $ | 1,375 | ||||||||
Fair value of plan assets | $ | 4,189 | 3,903 | 1,027 | 920 |
The following table provides information on the ABO and fair value of plan assets for pension plans with an ABO in excess of plan assets:
As of December 31, | 2010 | 2009 | 2012(1) | 2011 | ||||||||||||||
(millions) | ||||||||||||||||||
Accumulated benefit obligation | $ | 80 | (1) | $ | 3,085 | $ | 4,850 | $ | 95 | |||||||||
Fair value of plan assets | — | (1) | 2,902 | 4,189 | — |
(1) | The increase from 2011 is primarily due to a decrease |
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
Estimated Future Benefit Payments | Estimated Future Benefit Payments | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | |||||||||||||
(millions) | ||||||||||||||||
2011 | $ | 219 | $ | 101 | ||||||||||||
2012 | 226 | 106 | ||||||||||||||
2013 | 234 | 111 | $ | 231 | $ | 89 | ||||||||||
2014 | 246 | 116 | 245 | 93 | ||||||||||||
2015 | 271 | 121 | 255 | 96 | ||||||||||||
2016-2020 | 1,636 | 681 | ||||||||||||||
2016 | 300 | 100 | ||||||||||||||
2017 | 334 | 103 | ||||||||||||||
2018-2022 | 1,749 | 555 |
The above benefit payments for other postretirement benefit plans are expected to be offset by Medicare Part D subsidies of approximately $6 million each in 2011 and 2012, $7 million each in 2013 and 2014, $8 million in 2015 and $50 million during the period 2016 through 2020.Plan Assets
Dominion’s overall objective for investing its pension and other postretirement plan assets is to achieve the best possible long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for its pension funds are 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies
located in the United States. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the United States including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity REITs and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.
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 employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.
For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 7.6.
Combined Notes to Consolidated Financial Statements, Continued
The fair values of Dominion’s pension plan assets by asset category are as follows:
Fair Value Measurements | ||||||||||||||||||||||||||||||||
Pension Plans | ||||||||||||||||||||||||||||||||
At December 31, | 2010 | 2009 | ||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Cash equivalents | $ | 1 | $ | 264 | $ | — | $ | 265 | $ | — | $ | 233 | $ | — | $ | 233 | ||||||||||||||||
U.S. equity: | ||||||||||||||||||||||||||||||||
Large Cap | 937 | 197 | — | 1,134 | 886 | 114 | — | 1,000 | ||||||||||||||||||||||||
Other | 436 | 96 | — | 532 | 243 | — | — | 243 | ||||||||||||||||||||||||
Non-U.S. equity: | ||||||||||||||||||||||||||||||||
Large Cap | 231 | — | — | 231 | 242 | 111 | — | 353 | ||||||||||||||||||||||||
Other | 119 | 365 | — | 484 | 20 | 36 | — | 56 | ||||||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||||||||||
Corporate debt instruments | 32 | 694 | — | 726 | 57 | 611 | — | 668 | ||||||||||||||||||||||||
U.S. Treasury securities and agency debentures | 168 | 216 | — | 384 | 8 | 188 | — | 196 | ||||||||||||||||||||||||
State and municipal | 2 | 42 | — | 44 | 101 | 11 | — | 112 | ||||||||||||||||||||||||
Other securities | — | 3 | — | 3 | — | 1 | — | 1 | ||||||||||||||||||||||||
Real estate: | ||||||||||||||||||||||||||||||||
REITs | 51 | — | — | 51 | 33 | — | — | 33 | ||||||||||||||||||||||||
Partnerships | — | — | 271 | 271 | — | — | 344 | 344 | ||||||||||||||||||||||||
Other alternative investments: | ||||||||||||||||||||||||||||||||
Private equity | — | — | 400 | 400 | — | — | 344 | 344 | ||||||||||||||||||||||||
Debt | — | — | 262 | 262 | — | — | 241 | 241 | ||||||||||||||||||||||||
Hedge funds | — | — | 345 | 345 | — | — | 388 | 388 | ||||||||||||||||||||||||
Total(1) | $ | 1,977 | $ | 1,877 | $ | 1,278 | $ | 5,132 | $ | 1,590 | $ | 1,305 | $ | 1,317 | $ | 4,212 |
The fair values of Dominion’s other postretirement plan assets by asset category are as follows:
Fair Value Measurements | ||||||||||||||||||||||||||||||||
Other Postretirement Plans | ||||||||||||||||||||||||||||||||
At December 31, | 2010 | 2009 | ||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Cash equivalents | $ | — | $ | 13 | $ | — | $ | 13 | $ | — | $ | 13 | $ | — | $ | 13 | ||||||||||||||||
U.S. equity: | ||||||||||||||||||||||||||||||||
Large Cap | 43 | 293 | — | 336 | 291 | 35 | — | 326 | ||||||||||||||||||||||||
Other | 20 | 41 | — | 61 | 12 | — | — | 12 | ||||||||||||||||||||||||
Non-U.S. equity: | ||||||||||||||||||||||||||||||||
Large Cap | 87 | — | — | 87 | 85 | 5 | — | 90 | ||||||||||||||||||||||||
Other | 5 | 17 | — | 22 | 1 | 2 | — | 3 | ||||||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||||||||||
Corporate debt instruments | 1 | 106 | — | 107 | 3 | 120 | — | 123 | ||||||||||||||||||||||||
U.S. Treasury securities and agency debentures | 8 | 248 | — | 256 | — | 183 | — | 183 | ||||||||||||||||||||||||
State and municipal | — | 8 | — | 8 | 5 | 25 | — | 30 | ||||||||||||||||||||||||
Real estate: | ||||||||||||||||||||||||||||||||
REITs | 2 | — | — | 2 | 2 | — | — | 2 | ||||||||||||||||||||||||
Partnerships | — | — | 22 | 22 | — | — | 26 | 26 | ||||||||||||||||||||||||
Other alternative investments: | ||||||||||||||||||||||||||||||||
Private equity | — | — | 61 | 61 | — | — | 54 | 54 | ||||||||||||||||||||||||
Debt | — | — | 40 | 40 | — | — | 36 | 36 | ||||||||||||||||||||||||
Hedge funds | — | — | 17 | 17 | — | — | 19 | 19 | ||||||||||||||||||||||||
Total(1) | $ | 166 | $ | 726 | $ | 140 | $ | 1,032 | $ | 399 | $ | 383 | $ | 135 | $ | 917 |
108 |
The fair values of Dominion’s pension plan assets by asset category are as follows:
Fair Value Measurements | ||||||||||||||||||||||||||||||||
Pension Plans | ||||||||||||||||||||||||||||||||
At December 31, | 2012 | 2011 | ||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Cash equivalents | $ | — | $ | 195 | $ | — | $ | 195 | $ | 1 | $ | 84 | $ | — | $ | 85 | ||||||||||||||||
U.S. equity: | ||||||||||||||||||||||||||||||||
Large Cap | 927 | 104 | — | 1,031 | 805 | 123 | — | 928 | ||||||||||||||||||||||||
Other | 425 | 99 | — | 524 | 359 | 197 | — | 556 | ||||||||||||||||||||||||
Non-U.S. equity: | ||||||||||||||||||||||||||||||||
Large Cap | 313 | 68 | — | 381 | 253 | 58 | — | 311 | ||||||||||||||||||||||||
Other | 228 | 167 | — | 395 | 190 | 81 | — | 271 | ||||||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||||||||||
Corporate debt instruments | 27 | 1,026 | — | 1,053 | 36 | 834 | — | 870 | ||||||||||||||||||||||||
U.S. Treasury securities and agency debentures | 331 | 304 | — | 635 | 304 | 392 | — | 696 | ||||||||||||||||||||||||
State and municipal | 1 | 71 | — | 72 | 2 | 77 | — | 79 | ||||||||||||||||||||||||
Other securities | 5 | 43 | — | 48 | 8 | 40 | — | 48 | ||||||||||||||||||||||||
Real estate: | ||||||||||||||||||||||||||||||||
REITs | 29 | — | — | 29 | 16 | — | — | 16 | ||||||||||||||||||||||||
Partnerships | — | — | 321 | 321 | — | — | 304 | 304 | ||||||||||||||||||||||||
Other alternative investments: | ||||||||||||||||||||||||||||||||
Private equity | — | — | 456 | 456 | — | — | 448 | 448 | ||||||||||||||||||||||||
Debt | — | — | 192 | 192 | — | — | 243 | 243 | ||||||||||||||||||||||||
Hedge funds | — | — | 221 | 221 | — | — | 290 | 290 | ||||||||||||||||||||||||
Total | $ | 2,286 | $ | 2,077 | $ | 1,190 | $ | 5,553 | $ | 1,974 | $ | 1,886 | $ | 1,285 | $ | 5,145 |
The fair values of Dominion’s other postretirement plan assets by asset category are as follows:
Fair Value Measurements | ||||||||||||||||||||||||||||||||
Other Postretirement Plans | ||||||||||||||||||||||||||||||||
At December 31, | 2012 | 2011 | ||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Cash equivalents | $ | — | $ | 13 | $ | — | $ | 13 | $ | — | $ | 5 | $ | — | $ | 5 | ||||||||||||||||
U.S. equity: | ||||||||||||||||||||||||||||||||
Large Cap | 378 | 5 | — | 383 | 38 | 288 | — | 326 | ||||||||||||||||||||||||
Other | 21 | 45 | — | 66 | 17 | 44 | — | 61 | ||||||||||||||||||||||||
Non-U.S. equity: | ||||||||||||||||||||||||||||||||
Large Cap | 93 | 3 | — | 96 | 77 | 3 | — | 80 | ||||||||||||||||||||||||
Other | 11 | 8 | — | 19 | 9 | 4 | — | 13 | ||||||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||||||||||
Corporate debt instruments | 1 | 160 | — | 161 | 2 | 149 | — | 151 | ||||||||||||||||||||||||
U.S. Treasury securities and agency debentures | 16 | 266 | — | 282 | 14 | 246 | — | 260 | ||||||||||||||||||||||||
State and municipal | — | 9 | — | 9 | — | 6 | — | 6 | ||||||||||||||||||||||||
Other securities | — | 2 | — | 2 | — | 2 | — | 2 | ||||||||||||||||||||||||
Real estate: | ||||||||||||||||||||||||||||||||
REITs | 1 | — | — | 1 | 1 | — | — | 1 | ||||||||||||||||||||||||
Partnerships | — | — | 24 | 24 | — | — | 24 | 24 | ||||||||||||||||||||||||
Other alternative investments: | ||||||||||||||||||||||||||||||||
Private equity | — | — | 58 | 58 | — | — | 63 | 63 | ||||||||||||||||||||||||
Debt | — | — | 31 | 31 | — | — | 36 | 36 | ||||||||||||||||||||||||
Hedge funds | — | — | 11 | 11 | — | — | 14 | 14 | ||||||||||||||||||||||||
Total | $ | 521 | $ | 511 | $ | 124 | $ | 1,156 | $ | 158 | $ | 747 | $ | 137 | $ | 1,042 |
109 |
Combined Notes to Consolidated Financial Statements, Continued
The following table presents the changes in Dominion’s pension plan assets that are measured at fair value and included in the Level 3 fair value category:
Fair Value Measurements Using Significant Unobservable Inputs (Level 3) | ||||||||||||||||||||||||||||||||||||||||
Pension Plans | ||||||||||||||||||||||||||||||||||||||||
2010 | 2009 | |||||||||||||||||||||||||||||||||||||||
Real Estate | Private Equity | Debt | Hedge Funds | Total | Real Estate | Private Equity | Debt | Hedge Funds | Total | |||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
Balance at January 1, | $ | 344 | $ | 344 | $ | 241 | $ | 388 | $ | 1,317 | $ | 438 | $ | 267 | $ | 191 | $ | 324 | $ | 1,220 | ||||||||||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||||||||||||||||||
Relating to assets still held at the reporting date | 8 | 56 | 27 | 27 | 118 | (91 | ) | 128 | 19 | — | 56 | |||||||||||||||||||||||||||||
Relating to assets sold during the period | — | — | — | — | — | (1 | ) | 1 | — | — | — | |||||||||||||||||||||||||||||
Purchases, sales and settlements | (81 | ) | — | (6 | ) | (70 | ) | (157 | ) | (2 | ) | (52 | ) | 31 | 64 | 41 | ||||||||||||||||||||||||
Balance at December 31 | $ | 271 | $ | 400 | $ | 262 | $ | 345 | $ | 1,278 | $ | 344 | $ | 344 | $ | 241 | $ | 388 | $ | 1,317 |
The following table presents the changes in Dominion’s other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category:
Fair Value Measurements Using Significant Unobservable Inputs (Level 3) | ||||||||||||||||||||||||||||||||||||||||
Other Postretirement Plans | ||||||||||||||||||||||||||||||||||||||||
2010 | 2009 | |||||||||||||||||||||||||||||||||||||||
Real Estate | Private Equity | Debt | Hedge Funds | Total | Real Estate | Private Equity | Debt | Hedge Funds | Total | |||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
Balance at January 1, | $ | 26 | $ | 54 | $ | 36 | $ | 19 | $ | 135 | $ | 32 | $ | 47 | $ | 28 | $ | 15 | $ | 122 | ||||||||||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||||||||||||||||||
Relating to assets still held at the reporting date | — | 9 | 2 | 1 | 12 | (9 | ) | 13 | 3 | — | 7 | |||||||||||||||||||||||||||||
Purchases, sales and settlements | (4 | ) | (2 | ) | 2 | (3 | ) | (7 | ) | 3 | (6 | ) | 5 | 4 | 6 | |||||||||||||||||||||||||
Balance at December 31 | $ | 22 | $ | 61 | $ | 40 | $ | 17 | $ | 140 | $ | 26 | $ | 54 | $ | 36 | $ | 19 | $ | 135 |
Fair Value Measurements using Significant Unobservable Inputs (Level 3) | ||||||||||||||||||||||||||||||||||||||||
Pension Plans | Other Postretirement Plans | |||||||||||||||||||||||||||||||||||||||
Real Estate | Private Equity | Debt | Hedge Funds | Total | Real Estate | Private Equity | Debt | Hedge Funds | Total | |||||||||||||||||||||||||||||||
Balance at December 31, 2009 | $344 | $344 | $241 | $388 | $1,317 | $26 | $54 | $36 | $19 | $135 | ||||||||||||||||||||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||||||||||||||||||
Relating to assets still held at the reporting date | 8 | 56 | 27 | 27 | 118 | — | 9 | 2 | 1 | 12 | ||||||||||||||||||||||||||||||
Purchases | 56 | 90 | 36 | — | 182 | 3 | 9 | 8 | — | 20 | ||||||||||||||||||||||||||||||
Sales | (137 | ) | (90 | ) | (42 | ) | (70 | ) | (339 | ) | (7 | ) | (11 | ) | (6 | ) | (3 | ) | (27 | ) | ||||||||||||||||||||
Balance at December 31, 2010 | $ | 271 | $ | 400 | $ | 262 | $ | 345 | $ | 1,278 | $ | 22 | $ | 61 | $ | 40 | $ | 17 | $ | 140 | ||||||||||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||||||||||||||||||
Relating to assets still held at the reporting date | 38 | 70 | 10 | 10 | 128 | 3 | 11 | 1 | — | 15 | ||||||||||||||||||||||||||||||
Relating to assets sold during the period | (8 | ) | (34 | ) | (10 | ) | (15 | ) | (67 | ) | — | (4 | ) | (1 | ) | (1 | ) | (6 | ) | |||||||||||||||||||||
Purchases | 57 | 76 | 34 | 48 | 215 | 3 | 8 | 3 | 2 | 16 | ||||||||||||||||||||||||||||||
Sales | (54 | ) | (64 | ) | (53 | ) | (98 | ) | (269 | ) | (4 | ) | (13 | ) | (7 | ) | (4 | ) | (28 | ) | ||||||||||||||||||||
Balance at December 31, 2011 | $ | 304 | $ | 448 | $ | 243 | $ | 290 | $ | 1,285 | $ | 24 | $ | 63 | $ | 36 | $ | 14 | $ | 137 | ||||||||||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||||||||||||||||||
Relating to assets still held at the reporting date | 21 | 46 | 17 | 21 | 105 | 1 | 3 | 4 | 1 | 9 | ||||||||||||||||||||||||||||||
Relating to assets sold during the period | (8 | ) | (41 | ) | (11 | ) | (2 | ) | (62 | ) | — | (1 | ) | — | — | (1 | ) | |||||||||||||||||||||||
Purchases | 35 | 79 | 15 | — | 129 | 2 | 6 | 1 | — | 9 | ||||||||||||||||||||||||||||||
Sales | (31 | ) | (76 | ) | (72 | ) | (88 | ) | (267 | ) | (3 | ) | (13 | ) | (10 | ) | (4 | ) | (30 | ) | ||||||||||||||||||||
Balance at December 31, 2012 | $ | 321 | $ | 456 | $ | 192 | $ | 221 | $ | 1,190 | $ | 24 | $ | 58 | $ | 31 | $ | 11 | $ | 124 |
Net Periodic Benefit Cost
The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:
Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | 2012 | 2011 | 2010 | ||||||||||||||||||||||||||||||||||||
(millions, except percentages) | ||||||||||||||||||||||||||||||||||||||||||||||||
Service cost | $ | 102 | $ | 106 | $ | 102 | $ | 56 | $ | 60 | $ | 60 | $ | 116 | $ | 108 | $ | 102 | $ | 44 | $ | 48 | $ | 56 | ||||||||||||||||||||||||
Interest cost | 266 | 250 | 236 | 101 | 100 | 93 | 268 | 258 | 266 | 79 | 94 | 101 | ||||||||||||||||||||||||||||||||||||
Expected return on plan assets | (410 | ) | (405 | ) | (411 | ) | (69 | ) | (57 | ) | (73 | ) | (430 | ) | (440 | ) | (410 | ) | (79 | ) | (79 | ) | (69 | ) | ||||||||||||||||||||||||
Amortization of prior service (credit) cost | 3 | 4 | 4 | (7 | ) | (7 | ) | (6 | ) | 3 | 3 | 3 | (13 | ) | (13 | ) | (7 | ) | ||||||||||||||||||||||||||||||
Amortization of net actuarial loss | 59 | 38 | 7 | 12 | 30 | 8 | 132 | 96 | 59 | 6 | 12 | 12 | ||||||||||||||||||||||||||||||||||||
Settlements and curtailments(1) | 136 | 3 | — | 37 | — | — | — | — | 136 | (4 | ) | 1 | 37 | |||||||||||||||||||||||||||||||||||
Special termination benefits(2) | 10 | — | — | 1 | — | — | — | — | 10 | — | — | 1 | ||||||||||||||||||||||||||||||||||||
Plan amendments | — | 1 | — | — | — | 1 | ||||||||||||||||||||||||||||||||||||||||||
Net periodic benefit (credit) cost | $ | 166 | $ | (3 | ) | $ | (62 | ) | $ | 131 | $ | 126 | $ | 83 | ||||||||||||||||||||||||||||||||||
Net periodic benefit cost | $ | 89 | $ | 25 | $ | 166 | $ | 33 | $ | 63 | $ | 131 | ||||||||||||||||||||||||||||||||||||
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||
Current year net actuarial (gain) loss | $ | 95 | $ | (174 | ) | $ | 1,643 | $ | 13 | $ | (172 | ) | $ | 306 | $ | 786 | $ | 534 | $ | 95 | $ | 139 | $ | (157 | ) | $ | 13 | |||||||||||||||||||||
Prior service (credit) cost | 1 | — | 4 | — | (1 | ) | (7 | ) | — | — | 1 | 1 | (70 | ) | — | |||||||||||||||||||||||||||||||||
Settlements and curtailments(1) | (50 | ) | (2 | ) | — | (1 | ) | — | (11 | ) | — | — | (50 | ) | (2 | ) | (1 | ) | (1 | ) | ||||||||||||||||||||||||||||
Less amounts included in net periodic benefit (credit) cost: | ||||||||||||||||||||||||||||||||||||||||||||||||
Less amounts included in net periodic benefit cost: | ||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of net actuarial loss | (59 | ) | (38 | ) | (7 | ) | (12 | ) | (30 | ) | (8 | ) | (132 | ) | (96 | ) | (59 | ) | (6 | ) | (12 | ) | (12 | ) | ||||||||||||||||||||||||
Amortization of prior service credit (cost) | (3 | ) | (4 | ) | (4 | ) | 7 | 7 | 6 | (3 | ) | (3 | ) | (3 | ) | 13 | 13 | 7 | ||||||||||||||||||||||||||||||
Total recognized in other comprehensive income and regulatory assets and liabilities | $ | (16 | ) | $ | (218 | ) | $ | 1,636 | $ | 7 | $ | (196 | ) | $ | 286 | $ | 651 | $ | 435 | $ | (16 | ) | $ | 145 | $ | (227 | ) | $ | 7 | |||||||||||||||||||
Significant assumptions used to determine periodic cost: | ||||||||||||||||||||||||||||||||||||||||||||||||
Discount rate | 6.60 | % | 6.60 | % | 6.60 | % | 6.60 | % | 6.60 | % | 6.50 | % | 5.5 | % | 5.9 | % | 6.6 | % | 5.5 | % | 5.9 | % | 6.6 | % | ||||||||||||||||||||||||
Expected long-term rate of return on plan assets | 8.50 | % | 8.50 | % | 8.50 | % | 7.75 | % | 7.75 | % | 7.75 | % | 8.5 | % | 8.5 | % | 8.5 | % | 7.75 | % | 7.75 | % | 7.75 | % | ||||||||||||||||||||||||
Weighted average rate of increase for compensation | 4.76 | % | 4.79 | % | 4.79 | % | 4.79 | % | 4.78 | % | 4.70 | % | 4.21 | % | 4.61 | % | 4.76 | % | 4.22 | % | 4.62 | % | 4.79 | % | ||||||||||||||||||||||||
Healthcare cost trend rate | 7.00 | % | 8.00 | % | 9.00 | % | ||||||||||||||||||||||||||||||||||||||||||
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) | 4.60 | % | 4.90 | % | 4.90 | % | ||||||||||||||||||||||||||||||||||||||||||
Year that the rate reaches the ultimate trend rate | 2060 | 2060 | 2059 | |||||||||||||||||||||||||||||||||||||||||||||
Healthcare cost trend rate(3) | 7 | % | 7 | % | 7 | % | ||||||||||||||||||||||||||||||||||||||||||
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(3) | 4.6 | % | 4.6 | % | 4.6 | % | ||||||||||||||||||||||||||||||||||||||||||
Year that the rate reaches the ultimate trend rate(3) | 2061 | 2060 | 2060 |
(1) |
(2) | Represents a one-time special termination benefit for certain employees in connection with a workforce reduction program. |
(3) | Assumptions used to determine periodic cost for the following year. |
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Combined Notes to Consolidated Financial Statements, Continued
The components of AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit (credit) cost are as follows:
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
At December 31, | 2010 | 2009 | 2010 | 2009 | ||||||||||||
(millions) | ||||||||||||||||
Net actuarial loss | $ | 1,773 | $ | 1,788 | $ | 268 | $ | 271 | ||||||||
Prior service (credit) cost | 17 | 19 | (28 | ) | (36 | ) | ||||||||||
Total(1) | $ | 1,790 | $ | 1,807 | $ | 240 | $ | 235 |
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
At December 31, | 2012 | 2011 | 2012 | 2011 | ||||||||||||
(millions) | ||||||||||||||||
Net actuarial loss | $ | 2,865 | $ | 2,211 | $ | 229 | $ | 100 | ||||||||
Prior service (credit) cost | 11 | 14 | (71 | ) | (86 | ) | ||||||||||
Total(1) | $ | 2,876 | $ | 2,225 | $ | 158 | $ | 14 |
(1) | As of December 31, |
The following table provides the components of AOCI and regulatory assets and liabilities as of December 31, 20102012 that are expected to be amortized as components of periodic benefit cost in 2011:2013:
Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | |||||||||||||
(millions) | ||||||||||||||||
Net actuarial loss | $ | 96 | $ | 12 | $ | 185 | $ | 9 | ||||||||
Prior service (credit) cost | 3 | (6 | ) | 3 | (12 | ) |
Dominion determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans by using a combination of:
Expected inflation and risk-free interest rate assumptions;
Historical return analysis to determine expectedlong term historic returns as well as historic risk premiums for various asset classes;
Expected future risk premiums, asset volatilities and correlations;
Forecasts of an independent investment advisor;
Forward-looking return expectations derived from the yield on long-term bonds and the price earnings ratiosexpected long-term returns of major stock market indices;
Expected inflation and risk-free interest rate assumptions; and
Investment allocation of plan assets.
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 determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans.
Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion’s retiree healthcare plans. A one percentage point change in assumed healthcare cost trend rates would have had the following effects:
Other Postretirement Benefits | ||||||||
One percentage point increase | One percentage decrease | |||||||
(millions) | ||||||||
Effect on total of service and interest cost components for 2010 | $ | 23 | $ | (20 | ) | |||
Effect on other postretirement benefit obligation at December 31, 2010 | 217 | (171 | ) |
Other Postretirement Benefits | ||||||||
One percentage point increase | One percentage point decrease | |||||||
(millions) | ||||||||
Effect on total of service and interest cost components for 2012 | $ | 17 | $ | (16 | ) | |||
Effect on other postretirement benefit obligation at December 31, 2012 | 218 | (172 | ) |
An internal committee selects the final assumptions used for Dominion’s pension and other postretirement plans, including discount rates, expected long-term rates of return and healthcare cost trend rates.
Defined Contribution Plans
In addition, Dominion sponsors defined contribution employee savings plans. During 2010, 20092012, 2011 and 2008,2010, Dominion recognized $39$40 million, $42$38 million and $39 million, respectively, as employer matching contributions to these plans.
VIRGINIA POWER
Virginia Power participates in the Dominion Pension Plan, a defined benefit pension plan sponsored by Dominion. BenefitsDominion that provides benefits to multiple Dominion subsidiaries. Retirement benefits payable under thethis plan are based primarily on years of service, age and the employee’s compensation. As a participating employer, Virginia Power is subject to Dominion’s funding policy, which is to contribute annually an amount that is in accordance with the provisions of ERISA. During 2010,2012, Virginia Power contributed $302 millionmade no contributions to the defined benefit pension plan.plan and no contributions are currently expected in 2013. Virginia Power’s net periodic pension cost related to this pension plan was $72 million, $50 million and $84 million $48 millionin 2012, 2011 and $32 million in 2010, 2009 and 2008, respectively. The 2010 net periodic pension cost includes the impact of a settlement and curtailment as well as a one-time special termination benefit for certain employees in connection with a workforce reduction program. Employee compensation is the basis for determining Virginia Power’s share of total pension costs.
Virginia Power also participates in the Dominion Retiree Health and Welfare Plan, a plan sponsored by Dominion that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Annual employee premiums are based on several factors such as age, retirement date and years of service. Virginia Power’s net periodic benefit cost related to this plan was $13 million, $23 million and $59 million $55 millionin 2012, 2011 and $33 million in 2010, 2009 and 2008, respectively. Employee headcount is the basis for determining Virginia Power’s share of total other postretirement benefit costs.
Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power funds other postretirement benefit costs through a VEBA. Virginia Power’sPower made no contributions to the VEBA were $35 million, $34 millionin 2012 and $15 million in 2010, 2009 and 2008, respectively. Virginia Power expectsdoes not expect to contribute approximately $4 million to the VEBA in 2011.2013.
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Combined Notes to Consolidated Financial Statements, Continued
Dominion holds investments in trusts to fund employee benefit payments for its pension and other postretirement benefit plans, in which Virginia Power’s employees participate. Any investment-related declines in these trusts 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 that Virginia Power will provide to Dominion for its share of employee benefit plan contributions.
Virginia Power also participates in Dominion-sponsored defined contribution employee savings plans that cover substantially all employees. Employer matching contributions of $14$15 million were incurred in 2012 and $14 million in each of 2010, 20092011 and 2008.2010.
NOTE 23.22. COMMITMENTSAND CONTINGENCIES
As thea result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in legal tax and regulatory proceedings before various courts and are periodically subject to governmental examinations (including by regulatory commissionsauthorities), inquiries and investigations. Certain legal proceedings and governmental agencies, some of whichexaminations involve substantialdemands for unspecified amounts of money. The ultimatedamages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings cannot be predicted at this time; however,and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported herein,below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on Dominion’s or Virginia Power’s financial position, liquidity or results of operations.
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.
AIR
The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of Dominion’s and Virginia Power’s facilities are subject to the CAA’s permitting and other requirements.
In December 2011, the EPA issued MATS for coal and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance will be required by April 16, 2015, with certain limited exceptions. In December 2011, Virginia Power recorded a $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain regulated coal units, primarily as a result of the issuance of the final MATS. Dominion continues to be governed by individual state mercury emission reduction regulations in Massachusetts and Illinois that are largely unaffected by this rule.
The EPA established CAIR with the intent to require significant reductions in SO2 and NOxemissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO2 and NOxemissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO2 and NOx emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NOx emissions caps, NOx emissions caps during the ozone season (May 1 through September 30) and annual SO2 emission caps with differing requirements for two groups of affected states.
Following numerous petitions by industry participants for review and motions for stay, the U.S. Court of Appeals for the D.C. Circuit issued a ruling in December 2011 to stay CSAPR pending judicial review. In February and June 2012, the EPA issued technical revisions to CSAPR that are not material to Dominion. In August 2012, the Court vacated CSAPR in its entirety and ordered the EPA to implement CAIR until a valid replacement rule is issued. In October 2012, the EPA filed a petition requesting a rehearing of the court’s decision, which was denied in January 2013. The mandate vacating CSAPR was issued February 4, 2013. The stay of CSAPR remains in effect and the EPA will continue to administer CAIR until such time that the EPA develops and implements new rulemaking addressing the issues identified by the Court. With respect to Dominion’s generation fleet, the cost to comply with CAIR is not expected to be material. Future outcomes of litigation and/or any additional action to issue a revised rule could affect the assessment regarding cost of compliance.
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In May 2012, the EPA issued final designations for the 75-ppb ozone air quality standard. Several Dominion electric generating facilities are located in areas impacted by this standard. As part of the standard, states will be required to develop and implement plans to address sources emitting pollutants which contribute to the formation of ozone. Until the states have developed implementation plans, Dominion is unable to predict whether or to what extent the new rules will ultimately require additional controls.
In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, NSPS, the Title V permit program and the stations’ respective State Implementation Plans. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the CAA. In May 2010, 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 Brayton Point. Dominion submitted its response to the request in November 2010.
Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The CAA authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. In addition to any such penalties that may be awarded, an adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures. Dominion is currently in settlement discussions to resolve these matters. There can be no assurance that Dominion will reach a settlement with the EPA. However, in the past, the EPA has settled similar claims with other energy companies requiring them to pay civil penalties and/or undertake mitigation projects. Dominion has accrued a liability of $13 million, which represents its best estimate of the probable loss related to civil penalties and mitigation projects in this matter, assuming Dominion is able to reach settlement with the EPA and based on the EPA’s settlement of similar claims with other energy companies. Dominion does not believe that final resolution of the matter will have a material adverse effect on its results of operations, financial condition or cash flows.
WATER
The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. Dominion and Virginia Power must comply with all aspects of the CWA programs at their operating facilities.
In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling
water. As of the end of the third quarter of 2012, the station was fully converted to closed cycle cooling. The total cost to install these cooling towers was approximately $550 million. See Note 6 for a discussion of impairments related to Brayton Point.
In September 2010, Millstone’s NPDES permit was reissued under the CWA. The conditions of the permit require an evaluation of control technologies that could result in additional expenditures in the future. The report summarizing the results of the evaluation was submitted in August 2012 and is under review by the Connecticut Department of Energy and Environmental Protection. Dominion cannot currently predict the outcome of this review. In October 2010, the permit issuance was appealed to the state court by a private plaintiff. The permit is expected to remain in effect during the appeal. Dominion is currently unable to make an estimate of the potential financial statement impacts related to this matter.
SOLIDAND HAZARDOUS WASTE
The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally, and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.
From time to time, Dominion or Virginia Power may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion or Virginia Power may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. Except as noted below, the Companies do not believe this will have a material effect on results of operations, financial condition and/or cash flows.
In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. In November 2011, Virginia Power and a number of other parties notified the EPA that they are declining to undertake the work set forth in the UAO.
The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO
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Combined Notes to Consolidated Financial Statements, Continued
without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO. Virginia Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter.
Dominion has determined that it is associated with 17 former manufactured gas plant sites, three of which pertain to Virginia Power. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which Dominion and Virginia Power are associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Dominion is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options, but is not yet able to estimate the future remediation costs. Due to the uncertainty surrounding these sites, Dominion is unable to make an estimate of the potential financial statement impacts related to these sites.
CLIMATE CHANGE LEGISLATIONAND REGULATION
Massachusetts, Rhode Island and Connecticut, among other states, have joined RGGI, a multi-state effort to reduce CO2 emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO2 emissions from power plants in participating states are required to be stabilized at current levels from 2009 to 2015. Further reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO2 emissions. During 2012, RGGI underwent a program review, and in February 2013, revisions to the RGGI model rule were issued. Dominion is in the process of evaluating these revisions as to potential impacts on Dominion’s fossil fired generation operations in RGGI states. Until this evaluation is completed, Dominion is unable to estimate the potential financial statement impacts related to the program review.
Two of Dominion’s facilities, Brayton Point and Manchester Street, are subject to RGGI. Beginning with calendar year 2009, RGGI requires that Dominion cover each ton of CO2 direct stack emissions from these facilities with either an allowance or an offset. The allowances can be purchased through auction or through a secondary market. Dominion has periodically participated in RGGI allowance auctions to date and has procured allowances to meet its estimated compliance requirements under RGGI’s current requirement through 2013 and most of 2014, therefore Dominion does not expect compliance with RGGI to have a material impact on its results of operations or financial condition. During June 2011, a lawsuit was filed in New York seeking to retroactively rescind RGGI participation by that state. A percentage of Dominion’s RGGI allowances had been acquired from New York. The allocated value of these allowances totaled approximately $38 million, of which all have been expensed as consumed for RGGI Phase I compliance. In February 2012, Dominion surrendered these New York RGGI allowances for the
RGGI Phase I compliance period and therefore does not expect any significant financial statement impacts from this lawsuit as it no longer holds allowances issued by the state of New York. In June 2012, a New York state court dismissed the lawsuit. A notice of appeal was filed in July 2012, however no appeal was filed.
MF Global
Prior to October 31, 2011, certain of Dominion’s subsidiaries executed certain commodity transactions on exchanges using MF Global, an FCM registered with the CFTC. In order to secure its potential exposure on these commodity transactions, Dominion posted certain required margin collateral with MF Global. The parent company of MF Global, MF Global Holdings Ltd., filed for bankruptcy relief under Chapter 11 of the U.S. Bankruptcy Code on October 31, 2011. On the same date, the U.S. District Court for the Southern District of New York appointed a trustee to oversee the liquidation of MF Global pursuant to the Securities Investor Protection Act.
In accordance with court-approved procedures, Dominion transferred to other FCMs all open positions executed using MF Global. The initial margin posted for these open positions at October 31, 2011 was approximately $73 million. Dominion had received approximately $17 million of this amount through the liquidation process as of December 31, 2012. In January 2013, Dominion sold the remaining claims of approximately $56 million to a third party at a small discount.
Nuclear Matters
In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as INPO. Like other U.S. nuclear operators, Dominion has been gathering supporting data and participating in industry initiatives focused on the ability to respond to and mitigate the consequences of design-basis and beyond-design-basis events at its stations.
In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3, with the Tier 1 recommendations consisting of actions which the staff determined should be started without unnecessary delay. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations; and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.
Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion require implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation. The orders require prompt implementation of the safety enhancements and completion of implementation within two refueling outages or by December 31, 2016, whichever comes first. The information requests issued by
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the NRC request each reactor to reevaluate the seismic and flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. Dominion and Virginia Power do not currently expect that compliance with the NRC’s March 2012 orders and information requests will materially impact their financial position, results of operations or cash flows during the approximately four-year implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion and Virginia Power are currently unable to estimate the potential financial impacts related to compliance with Tier 2 and Tier 3 recommendations.
Long-Term Purchase Agreements
At December 31, 2010,2012, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:
2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | 2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | Total | |||||||||||||||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased electric capacity(1) | $ | 342 | $ | 347 | $ | 351 | $ | 358 | $ | 338 | $ | 779 | $ | 2,515 | $ | 350 | $ | 358 | $ | 337 | $ | 275 | $ | 181 | $ | 327 | $ | 1,828 |
(1) | Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, |
Lease Commitments
Dominion and Virginia Power lease various facilities, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 20102012 are as follows:
2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | 2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | Total | |||||||||||||||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dominion | $ | 184 | $ | 174 | $ | 138 | $ | 60 | $ | 48 | $ | 193 | $ | 797 | $ | 79 | $ | 72 | $ | 64 | $ | 55 | $ | 63 | $ | 161 | $ | 494 | ||||||||||||||||||||||||||||
Virginia Power | $ | 36 | $ | 28 | $ | 17 | $ | 14 | $ | 12 | $ | 23 | $ | 130 | $ | 26 | $ | 24 | $ | 19 | $ | 15 | $ | 11 | $ | 26 | $ | 121 |
Rental expense for Dominion totaled $112 million, $155 million, and $171 million $172 million,for 2012, 2011 and $160 million for 2010, 2009 and 2008, respectively. Rental expense for Virginia Power totaled $48 million, $50 million, $49 mil-
lion, and $39$50 million for 2010, 2009,2012, 2011, and 2008,2010, respectively. The majority of rental expense is reflected in other operations and maintenance expense.
Dominion leases Fairless, 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 that are reflectedexpense in the lease commitments table. 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%Consolidated Statements 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 the 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.
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.
AIR
The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of Dominion’s and Virginia Power’s facilities are subject to the CAA’s permitting and other requirements.
In May 2010, 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 Brayton Point and Salem Harbor. Dominion submitted its response to this request in November 2010 and cannot predict the outcome of this matter.
In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, New Source Performance Standards, the Title V permit program and the stations’ respective State Implementation Plans. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcementIncome.
Combined Notes to Consolidated Financial Statements, Continued
authority under the CAA. Dominion cannot predict the outcome of this matter. However, an adverse resolution could have a material effect on future results of operations and/or cash flows.
In March 2005, the EPA promulgated regulations finalizing CAIR and CAMR. In February 2008, the Court of Appeals for the District of Columbia Circuit issued a ruling vacating CAMR. The EPA is proceeding with the development of a MACT rulemaking for coal and oil-fired electric utility steam generating units. These rules could require significant reductions in mercury and other HAPs from electric generation facilities. It should be noted that Dominion continues to be governed by individual state mercury emission reduction regulations in Massachusetts and Illinois that were largely unaffected by the CAMR ruling.
In July 2008, the Court issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. The CAIR rules remain in effect until such time that the EPA develops and implements new rulemaking addressing the issues identified by the Court. In July 2010, the EPA announced a proposed new rule, called the Transport Rule, which will eventually replace CAIR, and, as proposed, requires significant reductions in SO2 and NOX emissions.
The EPA has finalized rules establishing a new 1-hour NAAQS for NO2 (January 2010) and a new 1-hour NAAQS for SO2 (June 2010), which could require additional NOX and SO2 controls in certain areas where the Companies operate. Until the states have developed implementation plans for these standards, the impact on Dominion’s or Virginia Power’s facilities that emit NOX and SO2 is uncertain. However, based on a preliminary assessment, Dominion has determined that the new 1-hour SO2 NAAQS will likely require significant future capital expenditures at State Line, and, accordingly, recorded an impairment charge on this facility in the second quarter of 2010. In January 2010, the EPA also proposed a new, more stringent NAAQS for ozone. Until the rulemaking for the Transport Rule is complete and the states have developed implementation plans for the new NO2, SO2 and ozone standards, it is not possible to determine the impact on Dominion’s or Virginia Power’s facilities that emit NOX and SO2. The Companies cannot currently predict with certainty whether or to what extent the new rules will ultimately require additional controls, however, if significant expenditures are required, it could adversely affect Dominion’s results of operations, and Dominion’s and Virginia Power’s cash flows.
In June 2005, the EPA finalized amendments to the Regional Haze Rule, also known as the Clean Air Visibility Rule. Although Dominion and Virginia Power anticipate that the emission reductions achieved through compliance with other CAA required programs will generally address this rule, additional emission reduction requirements may be imposed on the Companies’ facilities.
Implementation of projects to comply with SO2, NOX and mercury limitations, and other state emission control programs are ongoing and will be influenced by changes in the regulatory environment, availability of emission allowances and emission control technology. In response to federal and state regulatory requirements, Dominion and Virginia Power estimate that they will make capital expenditures at their affected generating facilities of approximately $2.4 billion and $2.0 billion, respectively, during the period 2011 through 2015.
In December 2010, the Virginia Department of Environmental Quality approved an air permit to construct the power station development project in Warren County, Virginia. In connection with the air permit process, 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.
In June 2010, the Conservation Law Foundation and Healthlink, Inc., filed a Complaint in the District Court of Massachusetts against Dominion Energy New England, Inc. alleging that Salem Harbor units 1, 2, 3, and 4 have been and are in violation of visible emissions standards and monitoring requirements of the Massachusetts State Implementation Plan and the station’s state and federal operating permits. Although Dominion cannot predict the outcome of this matter at this time, it is not expected to have a material effect on results of operations.
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, 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. In September 2009, the hazardous emissions air permit was amended by the Virginia Department of Environmental Quality to comply with the Richmond Circuit Court Order. The permit amendment does not impact the project. In October 2009, 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. In May 2010, the Court of Appeals affirmed the Circuit Court’s opinion in the appeal of the Virginia City Hybrid Energy Center’s air permit. SELC did not further appeal the Court of Appeals decision to the Supreme Court of Virginia.
WATER
The CWA is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. Dominion and Virginia Power must comply with all aspects of the CWA programs at their operating facilities. In July 2004, the EPA published regulations under CWA Section 316b that govern existing utilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold. The EPA’s rule presented several compliance options. However, in January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision on an appeal of the regulations, remanding the rule to the EPA. In July 2007, the EPA suspended the regulations pending further rulemaking, consistent with the decision issued by the U.S. Court of Appeals for the Second Circuit. In November 2007, a number of industries appealed the lower court decision to the U.S. Supreme Court. In April 2008, the
U.S. Supreme Court granted the industry request to review the question of whether Section 316b of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. The U.S. Supreme Court ruled in April 2009 that the EPA has the authority to consider costs versus environmental benefits in selecting best technology available for reducing impacts of cooling water intakes at power stations. It is currently unknown how the EPA will interpret the ruling in its ongoing rulemaking activity addressing cooling water intakes as well as how the states will implement this decision. Dominion has sixteen facilities, including eight at Virginia Power, that are likely to be subject to these regulations. In November 2010, the EPA settled with the original litigants and agreed to publish a proposed rule no later than March 14, 2011 and a final rule no later than July 27, 2012. Dominion and Virginia Power cannot predict the outcome of the EPA regulatory processes, nor can they determine with any certainty what specific controls may be required.
In August 2006, the CDEP issued a notice of a Tentative Determination to renew the NPDES permit for Millstone, which included a draft copy of the revised permit. In October 2007, CDEP issued a report to the hearing officer for the tentative determination stating the agency’s intent to further revise the draft permit. In December 2007, the CDEP issued a new draft permit. An administrative hearing on the draft permit began in January 2009 and was completed in February 2009. In February 2010, the hearing officer issued a proposed final decision, recommending that the CDEP Commissioner issue the revised draft permit without change. In September 2010, the permit was reissued under the CWA. The conditions of the permit require an evaluation of control technologies that could result in additional expenditures in the future, however Dominion cannot currently predict the outcome of this evaluation. In October 2010, the permit issuance was appealed to the state court by a private plaintiff. The permit is expected to remain in effect during the appeal.
In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. Currently, Dominion estimates the total cost to install these cooling towers at approximately $600 million, with remaining expenditures of $354 million included in its planned capital expenditures through 2012.
In October 2007, the VSWCB issued a renewed VPDES permit for North Anna. BREDL, and other persons, appealed the VSWCB’s decision to the Richmond Circuit Court, challenging several permit provisions related to North Anna’s discharge of cooling water. In February 2009, the court ruled that the VSWCB was required to regulate the thermal discharge from North Anna into the waste heat treatment facility. Virginia Power filed a motion for reconsideration with the court in February 2009, which was denied. The final order was issued by the court in September 2009. The court’s order allows North Anna to continue to operate pursuant to the currently issued VPDES permit. In October 2009, Virginia Power filed a Notice of Appeal of the court’s Order with the Richmond Circuit Court, initiating the appeals process to the Virginia Court of Appeals. In June 2010,
the Virginia Court of Appeals reversed the Richmond Circuit Court’s September 2009 order. The Virginia Court of Appeals held that the lower court had applied the wrong standard of review, and that the VSWCB’s determination not to regulate the station’s thermal discharge into the waste heat treatment facility was lawful. In July 2010, BREDL and the other original appellants filed a petition for appeal to the Supreme Court of Virginia requesting that it review the Court of Appeals’ decision. In December 2010, the Supreme Court of Virginia granted BREDL’s petition. Briefing on the merits of the case will occur during the first quarter of 2011. Until the appeals process is complete and any revised permit is issued, it is not possible to predict with certainty any financial impact that may result, however, an adverse resolution could have a material effect on Virginia Power’s cash flows.
SOLIDAND HAZARDOUS WASTE
The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be strictly, jointly and severally liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.
From time to time, Dominion or Virginia Power may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion or Virginia Power may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. The Companies do not believe that any currently identified sites will result in significant liabilities.
Dominion has determined that it is associated with 17 former manufactured gas plant sites. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the 17 former sites with which Dominion is associated is under investigation by any state or federal environmental agency. At one of the former sites Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program and Dominion has not yet estimated the future remediation costs. It is not known to what degree the other former sites may contain environmental contamination. Dominion
Combined Notes to Consolidated Financial Statements, Continued
is not able to estimate the cost, if any, that may be required for the possible remediation of these other sites.
In June 2010, the EPA proposed federal regulations under the RCRA for management of coal combustion by-products generated by power plants. The EPA is considering two possible options for the regulation of coal combustion by-products, both of which fall under the RCRA. Under the first proposal, the EPA would classify these by-products as special wastes subject to regulation under subtitle C, the hazardous waste provisions of the RCRA, when destined for disposal at landfills or surface impoundments. Under the second proposal, the EPA would regulate coal combustion by-products under subtitle D of the RCRA, the section for non-hazardous wastes. While the Companies cannot currently predict the outcome of this matter, regulation under either option will affect Dominion’s and Virginia Power’s onsite disposal facilities and coal combustion by-product management practices, and potentially require material investments.
CLIMATE CHANGE LEGISLATIONAND REGULATION
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.” On April 1, 2010, the EPA and the Department of Transportation’s National Highway Safety Administration announced a joint final rule establishing a program that will dramatically reduce GHG emissions and improve fuel economy for new cars and trucks sold in the United States. These rules took effect in January 2011 and established GHG emissions as regulated pollutants under the CAA. In May 2010, the EPA issued theFinal Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rulethat, combined with these prior actions, will require Dominion and Virginia Power to obtain permits for GHG emissions for new and modified facilities over certain size thresholds, and meet best available control technology for GHG emissions beginning in 2011. The EPA has issued draft guidance for GHG permitting, including best available control technology. EPA has also announced a schedule for proposing regulations of GHG emissions under the New Source Performance Standards that would apply to new and existing electric generating units. Also, the Companies expect continued regulatory action at the state level on the regulation of GHG emissions in the future. Any of these new or contemplated regulations above may affect capital costs, or create significant permitting delays, for new or modified facilities that emit GHGs.
There are other legislative proposals that may be considered that would have an indirect impact on GHG emissions. There is the potential for the Congress to consider a mandatory Clean Energy Standard or to promote greater energy efficiency through early retirements of coal-fired power plants.
In addition to possible federal action, some regions and states in which Dominion and Virginia Power operate have already adopted or may adopt GHG emission reduction programs. For example, the Virginia Energy Plan, released by the Governor of Virginia in September 2007, includes a goal of reducing GHG emissions state-wide back to 2000 levels by 2025. The Governor formed a Commission on Climate Change to develop a plan to achieve this goal. In November 2008, the Commission formulated its recommendations to the Governor.
In July 2008, Massachusetts passed the GWSA. Among other provisions, the GWSA sets economy-wide GHG emissions reduction goals for Massachusetts, including reductions of 10% to 25% below 1990 levels by 2020, interim goals for 2030 and 2040 and reductions of 80% below 1990 levels by 2050. Regulations requiring the implementation of the GWSA have not yet been proposed. Dominion operates two coal/oil-fired generating power stations in Massachusetts and acts as a retail electric supplier in Massachusetts and all of these entities are subject to the implementation of the GWSA.
Additionally, Massachusetts, Rhode Island and Connecticut, among other states, have joined the RGGI, a multi-state effort to reduce CO2 emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO2 emissions from power plants in participating states are required to be stabilized at current levels from 2009 to 2015. Further reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO2 emissions. During 2011 and possibly continuing through 2012, RGGI will undergo a program review which could impact regulations and implementation of RGGI. The impact of this program review on Dominion’s fossil fired generation operations in RGGI states is unknown at this time.
Three of Dominion’s facilities, Brayton Point, Salem Harbor and Manchester Street, are subject to RGGI. Beginning with calendar year 2009, RGGI requires that Dominion cover each ton of CO2 direct stack emissions from these facilities with either an allowance or an offset. The allowances can be purchased through auction or through a secondary market. Dominion participated in RGGI allowance auctions to date and has procured allowances to meet its estimated compliance requirements under RGGI for 2009 and 2010 and partially for 2011. Dominion does not expect these allowances to have a material impact on its results of operations or financial condition.
In December 2009, the governors of 11 Northeast and mid-Atlantic states, including Connecticut, Maryland, Massachusetts, New York, Pennsylvania, and Rhode Island (RGGI states plus Pennsylvania) signed a memorandum of understanding committing their states toward developing a low carbon fuel standard to reduce GHG emissions from vehicles. The memorandum of understanding establishes a process to develop a regional framework by 2011 and examine the economic impacts of a low carbon fuel standard program.
The U.S. is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change that became effective for signatories on February 16, 2005. The Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2009 United Nations Climate Change Conference in Copenhagen, Denmark, the Copenhagen Accord was adopted, which includes a collection of non-binding, voluntary actions by various countries, including the U.S, to keep the increase in global mean temperature below 2 degrees Celsius. It does not include specific emissions targets, but calls for industrial nations to offer up emissions reduction targets for 2020. The U.S. is expected to participate in this process.
Nuclear Operations
NUCLEAR DECOMMISSIONING—MINIMUM FINANCIAL ASSURANCE
The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 20102012 calculation for the NRC minimum financial assurance amount, aggregated for Dominion’s and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts, was $3.1$3.3 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 20102012 NRC minimum financial assurance amounts shown were calculated using September 30, 2010preliminary December 31, 2012 U.S. Bureau of Labor Statistics indices. The final NRC minimum financial assurance amounts that will be filed with the NRC in March 2011 will most likely be based on December 31, 2010 indices. Dominion does not anticipate a material difference between the NRC minimum financial assurance amounts shown and the final NRC minimum financial amounts to be filed with the NRC. Dominion believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover 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 a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be decommissionedcomplete for decades. Dominion and Virginia Power will continue to monitor these trusts to ensure they meet the minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC. See Note 6 to the Consolidated Financial Statements for additional information on Kewaunee.
NUCLEAR INSURANCE
The Price-Anderson Amendments Act of 1988 provides the public up to $12.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants. The Price-Anderson Amendments Act of 1988plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $118 million for each of their licensed reactors not to exceed $18 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.
The current level of property insurance coverage for Dominion’s and Virginia Power’s nuclear units is as follows:
Coverage | Coverage | |||||||
(billions) | ||||||||
Dominion | ||||||||
Millstone | $ | 2.75 | $ | 2.75 | ||||
Kewaunee | 1.80 | 1.80 | ||||||
Virginia Power | ||||||||
Virginia Power(1) | ||||||||
Surry | $ | 2.55 | $ | 2.55 | ||||
North Anna | 2.55 | 2.55 |
(1) | Surry and North Anna share a blanket property limit of $1 billion. |
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Combined Notes to Consolidated Financial Statements, Continued
The Companies’ coverage exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $77$89 million and $39$48 million, respectively. Based on the severity of the incident, the boardBoard of directorsDirectors of the nuclear insurerNEIL has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.
Dominion and Virginia Power also purchase insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, the Companies are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $32$33 million and $18$20 million, respectively.
During the fourth quarter of 2012, Dominion announced plans to close and decommission Kewaunee. Kewaunee is expected to cease power production in the second quarter of 2013 and commence decommissioning activities. Effective February 1, 2013, Kewaunee’s accidental outage policy for replacement power costs has been cancelled, and Kewaunee’s property coverage of $1.8 billion did not change. The cancellation of Kewaunee’s accidental outage policy for replacement power costs lowered Dominion’s retrospective premium assessment from $33 million to $30 million.
ODEC, a part owner of North Anna, and Massachusetts Municipal Wholesale Electric Company and Central Vermont Public ServiceGreen Mountain Power Corporation, part owners of Millstone’s Unit 3, are responsible to Dominion and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.
SPENT NUCLEAR FUEL
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.fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Companies’ contracts with the DOE. The Companies have previously received damages award payments and settlement payments related to these contracts.
Dominion and Virginia Power have resolved additional claims for damages incurred at Millstone, Kewaunee, Surry and North Anna. In May 2012, Dominion made formal offers of settlement to the Authorized Representative of the Attorney General for resolution of claims incurred at Millstone for the period July 1,
2006 through December 31, 2010 and periodic payments after that date through 2013 and for resolution of claims incurred at Kewaunee for the period January 2004,1, 2009 through December 31, 2010 and periodic payments after that date through 2013. In September 2012, Dominion and the government entered into settlement agreements. Initial settlement payments in the amounts of $20 million for Millstone and $6 million for Kewaunee were received in the fourth quarter of 2012. In September 2012, Virginia Power made a formal offer of settlement for resolution of claims incurred at Surry and North Anna for the period July 1, 2006 through December 31, 2010 and periodic payments after that date through 2013. In November 2012, Virginia Power and the government entered into a settlement agreement. An initial settlement payment in the amount of $75 million for Surry and North Anna was received in the fourth quarter of 2012. All of the settlement agreements are extendable after 2013 by mutual agreement of the parties. In June 2012, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims for Millstone, Surry and North Anna against the DOE requesting additional damages in connection with its failurefor the period July 1, 2006 through December 31, 2010. The lawsuits have been dismissed as a result of the settlement agreements.
The Companies continue to commence acceptingrecognize receivables for certain 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 incurredthat they believe are probable of recovery from the DOE. Dominion’s receivables for spent nuclear fuel-related costs totaled $36 million and $102 million 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 Appeals31, 2012 and 2011, respectively. Virginia Power’s receivables for the Federal Circuit and the appeal was docketed. In March 2009, the Federal Circuit granted the government’s
Combined Notes to Consolidated Financial Statements, Continued
request to stay the appeal. In May 2010, the stay 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 $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 2010totaled $26 million and oral argument took place before the Federal Circuit in January 2011. Payment of any damages will not occur until the appeal process has been resolved.
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$76 million at Kewaunee through December 31, 2008. The approximately $21 million settlement payment was received in September 2010.
2012 and 2011, respectively. 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 are probable of recovery from the DOE.
Guarantees, Surety Bonds and Letters of Credit
DOMINION
At December 31, 2010,2012, Dominion had issued $131$92 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2010,2012, Dominion’s exposure under these guarantees was $54$62 million, primarily related to certain reserve requirements associated with non-recourse financing. During the first quarter of 2010, Dominion’s $165 million limited-scope guarantee and indemnification for one-half of NedPower’s project-level financing, relating to litigation seeking to halt the NedPower wind farm, was formally terminated with the consent of NedPower’s lenders as a result of the dismissal by the applicable court of such litigation pursuant to an agreed dismissal order.
In addition to the above guarantees, Dominion and its partners, Shell and BP, may be required to make additional periodic equity contributions to NedPower and Fowler Ridge in connection with certain funding requirements associated with their respective non-recourse financings. As of December 31, 2010,2012, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $144$107 million through 2019 and its maximum annual future contributions could range from approximately $16$4 million to $19 million. Dominion expects the operating cash flows from these projects to be sufficient to meet their financing requirements.
Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion’s consolidated subsidiaries, that liability is included in itsthe Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once
obligations have been paid. Dominion currently believes it is
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unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.
At December 31, 2010,2012, Dominion had issued the following subsidiary guarantees:
Stated Limit | Value(1) | Stated Limit | Value(1) | |||||||||||||
(millions) | ||||||||||||||||
Subsidiary debt(2) | $ | 126 | $ | 126 | $ | 363 | $ | 363 | ||||||||
Commodity transactions(3) | 3,001 | 375 | 2,939 | 377 | ||||||||||||
Lease obligation for power generation facility(4) | 757 | 757 | ||||||||||||||
Nuclear obligations(5) | 231 | 52 | ||||||||||||||
Other | 498 | 126 | ||||||||||||||
Nuclear obligations(4) | 231 | 77 | ||||||||||||||
Other(5) | 673 | 98 | ||||||||||||||
Total | $ | 4,613 | $ | 1,436 | $ | 4,206 | $ | 915 |
(1) | Represents the estimated portion of the guarantee’s stated limit that is utilized as of December 31, |
(2) | Guarantees of debt of certain DEI subsidiaries. In the event of default by the subsidiaries, Dominion would be obligated to repay such amounts. |
(3) | Guarantees related to energy trading and marketing activities and other commodity commitments of certain subsidiaries, including subsidiaries of Virginia Power and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion would be obligated to satisfy such obligation. Dominion and its subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits. |
(4) |
Guarantees related to certain DEI subsidiaries’ potential retrospective premiums that could be assessed if there is a nuclear incident under Dominion’s nuclear insurance programs and guarantees for a DEI subsidiary’s and Virginia Power’s commitment to buy nuclear fuel. Excludes Dominion’s agreement to provide up to $150 million and $60 million to two DEI subsidiaries to pay the operating expenses of Millstone and Kewaunee, respectively, in the event of a prolonged outage, as part of satisfying certain NRC requirements concerned with ensuring adequate funding for the operations of nuclear power stations. The agreement for Kewaunee also provides for funds through the completion of decommissioning. |
(5) | Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. |
Additionally, as of December 31, 20102012 Dominion had purchased $87$163 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $136$26 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Dominion is obligated to indemnify the respective surety bond company for any amounts paid.
VIRGINIA POWER
As of December 31, 2010,2012, Virginia Power had issued $16$14 million of guarantees primarily to support tax-exempt debt issued through conduits. Virginia Power had also purchased $39$67 million of surety bonds for various purposes, including providing workers’ compensation coverage, and authorized the issuance of standby letters of credit by financial institutions of $91$2 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Virginia Power is obligated to indemnify the respective surety bond company for any amounts paid.
Indemnifications
As part of commercial contract negotiations in the normal course of business, Dominion and Virginia Power may sometimes agree
to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. Dominion and Virginia Power are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2010,2012, Dominion and Virginia Power believe future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.
Workforce Reduction Program
In the first quarter of 2010, Dominion and Virginia Power announced a workforce reduction program that reduced their total workforces by approximately 9% and 11%, respectively, during 2010. The goal of the workforce reduction program was to reduce operations and maintenance expense growth and further improve the efficiency of the Companies. In the first quarter of 2010, Dominion recorded a $338 million ($206 million after-tax) charge, including $202 million ($123 million after-tax) at Virginia Power, primarily reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other benefits related to the workforce reduction program. During 2010, Dominion and Virginia Power paid $109 million and $104 million, respectively, of costs related to the program. The terms of the workforce reduction program were consistent with the Companies’ existing severance plan.
NOTE 24.23. CREDIT RISK
Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.
Dominion and Virginia Power maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 20102012 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
GENERAL
DOMINION
As a diversified energy company, Dominion transacts primarily with major companies in the energy industry and with commercialcommer-
117
Combined Notes to Consolidated Financial Statements, Continued
cial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. and Texas. Dominion does not believe that this geo-
graphicgeographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.
Dominion’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include trading of energy-related commodities, marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2010,2012, Dominion’s gross credit exposure totaled $620 million. After the application of collateral, credit exposure is reduced to $591$512 million. Of this amount, investment grade counterparties, including those internally rated, represented 85%77%. One counterparty exposure represents 10%11% of Dominion’s total exposure and is a large financial institution rated investment grade.
VIRGINIA POWER
Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2010,2012, Virginia Power’s exposure to potential concentrations of credit risk was not considered material.
CREDIT-R-ELATEDRELATED CONTINGENT PROVISIONS
The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 20102012 and 2009,2011, Dominion would have been required to post an additional $88$110 million and $36$88 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual
terms. Dominion had posted $54$4 million in collateral at December 31, 2012 and $110 million in collateral, including $19$4 million of letters of credit at December 31, 2010 and $62
Combined Notes to Consolidated Financial Statements, Continued
million in collateral, including $48 million of letters of credit at December 31, 2009,2011, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 20102012 and 20092011 was $210$163 million and $181$259 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power were not material as of December 31, 2012 and 2011. See Note 87 for further information about derivative instruments.
NOTE 25. DOMINION CAPITAL, INC.
At December 31, 2007, DCI held an investment in the subordinated notes of a third-party CDO entity. The CDO entity’s primary focus is the purchase and origination of middle market senior secured first and second lien commercial and industrial loans in both the primary and secondary loan markets. Dominion concluded previously that the CDO entity was a VIE and that DCI was the primary beneficiary of the CDO entity and therefore Dominion consolidated the CDO entity at December 31, 2007.
In March 2008, Dominion reached an agreement to sell its remaining interest in the subordinated notes to a third party, effectively eliminating the variability of its interest, and therefore deconsolidated the CDO entity as of March 31, 2008 and recognized impairment losses of $62 million ($38 million after-tax), which were recorded in other operations and maintenance expense in its Consolidated Statement of Income. In connection with the sale of the subordinated notes, in April 2008, Dominion received proceeds of $54 million, including accrued interest. This sale concluded Dominion’s efforts to divest of DCI, since its remaining assets are aligned with Dominion’s core business.
NOTE 26.24. RELATED-PARTY TRANSACTIONS
Virginia Power engages in related-party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power is included in Dominion’s consolidated federal income tax return and participates in certain Dominion benefit plans. A discussion of significant related partyrelated-party transactions follows.
Transactions with Affiliates
Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps, and options, to manage commodity price risks associated with purchases of natural gas.
As of December 31, 2012 and 2011, Virginia Power’s derivative liabilities with affiliates were not material.
DRS providesand other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage. Presented below are significant transactions with DRS and other affiliates:
Year Ended December 31, | 2010 | 2009 | 2008 | 2012 | 2011 | 2010 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Commodity purchases from affiliates | $ | 373 | $ | 327 | $ | 527 | $ | 368 | $ | 376 | $ | 373 | ||||||||||||
Services provided by affiliates | 469 | 420 | 399 | 399 | 393 | 469 | ||||||||||||||||||
Services provided to affiliates | 19 | 21 | 19 |
During 2009,In the fourth quarter of 2011, a subsidiary of Virginia Power purchased turbinesnuclear fuel-related inventory from an affiliate for $58$39 million to be usedfor future use at its nuclear generation stations.
Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were $243 million in short-term demand note borrowings from Dominion as of December 31, 2012. There were no short-term demand note borrowings from Dominion as of December 31, 2011. Virginia
118 |
Power’s outstanding borrowings, net of repayments, under the Bear Garden power station, currently under construction.
The following table presentsDominion money pool for its nonregulated subsidiaries totaled $192 million and $187 million as of December 31, 2012 and 2011, respectively. Interest charges related to Virginia Power’s borrowings from Dominion under short-term arrangements:
At December 31, | 2010 | 2009 | ||||||
(millions) | ||||||||
Outstanding borrowings, net of repayments, under the Dominion money pool for Virginia Power’s nonregulated subsidiaries | $ | 24 | $ | 2 | ||||
Short-term demand note borrowings from Dominion | 79 | — |
Virginia Power incurred interest charges related to its borrowings from Dominion of $1 million, $5 million,were immaterial for the years ended December 31, 2012, 2011 and $10 million in 2010, 2009 and 2008, respectively.2010.
In 2010 2009 and 2008, Virginia Power issued 33,013 31,877 and 11,786 shares of its common stock to Dominion as settlement offor approximately $1 billion, $1 billion and $350 millionfor the purpose of retiring short-term demand note borrowings from Dominion, respectively.Dominion. There were no such issuances of common stock in 2011 and 2012.
NOTE 27.25. OPERATING SEGMENTS
Dominion and Virginia Power are organized primarily on the basis of products and services sold in the U.S. A description of the operations included in the Companies’ primary operating segments is as follows:
Primary Operating Segment | Description of Operations | Dominion | Virginia Power | |||||
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 | |||||||
In addition to the operating segments above, the Companies also report a Corporate and Other segment.
The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of Peoples and certain DCIthe operations that are expected to be or are currently discontinued, which are discussed in Notes 4 and 25, respectively.Note 3. 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.
DOMINION
In 2010,2012, Dominion reported after-tax net benefitsexpense of $837$1.4 billion for specific items in the Corporate and Other segment, with $1.4 billion of these net expenses attributable to its operating segments.
The net expenses for specific items in 2012 primarily related to the impact of the following items:
Ÿ | A $1.7 billion ($1.1 billion after-tax) net loss from operations, including an impairment charge, of Brayton Point, Kincaid and Elwood, attributable to Dominion Generation. Dominion announced its intention to pursue the sale of these two merchant power stations and equity method investment in the third quarter of 2012; |
Ÿ | A $467 million ($303 million after-tax) net loss, including impairment charges, primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013, attributable to Dominion Generation; |
Ÿ | An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP; and |
Ÿ | A $49 million ($22 million after-tax) loss from discontinued operations of State Line and Salem Harbor which were sold in 2012, attributable to Dominion Generation. |
In 2011, Dominion reported after-tax net expense of $311 million for specific items in the Corporate and Other segment, with $1$340 million of these net expenses attributable to its operating segments.
The net expenses for specific items in 2011 primarily related to the impact of the following items:
Ÿ | A $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units, attributable to Dominion Generation; |
Ÿ | A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP; |
Ÿ | A $66 million ($39 million after-tax) loss from the operations of Kewaunee, attributable to Dominion Generation; |
Ÿ | A $57 million ($34 million after-tax) charge related to the impairment of SO2 emissions allowances not expected to be consumed due to CSAPR, attributable to Dominion Generation; and |
Ÿ | A $34 million ($25 million after-tax) loss from discontinued operations of State Line and Salem Harbor which were sold in 2012, attributable to Dominion Generation. |
In 2010, Dominion reported after-tax net benefits of $865 million for specific items in the Corporate and Other segment, with $1.0 billion of these net benefits attributable to its operating segments.
The net benefits for specific items in 2010 primarily related to the impact of the following items:
Ÿ | A $2.5 billion ($1.4 billion after-tax) benefit resulting from the gain on the sale of substantially all of Dominion’s Appalachian E&P operations net of charges related to the divestiture, attributable to Dominion Energy; partially offset by |
Ÿ | A |
Ÿ | DVP ($67 million after-tax); |
Ÿ | Dominion Energy ($24 million after-tax); and |
Ÿ | Dominion Generation ($ |
Ÿ | A $158 million ($103 million after-tax) loss from the discontinued operations of State Line and Salem Harbor; and |
Ÿ | A $134 million ($155 million after-tax) loss from the discontinued operations of Peoples primarily reflecting a net loss on the sale, attributable to the Corporate and Other |
|
In 2009, Dominion reported after-tax net expenses of $655 million for specific items in the Corporate and Other segment, with $688 million of these net expenses attributable to its operating segments.
The net expenses for specific items in 2009 primarily related to the impact of the following items:
|
|
|
|
In 2008, Dominion reported after-tax net expenses of $3 million for specific items in the Corporate and Other segment, with $134 million of these net expenses attributable to its operating segments.
The net expenses for specific items in 2008 primarily related to the impact of the following items:
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|
|
|
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Combined Notes to Consolidated Financial Statements, Continued
The following table presents segment information pertaining to Dominion’s operations:
Year Ended December 31, | DVP | Dominion Generation | Dominion Energy | Corporate and Other | Adjustments & Eliminations | Consolidated Total | DVP | Dominion Generation(1) | Dominion Energy | Corporate and Other(1) | Adjustments & Eliminations | Consolidated Total | ||||||||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total revenue from external customers | $ | 3,385 | $ | 6,517 | $ | 1,813 | $ | 307 | $ | 1,071 | $ | 13,093 | ||||||||||||||||||||||||||||||||||||
Intersegment revenue | 112 | 333 | 930 | 608 | (1,983 | ) | — | |||||||||||||||||||||||||||||||||||||||||
Total operating revenue | 3,497 | 6,850 | 2,743 | 915 | (912 | ) | 13,093 | |||||||||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 402 | 500 | 216 | 68 | — | 1,186 | ||||||||||||||||||||||||||||||||||||||||||
Equity in earnings of equity method investees | — | 3 | 23 | (1 | ) | — | 25 | |||||||||||||||||||||||||||||||||||||||||
Interest income | 9 | 57 | 30 | 71 | (106 | ) | 61 | |||||||||||||||||||||||||||||||||||||||||
Interest and related charges | 187 | 208 | 47 | 546 | (106 | ) | 882 | |||||||||||||||||||||||||||||||||||||||||
Income taxes | 351 | 479 | 352 | (1,036 | ) | — | 146 | |||||||||||||||||||||||||||||||||||||||||
Loss from discontinued operations, net of tax | — | — | — | (22 | ) | — | (22 | ) | ||||||||||||||||||||||||||||||||||||||||
Net income (loss) attributable to Dominion | 559 | 874 | 551 | (1,682 | ) | — | 302 | |||||||||||||||||||||||||||||||||||||||||
Investment in equity method investees | 1 | 414 | 141 | 2 | — | 558 | ||||||||||||||||||||||||||||||||||||||||||
Capital expenditures | 1,158 | 1,615 | 1,350 | 22 | — | 4,145 | ||||||||||||||||||||||||||||||||||||||||||
Total assets (billions) | 12.1 | 21.2 | 11.2 | 12.6 | (10.3 | ) | 46.8 | |||||||||||||||||||||||||||||||||||||||||
2011 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total revenue from external customers | $ | 3,663 | $ | 7,080 | $ | 2,044 | $ | 55 | $ | 1,303 | $ | 14,145 | ||||||||||||||||||||||||||||||||||||
Intersegment revenue | 173 | 355 | 1,077 | 596 | (2,201 | ) | — | |||||||||||||||||||||||||||||||||||||||||
Total operating revenue | 3,836 | 7,435 | 3,121 | 651 | (898 | ) | 14,145 | |||||||||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 374 | 457 | 207 | 28 | — | 1,066 | ||||||||||||||||||||||||||||||||||||||||||
Equity in earnings of equity method investees | — | 3 | 23 | 9 | — | 35 | ||||||||||||||||||||||||||||||||||||||||||
Interest income | 22 | 54 | 27 | 70 | (106 | ) | 67 | |||||||||||||||||||||||||||||||||||||||||
Interest and related charges | 185 | 217 | 57 | 514 | (106 | ) | 867 | |||||||||||||||||||||||||||||||||||||||||
Income taxes | 318 | 583 | 323 | (470 | ) | — | 754 | |||||||||||||||||||||||||||||||||||||||||
Loss from discontinued operations, net of tax | — | — | — | (25 | ) | — | (25 | ) | ||||||||||||||||||||||||||||||||||||||||
Net income (loss) attributable to Dominion | 501 | 968 | 521 | (582 | ) | — | 1,408 | |||||||||||||||||||||||||||||||||||||||||
Investment in equity method investees | 8 | 415 | 104 | 26 | — | 553 | ||||||||||||||||||||||||||||||||||||||||||
Capital expenditures | 1,091 | 1,593 | 907 | 61 | — | 3,652 | ||||||||||||||||||||||||||||||||||||||||||
Total assets (billions) | 11.5 | 22.1 | 10.6 | 11.4 | (10.0 | ) | 45.6 | |||||||||||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total revenue from external customers | $ | 3,613 | $ | 8,005 | $ | 2,335 | $ | 19 | $ | 1,225 | $ | 15,197 | $ | 3,613 | $ | 7,735 | $ | 2,335 | $ | 19 | $ | 1,225 | $ | 14,927 | ||||||||||||||||||||||||
Intersegment revenue | 207 | 413 | 1,166 | 750 | (2,536 | ) | — | 207 | 413 | 1,166 | 750 | (2,536 | ) | — | ||||||||||||||||||||||||||||||||||
Total operating revenue | 3,820 | 8,418 | 3,501 | 769 | (1,311 | ) | 15,197 | 3,820 | 8,148 | 3,501 | 769 | (1,311 | ) | 14,927 | ||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 353 | 462 | 210 | 30 | — | 1,055 | 353 | 443 | 210 | 29 | — | 1,035 | ||||||||||||||||||||||||||||||||||||
Equity in earnings of equity method investees | — | 11 | 21 | 10 | — | 42 | — | 11 | 21 | 10 | — | 42 | ||||||||||||||||||||||||||||||||||||
Interest income | 12 | 45 | 12 | 92 | (90 | ) | 71 | 12 | 45 | 12 | 92 | (90 | ) | 71 | ||||||||||||||||||||||||||||||||||
Interest and related charges | 158 | 185 | 85 | 494 | (90 | ) | 832 | 158 | 179 | 85 | 494 | (90 | ) | 826 | ||||||||||||||||||||||||||||||||||
Income taxes | 277 | 771 | 302 | 707 | — | 2,057 | 277 | 756 | 302 | 777 | — | 2,112 | ||||||||||||||||||||||||||||||||||||
Loss from discontinued operations, net of tax | — | — | — | (155 | ) | — | (155 | ) | — | — | — | (258 | ) | — | (258 | ) | ||||||||||||||||||||||||||||||||
Net income attributable to Dominion | 448 | 1,291 | 475 | 594 | — | 2,808 | 448 | 1,263 | 475 | 622 | — | 2,808 | ||||||||||||||||||||||||||||||||||||
Investment in equity method investees | 8 | 426 | 106 | 31 | — | 571 | ||||||||||||||||||||||||||||||||||||||||||
Capital expenditures | 1,038 | 1,742 | 613 | 29 | — | 3,422 | 1,038 | 1,742 | 613 | 29 | — | 3,422 | ||||||||||||||||||||||||||||||||||||
Total assets (billions) | 10.8 | 20.4 | 9.7 | 10.8 | (8.9 | ) | 42.8 | |||||||||||||||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total revenue from external customers | $ | 3,107 | $ | 8,390 | $ | 2,604 | $ | (472 | ) | $ | 1,169 | $ | 14,798 | |||||||||||||||||||||||||||||||||||
Intersegment revenue | 174 | 361 | 1,206 | 711 | (2,452 | ) | — | |||||||||||||||||||||||||||||||||||||||||
Total operating revenue | 3,281 | 8,751 | 3,810 | 239 | (1,283 | ) | 14,798 | |||||||||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 341 | 492 | 258 | 47 | — | 1,138 | ||||||||||||||||||||||||||||||||||||||||||
Equity in earnings of equity method investees | — | 8 | 21 | 13 | — | 42 | ||||||||||||||||||||||||||||||||||||||||||
Interest income | 13 | 49 | 16 | 129 | (118 | ) | 89 | |||||||||||||||||||||||||||||||||||||||||
Interest and related charges | 159 | 201 | 113 | 534 | (118 | ) | 889 | |||||||||||||||||||||||||||||||||||||||||
Income taxes | 233 | 694 | 319 | (650 | ) | — | 596 | |||||||||||||||||||||||||||||||||||||||||
Income from discontinued operations, net of tax | — | — | — | 26 | — | 26 | ||||||||||||||||||||||||||||||||||||||||||
Net income (loss) attributable to Dominion | 384 | 1,281 | 517 | (895 | ) | — | 1,287 | |||||||||||||||||||||||||||||||||||||||||
Investment in equity method investees | 9 | 439 | 102 | 45 | — | 595 | ||||||||||||||||||||||||||||||||||||||||||
Capital expenditures | 841 | 2,140 | 737 | 119 | — | 3,837 | ||||||||||||||||||||||||||||||||||||||||||
Total assets (billions) | 9.8 | 18.7 | 10.1 | 12.6 | (8.6 | ) | 42.6 | |||||||||||||||||||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total revenue from external customers | $ | 2,977 | $ | 8,569 | $ | 2,641 | $ | (4 | ) | $ | 1,712 | $ | 15,895 | |||||||||||||||||||||||||||||||||||
Intersegment revenue | 134 | 102 | 1,829 | 740 | (2,805 | ) | — | |||||||||||||||||||||||||||||||||||||||||
Total operating revenue | 3,111 | 8,671 | 4,470 | 736 | (1,093 | ) | 15,895 | |||||||||||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 312 | 423 | 284 | 17 | (2 | ) | 1,034 | |||||||||||||||||||||||||||||||||||||||||
Equity in earnings of equity method investees | — | 27 | 17 | 8 | — | 52 | ||||||||||||||||||||||||||||||||||||||||||
Interest income | 22 | 78 | 35 | 136 | (167 | ) | 104 | |||||||||||||||||||||||||||||||||||||||||
Interest and related charges | 149 | 230 | 141 | 476 | (167 | ) | 829 | |||||||||||||||||||||||||||||||||||||||||
Income taxes | 232 | 688 | 283 | (250 | ) | — | 953 | |||||||||||||||||||||||||||||||||||||||||
Income from discontinued operations, net of tax | — | — | — | 190 | — | 190 | ||||||||||||||||||||||||||||||||||||||||||
Net income (loss) attributable to Dominion | 380 | 1,227 | 470 | (243 | ) | — | 1,834 | |||||||||||||||||||||||||||||||||||||||||
Capital expenditures | 797 | 1,665 | 940 | 152 | — | 3,554 |
(1) | Segment information has been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3. |
At December 31, 2010, 2009,2012, 2011, and 2008,2010, none of Dominion’s long-lived assets and no significant percentage of its operating revenues were associated with international operations.
120 |
VIRGINIA POWER
The majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s DVP and Dominion Generation segments.
In 2012, Virginia Power reported after-tax net expenses of $51 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2012 primarily related to the impact of the following:
Ÿ | An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP. |
In 2011, Virginia Power reported after-tax net expenses of $268 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2011 primarily related to the impact of the following:
Ÿ | A $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired generating units, attributable to Dominion Generation; |
Ÿ | A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP; and |
Ÿ | A $43 million ($26 million after-tax) charge related to the impairment of SO2 emissions allowances not expected to be consumed due to CSAPR, attributable to Dominion Generation. |
In 2010, Virginia Power reported after-tax net expenses of $153 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net expenses for specific items in 2010 primarily related to the impact of the following:
Ÿ | A $202 million ($123 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program, attributable to: |
Ÿ | DVP ($63 million after-tax); and |
Ÿ | Dominion Generation ($60 million after-tax). |
In 2009, Virginia Power reported after-tax net expenses of $430 million for specific items attributable to its operating segments in the Corporate and Other segment. The net expenses primarily related to a $700 million ($427 million after-tax) charge in connection with the settlement of the 2009 base rate case proceedings, attributable to Dominion Generation ($257 million after-tax) and DVP ($170 million after-tax).
In 2008, Virginia Power’s Corporate and Other segment included $23 million of net after-tax expenses attributable to its Dominion Generation segment. The net expenses in 2008 primarily related to impairment charges of $18 million ($11 million after-tax) related to non-refundable deposits for certain generation-related vendor contracts and $8 million ($5 million after-tax) reflecting other-than-temporary declines in the fair value of securities held as investments in nuclear decommissioning trusts.
The following table presents segment information pertaining to Virginia Power’s operations:
Year Ended December 31, | DVP | Dominion Generation | Corporate and Other | Adjustments & Eliminations | Consolidated Total | DVP | Dominion Generation | Corporate and Other | Adjustments & Eliminations | Consolidated Total | ||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 1,847 | $ | 5,379 | $ | — | $ | — | $ | 7,226 | ||||||||||||||||||||||||||||||
Depreciation and amortization | 392 | 390 | — | — | 782 | |||||||||||||||||||||||||||||||||||
Interest income | 1 | 7 | — | — | 8 | |||||||||||||||||||||||||||||||||||
Interest and related charges | 186 | 199 | — | — | 385 | |||||||||||||||||||||||||||||||||||
Income taxes | 277 | 403 | (27 | ) | — | 653 | ||||||||||||||||||||||||||||||||||
Net income (loss) | 448 | 653 | (51 | ) | — | 1,050 | ||||||||||||||||||||||||||||||||||
Capital expenditures | 1,142 | 1,146 | — | — | 2,288 | |||||||||||||||||||||||||||||||||||
Total assets (billions) | 11.4 | 14.8 | — | (1.4 | ) | 24.8 | ||||||||||||||||||||||||||||||||||
2011 | ||||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 1,793 | $ | 5,546 | $ | (93 | ) | $ | — | $ | 7,246 | |||||||||||||||||||||||||||||
Depreciation and amortization | 368 | 350 | — | — | 718 | |||||||||||||||||||||||||||||||||||
Interest income | 10 | 8 | — | — | 18 | |||||||||||||||||||||||||||||||||||
Interest and related charges | 182 | 199 | (50 | ) | — | 331 | ||||||||||||||||||||||||||||||||||
Income taxes | 265 | 447 | (172 | ) | — | 540 | ||||||||||||||||||||||||||||||||||
Net income (loss) | 426 | 664 | (268 | ) | — | 822 | ||||||||||||||||||||||||||||||||||
Capital expenditures | 1,081 | 1,009 | — | — | 2,090 | |||||||||||||||||||||||||||||||||||
Total assets (billions) | 10.7 | 14.3 | — | (1.5 | ) | 23.5 | ||||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 1,680 | $ | 5,546 | $ | (7 | ) | $ | — | $ | 7,219 | $ | 1,680 | $ | 5,546 | $ | (7 | ) | $ | — | $ | 7,219 | ||||||||||||||||||
Depreciation and amortization | 344 | 327 | — | — | 671 | 344 | 327 | — | — | 671 | ||||||||||||||||||||||||||||||
Interest income | 11 | 4 | — | — | 15 | 11 | 4 | — | — | 15 | ||||||||||||||||||||||||||||||
Interest and related charges | 158 | 189 | — | — | 347 | 158 | 189 | — | — | 347 | ||||||||||||||||||||||||||||||
Income taxes | 228 | 385 | (71 | ) | — | 542 | 228 | 385 | (71 | ) | — | 542 | ||||||||||||||||||||||||||||
Net income (loss) | 377 | 630 | (155 | ) | — | 852 | 377 | 630 | (155 | ) | — | 852 | ||||||||||||||||||||||||||||
Capital expenditures | 1,035 | 1,199 | — | — | 2,234 | 1,035 | 1,199 | — | — | 2,234 | ||||||||||||||||||||||||||||||
Total assets (billions) | 9.9 | 13.8 | — | (1.4 | ) | 22.3 | ||||||||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 1,465 | $ | 5,560 | $ | (441 | ) | $ | — | $ | 6,584 | |||||||||||||||||||||||||||||
Depreciation and amortization | 320 | 320 | 1 | — | 641 | |||||||||||||||||||||||||||||||||||
Interest income | 11 | 6 | — | — | 17 | |||||||||||||||||||||||||||||||||||
Interest and related charges | 158 | 191 | — | — | 349 | |||||||||||||||||||||||||||||||||||
Income taxes | 183 | 241 | (277 | ) | — | 147 | ||||||||||||||||||||||||||||||||||
Net income (loss) | 313 | 475 | (432 | ) | — | 356 | ||||||||||||||||||||||||||||||||||
Capital expenditures | 839 | 1,649 | — | — | 2,488 | |||||||||||||||||||||||||||||||||||
Total assets (billions) | 9.0 | 12.3 | — | (1.2 | ) | 20.1 | ||||||||||||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 1,439 | $ | 5,478 | $ | 17 | $ | — | $ | 6,934 | ||||||||||||||||||||||||||||||
Depreciation and amortization | 310 | 298 | — | — | 608 | |||||||||||||||||||||||||||||||||||
Interest income | 15 | 9 | — | (3 | ) | 21 | ||||||||||||||||||||||||||||||||||
Interest and related charges | 144 | 167 | 1 | (3 | ) | 309 | ||||||||||||||||||||||||||||||||||
Income taxes | 182 | 331 | (13 | ) | — | 500 | ||||||||||||||||||||||||||||||||||
Net income (loss) | 307 | 583 | (26 | ) | — | 864 | ||||||||||||||||||||||||||||||||||
Capital expenditures | 792 | 1,245 | — | — | 2,037 |
121 |
Combined Notes to Consolidated Financial Statements, Continued
NOTE 28.26. QUARTERLY FINANCIALAND COMMON STOCK DATA (UNAUDITED)
A summary of Dominion’s and Virginia Power’s quarterly results of operations for the years ended December 31, 20102012 and 20092011 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.
DOMINION
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year | ||||||||||||||||
(millions, except per share amounts) | ||||||||||||||||||||
2010 | ||||||||||||||||||||
Operating revenue | $ | 4,168 | $ | 3,333 | $ | 3,950 | $ | 3,746 | $ | 15,197 | ||||||||||
Income from operations | 734 | 3,110 | 1,119 | 737 | 5,700 | |||||||||||||||
Income from continuing operations(1) | 323 | 1,759 | 575 | 306 | 2,963 | |||||||||||||||
Income (loss) from discontinued operations(1) | (149 | ) | 2 | — | (8 | ) | (155 | ) | ||||||||||||
Net income including noncontrolling interests | 178 | 1,765 | 579 | 303 | 2,825 | |||||||||||||||
Net income attributable to Dominion | 174 | 1,761 | 575 | 298 | 2,808 | |||||||||||||||
Basic EPS: | ||||||||||||||||||||
Income from continuing operations(1) | 0.54 | 2.98 | 0.98 | 0.53 | 5.03 | |||||||||||||||
Income (loss) from discontinued operations(1) | (0.25 | ) | — | — | (0.01 | ) | (0.26 | ) | ||||||||||||
Net income attributable to Dominion | 0.29 | 2.98 | 0.98 | 0.52 | 4.77 | |||||||||||||||
Diluted EPS: | ||||||||||||||||||||
Income from continuing operations(1) | 0.54 | 2.98 | 0.98 | 0.52 | 5.02 | |||||||||||||||
Income (loss) from discontinued operations(1) | (0.25 | ) | — | — | (0.01 | ) | (0.26 | ) | ||||||||||||
Net income attributable to Dominion | 0.29 | 2.98 | 0.98 | 0.51 | 4.76 | |||||||||||||||
Dividends paid per share | 0.4575 | 0.4575 | 0.4575 | 0.4575 | 1.83 | |||||||||||||||
Common stock prices (intraday high-low) | $ | 41.61 - 36.12 | | $ | 42.56 - 38.05 | | $ | 44.94 38.59 | | $ | 45.12 - 41.13 | | $ | 45.12 - 36.12 | |
First Quarter(2) | Second Quarter | Third Quarter | Fourth Quarter | Full Year | ||||||||||||||||
(millions, except per share amounts) | ||||||||||||||||||||
2012 | ||||||||||||||||||||
Operating revenue | $ | 3,462 | $ | 3,053 | $ | 3,411 | $ | 3,167 | $ | 13,093 | ||||||||||
Income (loss) from operations | 913 | 617 | 518 | (892 | ) | 1,156 | ||||||||||||||
Net income (loss) including noncontrolling interests | 501 | 265 | 215 | (652 | ) | 329 | ||||||||||||||
Income (loss) from continuing operations(1) | 493 | 276 | 214 | (659 | ) | 324 | ||||||||||||||
Income (loss) from discontinued operations(1) | 1 | (18 | ) | (5 | ) | — | (22 | ) | ||||||||||||
Net income (loss) attributable to Dominion | 494 | 258 | 209 | (659 | ) | 302 | ||||||||||||||
Basic EPS: | ||||||||||||||||||||
Income (loss) from continuing operations(1) | 0.86 | 0.48 | 0.37 | (1.15 | ) | 0.57 | ||||||||||||||
Income (loss) from discontinued operations(1) | — | (0.03 | ) | (0.01 | ) | — | (0.04 | ) | ||||||||||||
Net income (loss) attributable to Dominion | 0.86 | 0.45 | 0.36 | (1.15 | ) | 0.53 | ||||||||||||||
Diluted EPS: | ||||||||||||||||||||
Income (loss) from continuing operations(1) | 0.86 | 0.48 | 0.37 | (1.15 | ) | 0.57 | ||||||||||||||
Loss from discontinued operations(1) | — | (0.03 | ) | (0.01 | ) | — | (0.04 | ) | ||||||||||||
Net income (loss) attributable to Dominion | 0.86 | 0.45 | 0.36 | (1.15 | ) | 0.53 | ||||||||||||||
Dividends declared per share | 0.5275 | 0.5275 | 0.5275 | 0.5275 | 2.11 | |||||||||||||||
Common stock prices (intraday high-low) | $ | 53.68 - 48.87 | | $ | 54.69 - 49.87 | | $ | 55.62 - 52.15 | | $ | 53.89 - 48.94 | | $ | 55.62 - 48.87 | |
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year | |||||||||||||||||||||||||||||||
(millions, except per share amounts) | ||||||||||||||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||||||||||
2011(2) | ||||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 4,586 | $ | 3,406 | $ | 3,630 | $ | 3,176 | $ | 14,798 | $ | 3,983 | $ | 3,288 | $ | 3,745 | $ | 3,129 | $ | 14,145 | ||||||||||||||||||||
Income from operations | 664 | 889 | 1,088 | (72 | ) | 2,569 | 993 | 733 | 828 | 340 | 2,894 | |||||||||||||||||||||||||||||
Income from continuing operations(1) | 239 | 469 | 635 | (82 | ) | 1,261 | ||||||||||||||||||||||||||||||||||
Income (loss) from discontinued operations(1) | 9 | (15 | ) | (41 | ) | 73 | 26 | |||||||||||||||||||||||||||||||||
Net income including noncontrolling interests | 252 | 458 | 598 | (4 | ) | 1,304 | 483 | 340 | 396 | 207 | 1,426 | |||||||||||||||||||||||||||||
Net income attributable to Dominion | 248 | 454 | 594 | (9 | ) | 1,287 | ||||||||||||||||||||||||||||||||||
Basic and Diluted EPS: | ||||||||||||||||||||||||||||||||||||||||
Income from continuing operations(1) | 0.41 | 0.79 | 1.07 | (0.13 | ) | 2.13 | 504 | 341 | 388 | 200 | 1,433 | |||||||||||||||||||||||||||||
Income (loss) from discontinued operations(1) | 0.01 | (0.03 | ) | (0.07 | ) | 0.12 | 0.04 | (25 | ) | (5 | ) | 4 | 1 | (25 | ) | |||||||||||||||||||||||||
Net income attributable to Dominion | 0.42 | 0.76 | 1.00 | (0.01 | ) | 2.17 | 479 | 336 | 392 | 201 | 1,408 | |||||||||||||||||||||||||||||
Dividends paid per share | 0.4375 | 0.4375 | 0.4375 | 0.4375 | 1.75 | |||||||||||||||||||||||||||||||||||
Basic EPS: | ||||||||||||||||||||||||||||||||||||||||
Income from continuing operations(1) | 0.87 | 0.59 | 0.68 | 0.35 | 2.50 | |||||||||||||||||||||||||||||||||||
Income (loss) from discontinued operations(1) | (0.04 | ) | (0.01 | ) | 0.01 | — | (0.04 | ) | ||||||||||||||||||||||||||||||||
Net income attributable to Dominion | 0.83 | 0.58 | 0.69 | 0.35 | 2.46 | |||||||||||||||||||||||||||||||||||
Diluted EPS: | ||||||||||||||||||||||||||||||||||||||||
Income from continuing operations(1) | 0.86 | 0.59 | 0.68 | 0.35 | 2.49 | |||||||||||||||||||||||||||||||||||
Income (loss) from discontinued operations(1) | (0.04 | ) | (0.01 | ) | 0.01 | — | (0.04 | ) | ||||||||||||||||||||||||||||||||
Net income attributable to Dominion | 0.82 | 0.58 | 0.69 | 0.35 | 2.45 | |||||||||||||||||||||||||||||||||||
Dividends declared per share | 0.4925 | 0.4925 | 0.4925 | 0.4925 | 1.97 | |||||||||||||||||||||||||||||||||||
Common stock prices (intraday high-low) | $ | 37.18 - 27.15 | | $ | 33.93 - 28.70 | | $ | 34.84 - 32.10 | | $ | 39.79 - 33.15 | | $ | 39.79 - 27.15 | | $ | 46.56 - 42.06 | | $ | 48.55 - 43.27 | | $ | 51.44 - 44.50 | | $ | 53.59 - 48.21 | | $ | 53.59 - 42.06 | |
(1) | Amounts attributable to Dominion’s common shareholders. |
(2) | Revenue and income amounts have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3. |
Dominion’s 20102012 results include the impact of the following significant items:
Ÿ |
|
Ÿ |
|
Dominion’s 20092011 results include the impact of the following significant items:item:
Ÿ |
|
122 |
|
|
|
VIRGINIA POWER
Virginia Power’s quarterly results of operations were as follows:
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Year | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Year | |||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 1,739 | $ | 1,711 | $ | 2,111 | $ | 1,658 | $ | 7,219 | $ | 1,754 | $ | 1,756 | $ | 2,086 | $ | 1,630 | $ | 7,226 | ||||||||||||||||||||
Income from operations | 254 | 479 | 673 | 235 | 1,641 | 468 | 361 | 746 | 417 | 1,992 | ||||||||||||||||||||||||||||||
Net income | 95 | 267 | 380 | 110 | 852 | 243 | 172 | 415 | 220 | 1,050 | ||||||||||||||||||||||||||||||
Balance available for common stock | 91 | 263 | 376 | 105 | 835 | 239 | 168 | 411 | 216 | 1,034 | ||||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||||||||||
2011 | ||||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 1,859 | $ | 1,675 | $ | 1,938 | $ | 1,112 | $ | 6,584 | $ | 1,757 | $ | 1,757 | $ | 2,177 | $ | 1,555 | $ | 7,246 | ||||||||||||||||||||
Income (loss) from operations | 402 | 299 | 554 | (507 | ) | 748 | ||||||||||||||||||||||||||||||||||
Net income (loss) | 204 | 149 | 315 | (312 | ) | 356 | ||||||||||||||||||||||||||||||||||
Income from operations | 511 | 471 | 568 | 55 | 1,605 | |||||||||||||||||||||||||||||||||||
Net income | 278 | 241 | 297 | 6 | 822 | |||||||||||||||||||||||||||||||||||
Balance available for common stock | 200 | 145 | 311 | (317 | ) | 339 | 274 | 237 | 293 | 1 | 805 |
Virginia Power’s 20102012 results include the impact of the following significant item:
Ÿ |
|
Virginia Power’s 20092011 results include the impact of the following significant item:
Ÿ | Fourth quarter results include a |
123
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
DOMINION
Senior management, including Dominion’s CEO and CFO, evaluated the effectiveness of Dominion’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion’s CEO and CFO have concluded that Dominion’s disclosure controls and procedures are effective. There were no changes in Dominion’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion’s internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORTON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Dominion Resources, Inc. (Dominion) understands and accepts responsibility for Dominion’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion does throughout all aspects of its business.
Dominion maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.
The Audit Committee of the Board of Directors of Dominion, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.
SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion’s 20102012 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2010,2012, Dominion makes the following assertion:assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Dominion’s internal control over financial reporting as of December 31, 2010.2012. This assessment was based on criteria for effective internal control over financial reporting described inInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Managementmanagement believes that Dominion maintained effective internal control over financial reporting as of December 31, 2010.2012.
Dominion’s independent registered public accounting firm is engaged to express an opinion on Dominion’s internal control over financial reporting, as stated in their report which is included herein.
February 25, 201127, 2013
124 |
REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the internal control over financial reporting of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2010,2012, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Dominion’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s boardBoard of directors,Directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes
in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Dominion maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010,2012, based on the criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 20102012 of Dominion and our report dated February 25, 2011,27, 2013, expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 25, 201127, 2013
125
VIRGINIA POWER
Senior management, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes in Virginia Power’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Power’s internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORTON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Virginia Electric and Power Company (Virginia Power) understands and accepts responsibility for Virginia Power’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Virginia Power continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.
Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.
The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.
SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s 20102012 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2010,2012, Virginia Power makes the following assertion:assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Virginia Power’s internal control over financial reporting as of December 31, 2010.2012. This assessment was based on criteria for effective internal control over financial reporting described inInternal Control-IntegratedControl—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Managementmanagement believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2010.2012.
This annual report does not include an attestation report of Virginia Power’s registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.
February 25, 201127, 2013
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None.Explanatory Note: The following information is furnished in this Form 10-K in lieu of being furnished pursuant to Item 2.02 in a Form 8-K. The date of the events reported below wasFebruary 28, 2013.
On January 31, 2013, Dominion issued its 4th Quarter 2012 Earnings Release Kit reporting unaudited earnings determined in accordance with GAAP for the 12 months ended December 31, 2012, and a fourth quarter impairment charge related to Brayton Point. On February 28, 2013, Dominion issued a revised 4th Quarter 2012 Earnings Release Kit to reflect a reduction in reported earnings for the 12 months ended December 31, 2012. The reduction relates to an additional impairment charge associated with Dominion’s merchant power stations being marketed for sale. For more information on the impairment charge, see Note 6 to the Consolidated Financial Statements, which information is incorporated herein by reference. The revised Earnings Release Kit reflecting the reduction in earnings and supplemental schedules are furnished with this Form 10-K as Exhibits 99.1 and 99.2, respectively.
Item 10. Directors, Executive Officers and Corporate Governance
DOMINION
The following information for Dominion is incorporated by reference from the 2011Dominion 2013 Proxy Statement, File No. 001-08489, which will be filed on or around March 31, 2011 (the 2011 Proxy Statement):19, 2013:
Ÿ | Information regarding the directors required by this item is found under the headingElection of Directors. |
Ÿ | Information regarding compliance with Section 16 of the Securities Exchange Act of 1934, as amended, required by this item is found under the headingSection 16(a) Beneficial Ownership Reporting Compliance. |
Ÿ | Information regarding |
Ÿ | Information regarding |
Ÿ | Information regarding Dominion’s Code of Ethics required by this item is found under the headingCorporate Governance and Board Matters. |
The information concerning the executive officers of Dominion required by this item is included in Part I of this Form 10-K under the captionExecutive Officers of Dominion. Each executive officer of Dominion is elected annually.
VIRGINIA POWER
Information concerning directors of Virginia Power, each of whom is elected annually, is as follows:
Name and Age | Principal Occupation and Directorships in Public Corporations for Last Five Years(1) | Year First Elected as Director | ||||
Thomas F. Farrell II | Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to Mr. Farrell’s qualifications to serve as a director include his | 1999 | ||||
Mark F. McGettrick | Executive Vice President and CFO of Virginia Power and Dominion from June 2009 to date; President and Mr. McGettrick’s qualifications to serve as a director include his more than 30 years of power generation management and industry experience. He currently serves on the George Mason University board of visitors and business council and is on the | 2009 | ||||
Steven A. Rogers | Senior Vice President and Chief Information Officer of Virginia Power and Dominion from January 2013 to date; Senior Vice President and Chief Administrative Officer of Dominion and President and Chief Administrative Officer of DRS from October 2007 to Mr. | 2007 |
(1) | Any service listed for Dominion |
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Executive Officers of Virginia Power
Information concerning the executive officers of Virginia Power, each of whom is elected annually, is as follows:
Name and Age | Business Experience Past Five Years(1) | |
Thomas F. Farrell II | Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to | |
Mark F. McGettrick | Executive Vice President and CFO of Virginia Power and Dominion from June 2009 to date; President and | |
Paul D. Koonce | President and COO of Virginia Power from June 2009 to date; Executive Vice President and Chief Executive Officer-Energy Infrastructure Group of Dominion from February 2013 to date; Executive Vice President of Dominion from April 2006 to | |
David A. Christian | President and COO of Virginia Power from June 2009 to date; Executive Vice President and Chief Executive Officer-Dominion Generation Group of Dominion from February 2013 to date; Executive Vice President of Dominion from May 2011 to February 2013; President and CNO of Virginia Power from October 2007 to May | |
David A. Heacock | President and CNO of Virginia Power from June 2009 to date; President and COO-DVP of Virginia Power and Senior Vice President of Dominion from June 2008 to May 2009; Senior Vice | |
Robert M. Blue | Senior Vice | |
Ashwini Sawhney | Vice |
(1) | Any service listed for Dominion |
Section 16(a) Beneficial Ownership Reporting Compliance
To Virginia Power’s knowledge, for the fiscal year ended December 31, 2010,2012, all Section 16(a) filing requirements applicable to its executive officers and directors were satisfied.
Audit Committee Financial Experts
Virginia Power is a wholly-owned subsidiary of Dominion. As permitted by SEC rules, its Board of Directors serves as Virginia Power’s Audit Committee and is comprised entirely of executive officers of Virginia Power or Dominion. Virginia Power’s Board of Directors has determined that Thomas F. Farrell II, Mark F. McGettrick and Steven A. Rogers are “audit committee financial experts” as defined by the SEC. As executive officers of Virginia Power and/or Dominion, Thomas F. Farrell II, Mark F. McGettrick and Steven A. Rogers arewere not deemed independent.
Code of Ethics
Virginia Power has adopted a Code of Ethics that applies to its principal executive, financial and accounting officers, as well as its employees. This Code of Ethics is the same as Dominion adopted and is available on the corporate governance section of Dominion’s website (www.dom.com). You may also request a copy of the Code of Ethics, free of charge, by writing or telephoning to: Corporate Secretary, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Any waivers or changes to Virginia Power’s Code of Ethics will be posted on the Dominion website.
Item 11. Executive Compensation
DOMINION
The following information about Dominion is contained in the 20112013 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the headingsCompensation Discussion and Analysis andExecutive CompensationCompensation;; the information regarding Compensation Committee interlocks contained under the headingCompensation Committee InterlocksandInsider Participation;theCompensation, Governance and Nominating Committee Report; and the information regarding director compensation contained under the headingNon-Employee Director CompensationCompensation..
VIRGINIA POWER
COMPENSATION DCISCUSSIONANDOMMITTEE ARNALYSISEPORT
Virginia Power is a wholly-owned subsidiaryIn preparation for the filing of Dominion. Virginia Power’s Board is comprised of Messrs. Farrell, McGettrick and Rogers. Messrs. Farrell and McGettrick are not independent because they are executive officers of Virginia Power. Mr. Rogers is not deemed independent because of his employment with Dominion. Virginia Power’s Board believes that it is more appropriate for its compensation program to be managed under the direction of individuals who are independent and, therefore, Virginia Power does not have a compensation committee. Instead, Virginia Power’s Board dependsAnnual Report on the advice and recommendations ofForm 10-K, Dominion’s CGN Committee which is comprisedreviewed and discussed the following CD&A with management and has recommended to the Board of independent directors and which retainedDirectors of Virginia Power that the consulting firm of PM&P to adviseCD&A be included in Virginia Power’s Annual Report on Form 10-K for the committee on compensationyear ended December 31, 2012.
Robert S. Jepson, Jr.,Chairman
William P. Barr
John W. Harris
Mark J. Kington
David A. Wollard
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matters.INTRODUCTION
Virginia Power is a wholly-owned subsidiary of Dominion. Virginia Power’s Board is comprised of Messrs. Farrell, McGettrick and Rogers. As executive officers of Virginia Power and/or Dominion, Messrs. Farrell, McGettrick and Rogers were not independent. Because Virginia Power’s Board is not independent, there is not a separate compensation committee at the Virginia Power level. Instead, Virginia Power’s Board depends on the advice and recommendations of Dominion’s CGN Committee which is comprised of independent directors. Virginia Power’s Board approves all compensation paid to Virginia Power’s executive officers based on theDominion’s CGN Committee’sCommittee recommendations.
None of Virginia Power’s directors receive any compensation for services they provide as directors.directors of Virginia Power. No executive officer of Dominion or Virginia Power serves as a member of another compensation committee or on the Board of Directors of any company of which a member of Dominion’s CGN Committee, Dominion’s Board of Directors or Virginia Power’s Board of Directors serves as an executive officer.
Because the CGN Committee effectively administers one compensation program for all of Dominion, the following discussion and analysis is based on Dominion’s overall compensation program.
ICNTRODUCTIONOMPENSATION DISCUSSIONAND ANALYSIS
This CD&A provides a detailed explanation of the objectives and principles that underlie Dominion’s executive compensation program, its elements and the way performance is measured, evaluated and rewarded. It also describes Dominion’s compensation decision-making process. Dominion’s executive compensation program is designed to pay for performance and playedplays an important role in the company’sDominion’s success in 2010 by linking a significant amount of compensation to the achievement of performance goals.
The program and processes generally apply to all of Dominion’s officers, but this discussion and analysis focuses primarily on compensation for the NEOs of Virginia Power. During 2010,2012, Virginia Power’s NEOs were:
Ÿ | Thomas F. Farrell II, Chairman |
Ÿ | Mark F. McGettrick, Executive Vice President and CFO |
Ÿ | Paul D. Koonce, President and COO—DVP |
Ÿ | David A. Christian, President and COO—Generation |
Ÿ |
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The CGN Committee determines the compensation payable to officers of Dominion and its wholly-owned subsidiaries on an aggregate basis, taking into account all services performed by the officers, whether for Dominion or one or more of its subsidiaries. All of Virginia Power’s NEOs, except for Mr. Heacock, are NEOs of Dominion. For the NEOs included in Dominion’s annual proxy statement, these aggregate amounts are reported in the Summary Compensation Table and related executive compensation tables. For purposes of reporting each NEO’s compensation from Virginia Power in the Summary Compensation Table (and related tables that follow) in this Item 11, the aggregate compensation for each NEO is pro-rated based on the ratio of services performed by the NEO for Virginia Power to the NEO’s
total services performed for all of Dominion. For officers who are NEOs of both Virginia Power and Dominion, the amounts reported in the tables below are part of, and not in addition to the aggregate compensation amounts that are reported for these NEOs in Dominion’s 20112013 Proxy Statement. The CD&A below discusses the CGN Committee’s decisions with respect to each NEO’s aggregate compensation for all services performed for all of Dominion, not just the pro-ratapro-rated portion attributable to the NEO’s services for Virginia Power.
OBJECTIVESOF DOMINION’S EXECUTIVE COMPENSATION PROGRAMANDTHE COMPENSATION DECISION-MAKING PROCESS
Objectives
Dominion’s executive compensation philosophy is to provide a competitive total compensation program tied to performance and aligned with the interests of Dominion shareholders, employees and customers.
The major objectives of Dominion’s compensation program are to:
Ÿ | Attract, develop and retain an experienced and highly qualified management team; |
Ÿ | Motivate and reward superior performance that supports |
Ÿ | Align the interests of management with those of Dominion’s shareholders and customers by placing a substantial portion of pay at risk through performance goals that, if achieved, are expected to increase |
Ÿ | Promote internal pay equity; and |
Ÿ | Reinforce Dominion’s four core values of safety, ethics, excellence and |
These objectives provide the framework for the compensation decisions. To determine if Dominion is meeting the objectives of its compensation program, the CGN Committee reviews and compares Dominion’s actual performance to its short-term and long-term goals, strategies, and peer companies’ performance.
Dominion’s 20102012 performance indicates that the design of Dominion’s compensation program is meeting these objectives. The NEOs have service with Dominion ranging from 1214 to 3436 years. Dominion has attracted, motivated and maintained a superior leadership team with skills, industry knowledge and institutional experience that strengthen their ability to act as sound stewards of Dominion’s shareholder dollars. Dominion is performing well relative to its internal goals and as compared to its peers.
In 2012, Dominion shareholders voted on the executive compensation program (also known as “Say on Pay”) and approved it on an advisory basis by almost 95%, which followed approval of 94% in the prior year. The CGN Committee considered the very strong shareholder endorsement of the CGN Committee’s decisions and policies and Dominion’s overall executive compensation program in continuing the pay-for-performance program that is currently in place without any specific changes for 2013 based on the vote. Unless Dominion’s
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Board of Directors modifies its policy on the frequency of future Say-on-Pay advisory votes, shareholders will have an opportunity annually to cast an advisory vote in connection with executive compensation. Dominion will ask shareholders, on an advisory basis, to vote on the frequency of the Say-on-Pay vote at least once every six years, with the next advisory vote on frequency to be held no later than Dominion’s 2017 Annual Meeting of Shareholders.
The Process for Setting Compensation
The CGN Committee is responsible for reviewing and approving NEO compensation and the overall executive compensation program. Each year, the CGN Committee reviews and considers a comprehensive assessment and analysis of the executive compensation program, including the elements of each NEO’s compensation, with input from management and the independent compensation consultant. As part of its assessment, the CGN Committee reviews the performance of the CEO and other executive officers, meets at least annually with the CEO to discuss succession planning for his position and the positions of the company’sDominion’s senior officers, reviews the share ownership guidelines and executive officer compliance with the guidelines, and establishes compensation programs designed to achieve Dominion’s objectives.
THE ROLEOFTHE INDEPENDENT COMPENSATION CONSULTANT
The CGN Committee’s practiceCommittee has been to retainretained an independent compensation consultant, PM&P, to advise the committee on executive and director compensation matters. PM&P does not provide any services to Dominion other than its consulting services to the CGN Committee related to executive and director compensation. The PM&P consultant participates in meetings with the CGN Committee, either in person or by teleconference, and communicates directly with the chairman of the committee outside of the committee meetings as requested by the chairman of the committee. PM&P also reviewed meeting materials as requested for the CGN Committee and provided the following services related to the 20102012 executive compensation program:
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Ÿ | Participated in CGN Committee executive sessions without management present to discuss CEO compensation and any other relevant matters, including the appropriate relationship between pay and performance and emerging trends, to answer technical questions, and to review and comment on management |
Ÿ | Generally reviewed and offered advice as requested by or on behalf of the CGN Committee regarding other aspects of the executive compensation program, including |
PM&P received compensation from Dominion for consulting services related only to executive and director compensation, except for $3,300 related to Dominion’s participation in one natural gas transmission compensation survey which was administered by PM&P. PM&P did not provide any additional services to Dominion.
The CGN Committee has reviewed and considered information provided to the CGN Committee by its PM&P consultant, the CGN Committee members and Dominion’s executive officers, and based on its review and such factors as it deemed relevant, the CGN Committee has concluded that the advice it receives from PM&P is objective and that PM&P’s work did not raise any conflict of interest.
MANAGEMENT’S ROLEIN DOMINION’S PROCESS
Although the CGN Committee has the responsibility to approve and monitor all compensation for the NEOs, management plays an important role in determining executive compensation. Under the direction of the Corporate Secretary, internal compensation specialists provide the CGN Committee with data, analysis and counsel regarding the executive compensation program, including an ongoing assessment of the effectiveness of the program, peer practices, and executive compensation trends and best practices. The CEO, CFO and Corporate Secretary, along with the internal compensation and financial specialists, assist in the design of the incentive compensation plans, including performance target recommendations consistent with the strategic goals of the company, and inrecommendations for establishing the peer group. Management also works with the Chairman of the CGN Committee to establish the agenda and prepare meeting information for each committeeCGN Committee meeting.
On an annual basis,As discussed previously, the CEO is responsible for reviewing senior officer succession plans with the CGN Committee Dominion’s succession plans for his own position and for Dominion’s senior officers.on an annual basis. He is also responsible for reviewing the performance of his senior officers, including the other NEOs, with the CGN Committee at least annually. He makes recommendations on the compensation and benefits for the NEOs (other than himself) to the CGN Committee and provides other information and counsel as appropriate or as requested by the CGN Committee, but all decisions are ultimately made by the CGN Committee.
THE PCEER GROUPANDOMPENSATION PEER GROUP COMPARISONS
EachThe CGN Committee uses two peer groups for executive compensation. The Compensation Peer Group is used to assess the competitiveness of the compensation of the NEOs. Starting with the 2012 Performance Grant, a separate Performance Grant Peer Group is used to evaluate the relative performance of Dominion for purposes of the LTIP. (See2012 Performance Grants for additional information.) In the fall of each year, the CGN Committee approves a peer groupCompensation Peer Group of companies. In selecting the peer group,Compensation Peer Group, Dominion uses a methodology generally recommended by PM&P to identify companies in the industry
that compete for customers, executive talent and investment capital. Dominion screens this group based on size and usually eliminates companies that are much smaller or larger than Dominion’s size in revenues, assets and market capitalization. Dominion also considers the geographic locations and the regulatory environment in which potential peer companies operate.
Dominion’s peer groupCompensation Peer Group is generally consistent from year to year, with merger and acquisition activity being the primary reason for any changes. The 2010No changes were made to the peer group was the sameused for setting compensation for 2012. The members of Dominion’s Compensation Peer Group are as the 2009 peer group and consisted of the following 14 energy companies:follows:
Ameren Corporation | FirstEnergy Corp. | |
American Electric Power Company, Inc.
DTE Energy Company Duke Energy Corporation | NextEra Energy, Inc. NiSource, Inc. PPL Corporation Public Service Enterprise Group Inc. | |
Entergy Corporation Exelon Corporation |
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The CGN Committee PM&P and management use peer company data from the Compensation Peer Group prepared by management to: (i) compare Dominion’s stock and financial performance against its peers using a number of different metrics and time periods to evaluate how Dominion is performing as compared to its peers; (ii) analyze compensation practices within the industry; (iii) evaluate peer company practices and determine peer median and 75th percentile ranges for base pay, annual incentive pay, long-term incentive pay and total direct compensation, both generally and for specific positions; and (iv) compare Employment Continuity Agreementsbenefits and other benefits.perquisites. In setting the levels for base pay, annual incentive pay, long-term incentive pay and total direct compensation, the CGN Committee also takes into consideration Dominion’s larger size compared with the median of the peer group.Compensation Peer Group.
SURVEY DATA
During 2009 and 2010, survey compensation data was used only to provide a general understanding of compensation practices and trends. Dominion did not benchmark or otherwise use broad-based market data as the basis for 2009 or 2010 compensation decisions for the NEOsNEOs. Survey compensation data is used only to provide a general understanding of compensation practices and other senior officers. Going forward, thetrends. The CGN Committee intends to continue its practice of emphasizingtakes into account individual and company specific considerations,factors, including internal pay equity, along with peer company data from the Compensation Peer Group in establishing compensation opportunities. The CGN Committee believes that this emphasis better reflects Dominion’s specific needs in its distinct competitive market and with respect to its size and complexity versus its peers.
COMPENSATION DESIGNAND RISK
Management,Dominion’s management, including Dominion’s chief risk officer and other executives, annually reviews the overall structure of Dominion’s executive compensation program and policies to ensure they are consistent with effective management of enterprise key risks and that they do not encourage executives to take unnecessary or excessive risks that could threaten the value of the enterprise. With respect to the programs and policies that apply to the NEOs, this review includes:
Ÿ | Analysis of how different elements of the compensation programs may increase or mitigate risk-taking; |
Ÿ | Analysis of performance metrics used for short-term and long-term incentive programs and the relation of such incentives to the objectives of Dominion; |
Ÿ | Analysis of whether the performance measurement periods for short-term and long-term incentive compensation are appropriate; and |
Ÿ | Analysis of the overall structure of compensation programs as related to business risks. |
Among the factors considered in management’s assessment are: the balance of the overall program design, including the mix of cash and equity compensation; the mix of fixed and variable compensation; the balance of short-term and long-term objectives of incentive compensation; the performance metrics, performance targets, threshold performance requirements and capped payouts related to incentive compensation; the clawback provision on incentive compensation; Dominion’s share ownership guidelines, including share ownership levels and retention practices; prohibitions on hedging, pledging, and other derivative transactions related to Dominion stock; and internal controls and oversight structures in place.place at Dominion.
Management reviewed and discussedprovided the results of this assessment withto the CGN Committee. Based on this review, the CGN Committee believes that Dominion’s well-balanced mix of salary and short-term and long-term incentives, as well as the performance
metrics that are included in the incentive programs, are appropriate and consistent with Dominion’s risk management practices and overall strategies.
OTHER TOOLS
The CGN Committee uses a number of tools in its annual review of the compensation of theDominion’s CEO and other NEOs, including charts illustrating the total range of payouts for each performance-based compensation element under a number of different scenarios; spreadsheets showing the cumulative dollar impact on total direct compensation that could result from implementing proposals on any single element of compensation; graphs showing the relationship between the CEO’s pay and that of the next highest-paid officer and Dominion’s NEOs as a group; and other information the CGN Committee may request in its discretion. Management’s internal compensation specialists provide the CGN Committee with detailed comparisons of the design and features of Dominion’s long-term incentive and other executive benefit programs with available information regarding similar programs at the peer companies.companies in the Compensation Peer Group. These tools are used as part of the overall process to ensure that the program results in appropriate pay relationships as compared to Dominion’s peer companies and internally among theDominion’s NEOs, and that an appropriate balance of at-risk, performance-based compensation is maintained to support the program’s core objectives. No material adjustments were made to Dominion’s NEO’s compensation as a result of using these tools.
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ELEMENTSOF DOMINION’S COMPENSATION PROGRAM
The executive compensation program consists of four basic elements:
Pay Element | Primary Objectives | Key Features & Behavioral Focus | ||
Base Salary | Ÿ Provide competitive level of fixed cash compensation for performing day-to-day responsibilities Ÿ Attract and retain talent | Ÿ Generally targeted at or slightly above peer median, with individual and company-wide considerations Ÿ Rewards individual performance and level of experience | ||
Annual Incentive Plan | Ÿ Provide competitive level of at-risk cash compensation for achievement of short-term financial and operational goals Ÿ Align short-term compensation with | Ÿ Cash payments based on achievement of annual financial and individual operating and stewardship goals Ÿ Rewards achievement of annual financial goals for Dominion | ||
Long-Term Incentive Program | Ÿ Provide competitive level of at-risk compensation for achievement of long-term performance goals Ÿ Create long-term shareholder value Ÿ Retain talent and support the succession planning process | Ÿ A combination of performance-based cash and restricted stock awards Ÿ Encourages and rewards officers for making decisions and investments that create long-term shareholder value as reflected in superior relative total shareholder returns, as well as achieving desired | ||
Employee and Executive Benefits | Ÿ Provide competitive retirement and other benefit programs that attract and retain highly qualified individuals Ÿ Provide competitive terms to encourage officers to remain with Dominion during any potential change in control to ensure an orderly transition of management | Ÿ Includes company-wide benefit programs, executive retirement plans, limited perquisites, and change in control and other agreements, supplemented with non-compete provisions in the non-qualified retirement plans Ÿ Encourages officers to remain with Dominion long-term and to act in the best |
Factors in Setting Compensation
As part of the process of setting compensation targets, approving payouts and designing future programs, the CGN Committee evaluates Dominion’s overall performance versus its business plans and strategies, its short-term and long-term goals and the performance of its peer companies. In addition to considering Dominion’s overall performance for the year, the CGN Commit-
teeCommittee takes into consideration several individual factors that are not given any specific weighting in setting each element of compensation for each NEO, including:
Ÿ | An officer’s experience and job performance; |
Ÿ | The scope, complexity and significance of responsibility for a position, including any differences from peer company positions; |
Ÿ | Internal pay equity considerations, such as the relative importance of a particular position or individual officer to Dominion’s strategy and success, and comparability to other officer positions at Dominion; |
Ÿ | Retention and market competitive concerns; and |
Ÿ | The officer’s role in any succession plan for other key positions. |
The CGN Committee evaluates each NEO’s base salary, total cash and total direct compensation opportunities against peer group data both at peer group median andfrom the 75th percentile,Compensation Peer Group to ensure the compensation levels are appropriately competitive, but except for base salary, does not target these compensation levels at a particular percentile or range of the peer group data. Base salaryFor Mr. Heacock, the same evaluation process is generally targeted at or slightly aboveperformed using the Towers Watson Energy Services data instead of peer group 50th percentile (median). Compensation decisions are based on whatdata. See Exhibit 99.3 for a listing of the CGN Committee deems appropriate, taking into consideration a number of factors, including those discussed above. However, actual compensation targets may range from below peer median to at or abovecompanies included in the 75th percentile based on a number of factors including experience, tenure and internal pay equity considerations.survey. As part of this analysis, the CGN Committee also takes into account Dominion’s larger size and complexity compared to its peer companies.the companies in the Compensation Peer Group.
In setting compensation for 2010, due to volatile market conditions and budget considerations,2012, Dominion provided a modest increase in base salaries were generally maintained at the 2009 levelssalary for all officers, including all NEOs, and made adjustments were made to performance-based compensation target levels for certain officers. Based on the review of peer company compensation data from the Compensation Peer Group, each NEO’s job performance, recent promotions and internal pay equity considerations such as scope and complexity of the position relative to other positions at the company,Dominion, the CGN Committee determined it was appropriate to increase the target levels under the annual incentive plan2012 AIP for Mr. Christian as described below inAnnual Incentive Plan and the LTIP for Messrs. McGettrick, and Christian and for all of the NEOs under the long-term incentive program,Koonce as described below in Base Salary, Annual Incentive Plan and Long-Term Incentive Program.Program.
CEO Compensation Relative to Other NEOs
Mr. Farrell participates in the same compensation programs and receives compensation based on the same philosophy and factors as other NEOs. Application of the same philosophy and factors to Mr. Farrell’s position results in overall CEO compensation that is significantly higher than the compensation of the other NEOs. His compensation is commensurate with his greater responsibilities and decision-making authority, broader scope of duties that encompassesencompassing the entirety of the companyDominion (as compared to the other NEOs who are responsible for significant but distinct areas within the company)Dominion) and his overall responsibility for corporate strategy. His compensation also reflects his role as the primaryprincipal corporate representative to investors, customers, regulators, analysts, legislators, industry and the media.
Dominion considers CEO compensation trends as compared to the next highest-paid officer, as well as to other executive officers as a group, over a multi-year period to monitor the ratio of Mr. Farrell’s pay relative to the pay of other executive officers based on (i) salary only and (ii) total direct compensation. Dominion also compares its ratios to that of its peers to confirm
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that its ratios are consistent with practices at the peer companies. There is no particular targeted ratio or goal, but instead the CGN
Committee considers year-to-year trends and comparisons with peer companies. The CGN Committee did not make any adjustments to the compensation of any NEOs based on this review in 2010.2012.
Allocation of Total Direct Compensation in 20102012
Consistent with Dominion’s objective to reward strong performance based on the achievement of short-term and long-term goals, a significant portion of total cash and total direct compensation is at risk. Total direct compensation is the sum of base salary, targeted AIP compensation and targeted long-term incentive compensation. Approximately 88%87% of Mr. Farrell’s targeted 20102012 total direct compensation is performance-based, tied to pre-approved performance metrics, including relative TSR and ROIC, or tied to the performance of Dominion’s stock. For the other NEOs, performance-based and stock-based compensation ranges from 71%65% to 79%80% of targeted 20102012 total direct compensation. This compares to an average of approximately 53%52% of targeted compensation at risk for most officers at the vice president level and an average of approximately 12% of total pay at risk for non-officer employees.
The charts below illustrate the elements of total direct compensation opportunities in 20102012 for Mr. Farrell and the average of the other NEOs as a group and the allocation of such compensation among base salary, targeted 2010 annual incentive plan2012 AIP award and targeted 20102012 long-term incentive compensation.
Base Salary
Base salary compensates officers, along with the rest of the work force,workforce, for committing significant time to working on Dominion’s
behalf. Annual salary reviews achieve two primary purposes: (i) an annual adjustment, as appropriate, to keep salaries in line and
competitive with the peer groupCompensation Peer Group and to reflect changes in responsibility, including promotions; and (ii) a motivational tool to acknowledge and reward excellent individual performance, special skills, experience, the strategic impact of a position relative to other Dominion executives and other relevant considerations.
The primary goal is to compensate its officers at a level that best achieves itsDominion’s objectives and reflects the considerations discussed above. Dominion believes that an overall goal of targeting base salary at or slightly above the peer groupCompensation Peer Group median is a conservative but appropriate target for base pay. However, an individual’s compensation may be below or above Dominion’s target range based on a number of factors such as performance, tenure, and other factors explained above inFactors in Setting Compensation. In addition to being ranked above or at the peer groupCompensation Peer Group median in 20102012 in terms of revenues, assets and market capitalization, the scope of Dominion’s business operations is complex and unique in its industry. Successfully managing such a broad and complex business requires a skilled and experienced management team. Dominion believes it would not be able to successfully recruit and retain such a team if the base pay for officers was generally below the peer groupCompensation Peer Group median.
Although individual and company performance would have supported merit increases for 2010 for the NEOs, due to uncertain market conditions and the current economic climate, For 2012, the CGN Committee frozeapproved a 7.5% base salariessalary increase for most officers, including all NEOs at their 2009 levels.
Messrs. Farrell and Christian, a 3% base salary increase for Messrs. McGettrick and Koonce and a 4% base salary increase for Mr. Heacock. In September 2010,determining the base salary increase for Mr. Farrell, the CGN Committee considered Dominion’s exceptionalstrong performance year-to-datein 2011 as well as Mr. Farrell’s individual performance, the complexity of Dominion and determined it was appropriate to authorize a one-time, 2% merit lump sum payment to all employees (other than those whose compensation is determined pursuant to the terms of a collective bargaining agreement). This 2% merit lump sum payment was also paid to all NEOs. The 2% merit lump sum payment was withinenergy industry itself and Mr. Farrell’s leadership in the range of general market increases for 2010 merit awards, based on Dominion’s understanding of compensation practices and trends. As a special one-time lump sum payment, however, the payment did not increase base salaries or change compensation levels used in calculating retirement planindustry and other employee benefits.factors. For Mr. Christian, the CGN Committee took into consideration that Mr. Christian’s base salary was slightly below the Compensation Peer Group median, the increased competitiveness for nuclear industry expertise and the size of the Dominion Generation business unit, which is the largest of Dominion’s three business units, relative to Dominion’s other business units and other factors. Effective January 1, 2013, the CGN Committee increased Mr. Koonce’s base salary 10% to recognize his increased responsibility as CEO of the Energy Infrastructure Group with the CEO of the Dominion Energy business unit reporting to him.
Annual Incentive Plan
OVERVIEW
The AIP plays an important role in meeting Dominion’s overall objective of rewarding strong performance. The AIP is a cash-based program focused on short-term goal accomplishments and is designed to:
Ÿ | Tie interests of |
Ÿ | Focus the workforce on company, operating group, team and individual goals that ultimately influence operational and financial results; |
Ÿ | Reward corporate and operating unit earnings performance; |
Ÿ | Reward safety and other operating and stewardship goal |
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Ÿ | Emphasize teamwork by focusing on common goals; |
Ÿ | Appropriately balance risk and reward; and |
Ÿ | Provide a competitive total compensation opportunity. |
TARGET AWARDS
An NEO’s compensation opportunity under the AIP is based on a target award. Target awards are determined as a percentage of a
participant’s base salary (for example, 95%85% of base salary). The target award is the amount of cash that will be paid if a participant achieves a score of 100% for the goals established at the beginning of the year and the plan is funded at the full funding target set for the year.year and a participant achieves a score of 100% for the payout goals. Participants who retire during the plan year are eligible to receive a pro-ratedprorated payment of their AIP award after the end of the plan year based on final funding and goal achievement. Participants who voluntarily terminate employment during the plan year and who are not eligible to retire (before attainment of age 55) forfeit their AIP award.
AIP target award levels are established based on a number of factors, including historical practice, individual and company performance and internal pay equity considerations, and are compared against peer groupCompensation Peer Group data to ensure the appropriate competitiveness of an NEO’s total cash compensation opportunity. However, as discussed above, AIP target award levels arewere not targeted at a specific percentile or range of the peer group data, nor was market survey data used in setting AIP target award levels for 2010.2012. Annual incentive target award levels wereare also consistent with theDominion’s intent to have a significant portion of NEO compensation at risk. The 2010For 2012, Mr. Christian’s AIP targets fortarget award percentage was increased from 85% to 90% of base salary to reflect the NEOs,continued transition of his compensation to a business unit CEO level. There were no changes to the AIP targets as a percentage of their base salary are shown belowfor Messrs. Farrell, McGettrick, Koonce and as compared to their 2009 targets.Heacock for 2012.
Name | 2009 AIP Target Award* | 2010 AIP Target Award* | 2011 AIP Target Award* | 2012 AIP Target Award* | ||||||||||||
Thomas F. Farrell II | 125% | 125% | 125% | 125% | ||||||||||||
Mark F. McGettrick | 95% | 100% | 100% | 100% | ||||||||||||
David A. Christian | 85% | 90% | ||||||||||||||
Paul D. Koonce | 90% | 90% | 90% | 90% | ||||||||||||
David A. Christian | 80% | 85% | ||||||||||||||
James F. Stutts | 80% | 80% | ||||||||||||||
David A. Heacock | 70% | 70% |
* As a % of base salary
The 2010 AIP targets for Messrs. Farrell, Koonce and Stutts were the same as their 2009 AIP targets at 125%, 90% and 80% of base salary, respectively.
Mr. McGettrick transitioned from the role of CEO of the Dominion Generation business unit to CFO of Dominion in 2009, but he did not receive an increase in his AIP target in 2009 when he became Dominion’s CFO. Due to Mr. McGettrick’s increased responsibility as Dominion’s CFO, Mr. McGettrick’s 2010 AIP target increased from 95% to 100%. Similarly, Mr. Christian’s AIP target did not increase in 2009 when he transitioned from CNO to CEO of the Generation business unit. Due to the increased scope of responsibility in his new position, the CGN Committee determined it was appropriate to increase the AIP target for 2010 from 80% to 85% for Mr. Christian.
FUNDINGOFTHE 20102012 AIP
Funding of the 20102012 AIP was based solely on consolidated operating earnings per share, with potential funding ranging from 0% to 200% of the target funding. Consolidated operating earnings are Dominion’s reported earnings determined in accordance with GAAP, adjusted for certain items. Dominion believes that by placing a focus on pre-established consolidated operating earnings per share targets, it increases employee awareness of the company’s financial objectives and encourages behavior and performance that will help achieve these objectives.
The 2010For the 2012 AIP, hadthe CGN Committee established a full funding target of $3.30 consolidatedat 100% for the NEOs at $3.05 operating earnings per share, the approximate mid-pointinclusive of
Dominion’s 2010 earnings guidance announced in January 2010. Funding is based on a formula that provides proportionate sharing of consolidated operating earnings between AIP participants and shareholders until the full funding target is achieved. Consolidated operating earnings above the fullfor all plan participants. The maximum funding target of $3.30200% was set at $3.15 operating earnings per share, are shared equally with shareholders, up to the maximum AIPand no funding level of 200% at $3.40if operating earnings were less than $3.05 per share.share (threshold), with the Committee retaining negative discretion to determine the final funding level.
Full funding means that the AIP is 100% funded and participants can receive their full targeted AIP payout if they achieve a score of 100% for their particular goal package, as described below inHow AIP PayoutsAre Determined. At the maximum
plan funding level of 200%, participants can earn up to two times their targeted AIP payout, subject to achievement of their individual goal packages.
Dominion’s consolidated operating earnings for the year ended December 31, 20102012 were $1.97$1.75 billion or $3.34$3.05 per share, as compared to its consolidated reported earnings in accordance with GAAP of $2.81 billion$302 million or $4.76$0.53 per share.* This resulted in 134%share, with enough earnings above $3.05 (before AIP funding) to support 60% funding for the 20102012 AIP.*
*Reconciliation of 20102012 Consolidated Operating Earnings to Reported Earnings. The following items, which are net of tax, are included in Dominion’s 20102012 reported earnings, but are excluded from consolidated operating earnings: $1.4$1.1 billion net benefitloss, including an impairment charge, associated with certain fossil fuel-fired merchant power stations that Dominion decided to market for sale in the third quarter of 2012; $303 million net loss, including impairment charges, primarily resulting from the saleplanned shutdown of Appalachian E&P operations, $206the Kewaunee nuclear merchant power station; $53 million charge related to a workforce reduction program, $155of restoration costs associated with severe storms affecting the Dominion Virginia Power and Dominion North Carolina Power service territories; $22 million net loss from the discontinued operations of two merchant power stations (State Line and loss on sale of Peoples, $127 million impairment charge related to certain merchant generation facilities, $57 million charge related to health care legislation changes,Salem Harbor) that were sold in 2012; and $1$5 million net expensebenefit related to other items.
HOW AIP PAYOUTS ARE DETERMINED
For most officers other than theDominion’s NEOs, payout of their funded AIP awards for 2010 was subjectis contingent solely on the achievement of the consolidated operating financial goal with the CGN Committee retaining negative discretion to lower the payout as it deems appropriate, taking into consideration the accomplishment of the consolidated financial, business unit financial and operating and stewardship goals, including a safety goal. The percentage allocated to each category of goals represents the percentage of the funded award subject to the per-
formanceperformance of that goal. Officer goals are weighted according to their responsibilities. The overall score cannot exceed 100% scoring..
Business unit financial goals provide a line-of-sight performance target for officers within a business unit and, on a combined basis, support the consolidated operating earnings target for Dominion. Operating and stewardship goals provide line-of-sight performance targets that may not be financial and that can be customized for each individual or by segments of each business unit. Operating and stewardship goals promote Dominion’sthe core values of safety, ethics, excellence and teamwork, which in turn contribute to Dominion’s financial success.
The AIP is designed so that AIP payouts earneddiscretionary payout goals adopted by the NEOs will qualify as tax deductible “performance-based” compensation under Section 162(m) of the Internal Revenue Code (the Code). To preserve the tax deduction for payouts made to the NEOs whose compensation is subject to Code Section 162(m), their payout, if any, is contingent solely on the achievement of the consolidated financial goal (weighted 100%). If the consolidated financial goal is met, the CGN Committee has the authority to exercise negative discretion to lower payouts if additional discretionary goals are adopted and these discretionary goals are not achieved.
For the 2010 AIP, all of the NEOs adopted a discretionary safety goal. Messrs. Koonce, Christian and Stutts adopted discretionary business unit financial goals and Mr. Stutts also adopted discretionary operating and stewardship goals. These goalseach NEO are described under20102012 AIP Payouts. The table below shows and the goal weightings applied to these discretionary goals.those goals are shown in the table below.
Name | Consolidated Financial Goal | Business Unit Financial Goals | Operating/ Stewardship* | Consolidated Financial Goal | Business Unit Financial Goals | Operating/ Stewardship Goals* | ||||||||||||||||||
Thomas F. Farrell II | 95% | 0% | 5% | 95% | — | 5% | ||||||||||||||||||
Mark F. McGettrick | 95% | 0% | 5% | 95% | — | 5% | ||||||||||||||||||
David A. Christian | 65% | 30% | 5% | |||||||||||||||||||||
Paul D. Koonce | 65% | 30% | 5% | 65% | 30% | 5% | ||||||||||||||||||
David A. Christian | 65% | 30% | 5% | |||||||||||||||||||||
James F. Stutts | 40% | 30% | 30% | |||||||||||||||||||||
David A. Heacock | 40% | 30% | 30% |
*5% goal weighting is for a safety goal. Mr. StuttsHeacock had other non-safety operating and stewardship goals as described below.
2010 AIP PAYOUTS
The 2010 discretionary business unit financial goals and accomplishment levels for Mr. Koonce (Dominion Virginia Power), Mr. Christian (Dominion Generation) and Mr. Stutts (DRS) were as follows:
Business Unit | Goal Threshold (Net Income) | Goal 100% Payout (Net Income) | Actual 2010 (Net Income) | 2010 Accomplishment | ||||||||||||
(Millions/$) | ||||||||||||||||
Dominion Virginia Power | $ | 343 | $ | 429 | $ | 448 | 100% | |||||||||
Dominion Generation | $ | 1,032 | $ | 1,290 | $ | 1,291 | 100% | |||||||||
DRS(1) | $ | 589 | $ | 535 | $ | 532 | 100% |
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A discretionary safety goal of minimizing OSHA recordable incident rates to a specified target number was adopted for all of the NEOs. Each NEO achieved his safety goal. In addition to his safety goal, which was weighted 5%, Mr. Stutts had discretionary operating and stewardship goals in four other categories: compliance (weighted 5%); training (weighted 10%); regulatory (weighted 5%); and efficiency improvements (weighted 5%). Mr. Stutts had a compliance goal to improve cycle time for disposition of compliance incident reports. His training goal was to identify in-house training opportunities that would benefit employees and the company. His regulatory goal was to meet deadlines for filings in all jurisdictions and maintain the quality of final work. The efficiency goal was to implement a new legal matters management system and bring to full usage. Mr. Stutts fully achieved all of these operating and stewardship goals.
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2012 AIP PAYOUTS
The formula for calculating an award is: |
The consolidated financial goal was consolidated operating earnings for the year ended December 31, 2012 of $3.05 per share, which was accomplished as described above. The 2012 business unit financial goals and accomplishment levels for Mr. Koonce (DVP), and Messrs. Christian and Heacock (Dominion Generation) were as follows:
Business Unit | Goal Threshold (Net Income) | Goal 100% Payout (Net Income) | Actual 2012 Net Income | 2012 Approved | ||||||||||||
(Million/$) | ||||||||||||||||
DVP | $ | 431 | $ | 539 | $ | 559 | 100% | |||||||||
Dominion Generation | 803 | 1,004 | 874 | 87 |
Messrs. Farrell and McGettrick each received partial credit for their safety goal as the DRS business unit had five OSHA recordable incidents which exceeded the target of four or less OSHA recordable incidents with an incidence rate of 0.15 or less. Mr. Christian met his target safety goal of an OSHA incidence rate ranging from 0.16 to 1.31 for certain operating units and recordable incidents of two or fewer for another operating unit in the Dominion Generation business unit. Mr. Koonce met his target safety goal of an OSHA incidence rate of 1.39 and lost time/restricted duty rate of 0.25 for the DVP business unit. Mr. Heacock met his target safety goal of less than seven fleetwide total OSHA recordable injuries (weighted 6%) and his nuclear safety goal of less than six station clock resets for total nuclear fleet (weighted 8%). In addition to his safety goal, Mr. Heacock had operating and stewardship goals in three other categories: environmental compliance (weighted 5%); radiation exposure (weighted 4%); and fleet capacity factor (weighted 7%), Mr. Heacock met all three of these goals.
The CGN Committee exercised negative discretion to lower the payouts for Messrs. Farrell and McGettrick due to their missed safety goals and Messrs. Christian and Heacock due to their missed business unit financial goals. Amounts earned under the 20102012 AIP by NEOs are shown below and are reflected in theNon-Equity Incentive Plan Compensation column of theSummary Compensation Table.
Name | Base Salary | Target Award | Funding % | Total Payout Score % | 2010 AIP Payout | Base Salary | Target Award* | Funding% | Total Payout Score % | 2012 AIP Payout | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Thomas F. Farrell II | $ | 336,000 | x | 125% | x | 134% | x | 100% | = | $ | 562,800 | $ | 386,319 | X | 125% | X | 60% | X | 99% | = | $ | 286,842 | ||||||||||||||||||||||||||||||||||||||||||
Mark F. McGettrick | 299,414 | x | 100% | x | 134% | x | 100% | = | 401,215 | 313,402 | X | 100% | X | 60% | X | 99% | = | 186,161 | ||||||||||||||||||||||||||||||||||||||||||||||
David A. Christian | 327,668 | X | 90% | X | 60% | X | 96% | = | 169,863 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Paul D. Koonce | 423,215 | x | 90% | x | 134% | x | 100% | = | 510,397 | 431,709 | X | 90% | X | 60% | X | 100% | = | 233,123 | ||||||||||||||||||||||||||||||||||||||||||||||
David A. Christian | 293,514 | x | 85% | x | 134% | x | 100% | = | 334,312 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
James F. Stutts | 180,600 | x | 80% | x | 134% | x | 100% | = | 193,603 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
David A. Heacock | 207,766 | X | 70% | X | 60% | X | 96% | = | 83,771 |
*As a % of base salary.
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the appropriateapplicable portion related to their service for Virginia Power forin the year presented.
Messrs. Farrell and McGettrick’s payout scores were calculated as follows:
Name | Consolidated Financial Goal Accomplishment | Goal Weighting | Operating/ Stewardship Goal Accomplishment | Goal Weighting | Total Payout Score | |||||||||||||||||||||||
Thomas F. Farrell II | 100% | X | 95% | + | 80% | X | 5% | = | 99 | % | ||||||||||||||||||
Mark F. McGettrick | 100% | X | 95% | + | 80% | X | 5% | = | 99 | % |
Messrs. Christian, Koonce and Heacock’s payout scores were calculated as follows:
Name | Consolidated Financial Goal Accomplishment | Goal Weighting | Business Unit Financial Goal Accomplishment | Goal Weighting | Operating/ Stewardship Goal Accomplishment | Goal Weighting | Total Payout Score | |||||||||||||||||||||||||||||||||
David A. Christian | 100% | X | 65% | + | 87% | X | 30% | + | 100% | X | 5% | = | 96% | |||||||||||||||||||||||||||
Paul D. Koonce | 100% | X | 65% | + | 100% | X | 30% | + | 100% | X | 5% | = | 100% | |||||||||||||||||||||||||||
David A. Heacock | 100% | X | 40% | + | 87% | X | 30% | + | 100% | X | 30% | = | 96% |
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Long-Term Incentive Program
OVERVIEW
Dominion’s long-term incentive programLTIP focuses on Dominion’s longer-term strategic goals and retention.retention of its executives. Since 2006, 50% of Dominion’s long-term incentives have been full value equity awards in the form of restricted stock with time-based vesting and the other 50% have been performance-based awards. Dominion believes restricted stock serves as a strong retention tool and also creates a focus on Dominion’s stock price to further align the interests of officers with the interests of Dominion’s shareholders.its shareholders and customers. For those officers who have made substantial progress toward their share ownership guidelines, 50% of their long-termthe performance-based award is in the form of a cash performance grant. Officers who have not achieved 50% of their targeted share ownership guideline receive goal-based stock performance grants instead of a cash performance grant. Dividend equivalents are not paid on any performance-based grants. Because officers are expected to retain ownership of shares upon vesting of restricted stock awards, as explained inShare Ownership Guidelines,the long-term cash performance grant balances the program and allows a portion of the long-term incentive award to be accessible to the NEOs during the course of their employment. As all of the NEOs have satisfied their full targeted share ownership, all of the NEOs received the performance-based component of their 2012 long-term incentive award in the form of a cash performance grant.
The CGN Committee approves long-term incentive awards in January each year with a grant date established in early February. This process ensures incentive-based awards are made at the beginning of the performance period and shortly after the public disclosure of Dominion’s earnings for the prior year. Like the AIP target award levels discussed above, long-term incentive target award levels arewere established based on a number of factors, including historical practice, individual and company performance, and internal pay equity considerations, and are compared against peer groupCompensation Peer Group data to ensure the appropriate competitiveness of an NEO’s total direct compensation opportunity. However, as discussed above, long-term incentive target award levels are not targeted at a specific percentile or range of the peer groupCompensation Peer Group data, nor was market survey data a factor in setting long-term incentive target award levels for 2010.2012.
Through 2009,For 2012, the CGN Committee approved increases to the target long-term incentive valuesawards for all NEOs, exceptMessrs. McGettrick, Christian and Koonce as discussed below. There was no change to the target long-term incentive award for Mr. McGettrick, remained atFarrell or for Mr. Heacock.
MCGETTRICK. Among the same target levels as they had been since 2006, which wasfactors considered by the first year Dominion granted performance-based awards as partCGN Committee in determining the amount of the long-term incentive compensation program. Mr. McGettrick’s long-term incentive compensation value has remained at the same target level since 2007.award were Mr. McGettrick’s continued superior performance as CFO and his broad-based experience. The CGN Committee considered the job performance to date of the NEOs, the increased scope of responsibilities assumed and recent promotions or job rotations and determined it was appropriate to approve a 6% increase thein Mr. McGettrick’s target levels for the NEOs’ 2010 long-term incentive awards from their 2006award, which resulted in a 5% increase in total direct compensation at target.
CHRISTIAN. For Mr. Christian’s target level, orlong-term incentive award, the CGN Committee considered, among other factors, Mr. Christian’s performance as CEO of the Dominion Generation business unit and his experience with the company. The CGN Committee also considered the size of the Dominion Generation business unit, which is the largest of Dominion’s three
business units, relative to Dominion’s other business units in determining his target long-term incentive award, the casecontinued transition of Mr. McGettrick,Christian’s compensation to a business unit CEO level and the increased industry competitiveness for personnel with nuclear expertise. The CGN Committee determined it was appropriate to approve an 18% increase in Mr. Christian’s target long-term incentive award, which resulted in a 14% increase in total direct compensation at target.
KOONCE. Among the factors considered by the CGN Committee in determining the amount of Mr. Koonce’s award were Mr. Koonce’s performance as CEO of the DVP business unit and his 2007experience and long tenure with Dominion. The CGN Committee determined it was appropriate to approve a 13% increase in Mr. Koonce’s target level.long-term incentive award, which resulted in a 9% increase in total direct compensation at target.
Information regarding the fair value of 2010the 2012 restricted stock grants and target cash performance grants for the NEOs is provided in theGrants of Plan-Based Awardstable.
20102012 RESTRICTED STOCK GRANTS
All officers received a restricted stock grant on February 1, 20102012 based on a stated dollar value. The number of shares awarded was determined by dividing the stated dollar value by the closing price of Dominion’s common stock on January 29, 2010.February 1, 2012. The grants have a three-year vesting term, with cliff vesting at the end of the restricted period on February 1, 2013. Mr. Stutts’ grant vested pro-rata upon his retirement on January 1, 2011 based on a determination by the CEO that Mr. Stutts’ retirement would not be detrimental to the company.2015. Dividends are paid to officers during the restricted period. The grant date fair value and vesting terms of the 20102012 restricted stock grant awards made to the NEOs isare disclosed in theGrants of Plan-Based Awardstable. table and related footnotes.
20102012 PERFORMANCE GRANTS
Most officers, includingIn January 2012, the NEOs, receivedCGN Committee approved cash performance grants onfor the NEOs, effective February 1, 2010. Officers who had not achieved 50% of their targeted share ownership guideline received stock-based performance grants. Dividend equivalents are not paid on any performance-based grants.2012. The performance period commenced on January 1, 20102012 and will end on December 31, 2011. Mr. Stutts’ payout, if any, under his 2010 performance grant will be determined after the end of the performance period ending December 31, 2011 and will be pro-rated based on his months of service during such period.2013. The 20102012 grants are denominated as a target award, with potential payouts ranging from 0-200% of the target based on Dominion’s TSR relative to the peer groupa Performance Grant Peer Group of companies selected by the CGN Committee and ROIC, weighted equally.
The TSR metric was selected to focus officers on long-term shareholder value when developing and implementing their strategic plans and in turn, reward management based on the achievement of TSR levels as measured relative to Dominion’s peer companies. The ROIC metric was selected to reward officers for the achievement of expected levels of return on the company’sDominion’s investments. Dominion believes an ROIC measure encourages management to choose the right investments, and with those investments, to achieve the highest returns possible through prudent decisions, management and control of costs. The target awards and vesting terms of the 20102012 performance grants made to the NEOs are disclosed in theGrants of Plan-Based Awardstable. table and related footnotes.
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Performance Grant Peer Group
Since performance grants were first awarded in 2006, Dominion’s TSR performance has been measured relative to a Performance Grant Peer Group that included the same companies included in its peer group for compensation setting purposes.
For the 2011 Performance Grant, the peer group used in measuring relative TSR is the same group of companies included in the Compensation Peer Group, excluding Constellation and Progress Energy due to their mergers with Exelon and Duke, respectively (2011 Performance Grant Peer Group). Following its annual review of the design of the LTIP, the CGN Committee approved measuring TSR performance for the 2012 Performance Grant against the TSR of the companies listed as members of the Philadelphia Stock Exchange Utility Index at the end of the performance period (2012 Performance Grant Peer Group). In selecting the Philadelphia Utility Index, the CGN Committee took into consideration that the companies represented in the Philadelphia Stock Exchange Utility Index are similar to those companies currently included in Dominion’s Compensation Peer Group and the index itself is a recognized published index whose members are determined externally and independently from Dominion. The CGN Committee also took into consideration the past and recent mergers within the utility industry and the effects of consolidation on the size of Dominion’s Performance Grant Peer Group. The companies in the Philadelphia Stock Exchange Utility Index at the grant date of the 2012 Performance Grant were as follows:
The AES Corporation Ameren Corporation American Electric Power Company, Inc. CenterPoint Energy, Inc. Consolidated Edison, Inc. Covanta Holding Corporation DTE Energy Company Duke Energy Corporation Edison International | El Paso Electric Company Entergy Corporation Exelon Corporation FirstEnergy Corp. NextEra Energy, Inc. Northeast Utilities PG&E Corporation Public Service Enterprise Group Incorporated The Southern Company Xcel Energy Inc. | |
For 2012 Performance Grants, the CGN Committee also approved recalibrating the performance grant payout scale for the TSR metric so that payout will be capped at 200% at the 85th percentile of the Performance Grant Peer Group rather than at the 100th percentile, which is consistent with the long-term incentive plans of several companies in Dominion’s Compensation Peer Group. No other changes were made to the payout scale with payout at target (or 100%) remaining at the 50th percentile of the Performance Grant Peer Group, payout at threshold (or 50%) at the 25th percentile and no payout for relative TSR below the 25th percentile.
PAYOUT UNDER 20092011 PERFORMANCE GRANTS
In February 2011,2013, final payouts were made to officers who received 20092011 performance grants, including the NEOs. The 20092011 performance grants were based on threetwo goals: TSR for the two-year period ended December 31, 20102012 relative to Dominion’s peer group of companies2011 Performance Peer Group (weighted 50%); and ROIC for the same two-year period (weighted 40%); and BVP as of December 31, 2010 (weighted 10%50%).
Ÿ | Relative TSR (50% weighting). |
end of the two-year performance period, plus dividends paid as if reinvested in stock. For this metric, Dominion’s TSR is compared to TSR levels |
Relative TSR Performance | Percentage Payout of TSR Percentage* | |||
| 150% – 200% | |||
2ndQuartile – 50% to 74.9% | 100% – 149.9% | |||
3rdQuartile – 25% to 49.9% | 50% – 99.9% | |||
4thQuartile – below 25% | 0% |
*TSR |
Actual relative TSR performance for the 2009-20102011-2012 period was in the topsecond quartile. Dominion’s TSR for the two-year period ended December 31, 2012 was 31.6%, which ranked sixth relative to the peer group which was comprised of the same companies in the Compensation Peer Group and placed Dominion ahead of nine of the 14 peer companies.
Ÿ | ROIC |
ROIC Performance | Percentage Payout of ROIC Percentage* | |||
| 200% | |||
| 150% | |||
| 100% – 149.9% | |||
| 50% – 99.9% | |||
Below | 0% |
*ROIC |
Actual ROIC performance for the 2009-20102011-2012 period was 8.82%.
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* BVP percentage payout is interpolated between the top and bottom of the percentages for any range.
Actual BVP for the 2009-2010 period was $21.89.0%.
Based on the achievement of the performance criteria, the CGN Committee approved a 127.6%64.2% payout for the 20092011 performance grants. The following table summarizes the achievement of the 20092011 performance criteria:
Measure | Goal Weight% | Goal Achievement% | Payout% | Goal Weight% | Goal Achievement% | �� | Payout% | |||||||||||||||||||||||||
Relative TSR | 50% | 157.0% | 78.5% | 50% | X | 128.5% | = | 64.2% | ||||||||||||||||||||||||
ROIC | 40% | 92.0% | 36.8% | 50% | X | 0% | = | 0% | ||||||||||||||||||||||||
BVP | 10% | 123.4% | 12.3% | |||||||||||||||||||||||||||||
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Combined Overall Performance Score | Combined Overall Performance Score |
| 127.6% | Combined Overall Performance Score |
| 64.2% |
137
The resulting payout amounts for the NEOs for the 20092011 performance grants are shown below and are also reflected in theNon-Equity Incentive Plan Compensation column of theSummary Compensation Table.
Name | 2009 Performance Grant Award | Overall Performance Score | Calculated Performance Grant Payout | 2011 Performance Grant Award | Overall Performance Score | Calculated Performance Grant Payout | ||||||||||||||||||||||||||||||||||
Thomas F. Farrell II | $ | 840,000 | x | 127.6% | = | $ | 1,071,840 | $ | 1,027,600 | X | 64.2% | = | $ | 659,719 | ||||||||||||||||||||||||||
Mark F. McGettrick | 345,000 | x | 127.6% | = | 440,220 | 458,300 | X | 64.2% | = | 294,229 | ||||||||||||||||||||||||||||||
David A. Christian | 303,525 | X | 64.2% | = | 194,863 | |||||||||||||||||||||||||||||||||||
Paul D. Koonce | 382,500 | x | 127.6% | = | 488,070 | 464,231 | X | 64.2% | = | 298,036 | ||||||||||||||||||||||||||||||
David A. Christian | 172,250 | x | 127.6% | = | 219,791 | |||||||||||||||||||||||||||||||||||
James F. Stutts | 105,000 | x | 127.6% | = | 133,980 | |||||||||||||||||||||||||||||||||||
David A. Heacock | 117,650 | X | 64.2% | = | 75,531 |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the appropriateapplicable portion related to their service for Virginia Power.Power in the year presented.
Other Restricted Stock GrantGrants
The CGN Committee may consider other restricted stock grants for selected individuals in order to support key objectives including succession planning, talent retention and recruitment. These awards are not considered part of the annual program and are only awarded periodically. In December 2010,2012, the CGN Committee approved a restricted stock grantgrants for Messrs. McGettrick, Koonce and Christian of 28,00021,949, 23,715, and 15,505 shares (these NEOs perform services for more than one subsidiary of Dominion. These share amounts reflect only the applicable portion related to Mr. Farrelltheir service for Virginia Power in the year presented), respectively, to retain and secure histheir services for the next five years to providethree years. In making the leadership stability to implement Dominion’s strategic plans. Therestricted stock grants, the CGN Committee considered the increasing competitiveness of both the utility industry and general industry in retaining executive level officers, especially chief financial officers, chief operating officers and nuclear executives, and succession planning.
Each restricted stock grant supports CEO succession planning and the vesting terms of the grant further align Mr. Farrell’s interests with the interests of shareholders. The restricted shares areis subject to a five-yearthree-year cliff vesting with all
shares vesting on December 17,20, 2015 (the Vesting Date). Mr. FarrellThe officer will forfeit the restricted stock grant if his employment with Dominion terminates prior to the Vesting Date for any reason other than a change in control, death or disability. In the event of a change in control, death or disability, the restricted shares are subject to vesting on a pro-rated basis. Dividends will be paid on the restricted shares, but will be retained and subject to the same vesting terms as the restricted shares. To the extent the officer remains an employee of Dominion or a Dominion Company, net shares of vested restricted stock under each agreement must be retained for two years following the Vesting Date unless the officer dies or becomes disabled.
Employee and Executive Benefits
Benefit plans and limited perquisites composedcompose the fourth element of the compensation program. These benefits serve as a retention tool and reward long-term employment.
RETIREMENT PLANS
Dominion sponsors two types of tax-qualified retirement plans for eligible non-union employees, including the NEOs: a defined benefit pension plan (the Pension Plan)(DPP) and a defined contribution 401(k)
savings plan (the 401(k) Plan).plan. The NEOs, as employees hired before 2008, are eligible for a pension benefit upon attainment of retirement age based on a formula that takes into account final compensation and years of service. They also receive a cash balanceretirement benefit under which the companyDominion contributes 2% of each participant’s compensation to a special retirement account, which may be paid in a lump sum or added to the annuity benefit upon retirement. Dominion began funding the special retirement account for eligible employees in January 2001. The formula for the Pension PlanDPP is explained in the narrative following thePension Benefits table. The change in Pension PlanDPP value for 20102012 for the NEOs is included in theSummary Compensation Table.
Officers whose matching contributions under the 401(k) Plan are limited by the Internal Revenue CodeIRC receive a cash payment to make them whole for the company match lost as a result of these limits. These cash payments are currently taxable. The company matching contributions to the 401(k) Plan and the cash payments of company matching contributions above Internal Revenue CodeIRC limits for the NEOs are included in theAll Other Compensation column of theSummary Compensation Table and detailed in the footnote for that column.
Dominion also maintains two nonqualified retirement plans for its executives, the BRP and the ESRP, for the executives.ESRP. Unlike the Pension PlanDPP and 401(k) Plan, these plans are unfunded, unsecured obligations of Dominion. These plans keep Dominion competitive in attracting and retaining officers. Due to Internal Revenue CodeIRC limits on Pension Planpension plan benefits and because a more substantial portion of total compensation for officers is paid as incentive compensation than for other employees, the Pension PlanDPP and 401(k) Plan alone will produce a lower percentage of replacement income in retirement for officers than these plans will for other employees. The BRP restores benefits that will not be paid under the Pension PlanDPP due to the Internal Revenue CodeIRC limits. The ESRP provides a benefit that covers a portion (25%) of final base salary and target annual incentive compensation to partially make up for this gap in retirement income. The BRP and ESRP do not include long-term incentive compensation in benefit calculations and, therefore, a significant portion of the potential compensation for the officers is excluded from calculation in any retirement plan benefit. As consideration for the benefits earned under the BRP and ESRP, all officers agree to comply with confidentiality and one-year non-competition
requirements set forth in the plan documents following their retirement or other termination of employment. The present value of accumulated benefits under these retirement plans is disclosed in thePension Benefits table and the terms of the plans are fully explained in the narrative following that table.
In May 2010,individual situations and primarily for mid-career changes or retention purposes, the CGN Committee entered into a supplemental retirement agreement with Mr. McGettrick. This agreement restateshas granted certain officers additional years of credited age and clarifiesservice for purposes of calculating benefits under the BRP. Age and service credits granted to the NEOs are described inDominion Retirement Benefit Restoration PlanunderPension Benefits.Additional age and service may also be earned under the terms of prior agreements entered intoan officer’s Employee Continuity Agreement in 2005 and 2007the event of a change in control, as well as the surviving provisionsdescribed inChange in Control underPotential Payments Upon Termination or Change in Control.No additional years of his 1999 employment agreement. Mr. McGettrick will earn a lifetime benefit under the ESRP if he remains employed as an officer of Dominion until November 14, 2012, effectively giving him previously earned age andor service credit towardwere granted to the lifetime ESRP benefit that was provided to him under the surviving provisions of his 1999 employment agreement and later restated in a February 2007 letter agreement. As consideration for this benefit, Mr. McGettrick has agreed not to compete with the company for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.NEOs during 2012.
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OTHER BENEFIT PROGRAMS
OfficersDominion’s officers participate in all of the benefit programs available to other Dominion employees. The core benefit programs generally include medical, dental and vision benefit plans, a health savings account, health and dependent care flexible spending accounts, group-term life insurance, travel accident coverage, long-term disability coverage and a paid time off program.
Dominion also maintains an executive life insurance program for officers to replace a former company-wide retiree life insurance program that was discontinued in 2003. The plan is fully insured by individual policies that provide death benefits at a fixed amount depending on an officer’s salary tier. This life insurance coverage is in addition to the group-term insurance that is provided to all employees. The officer is the owner of the policy and Dominion makes premium payments until the later of 10 years from enrollment date or the date the officer attains age 64. Officers are taxed on the premiums paid by Dominion. The premiums for these policies are included in theAll Other Compensation column of theSummary Compensation Table.
PERQUISITES
Dominion provides a limited number of perquisites for officers to enable them to perform their duties and responsibilities as efficiently as possible and to minimize distractions. The CGN Committee annually reviews the perquisites to ensure they are an effective and efficient use of corporate resources. Dominion believes the benefits it receives from offering these perquisites outweigh the costs of providing them. In addition to incidental perquisites associated with maintaining an office, Dominion offers the following perquisites to all officers:
Ÿ | An allowance of up to $9,500 a year to be used for health club memberships and wellness programs, comprehensive executive physical exams and financial and estate planning. Dominion wants officers to be proactive with preventive healthcare and also wants executives to use professional, independent financial and estate planning consultants to ensure proper tax reporting of company-provided compensation and to help officers optimize their use of Dominion’s retirement and other employee benefit programs. |
Ÿ | A vehicle leased by Dominion, up to an established lease-payment limit (if the lease payment exceeds the allowance, the officer pays for the excess amount on the vehicle). The costs of insurance, fuel and maintenance for company-leased vehicles are paid by Dominion. |
Ÿ | In limited circumstances, use of company aircraft for personal travel by executive officers. For security and other reasons, the Board of Directors has directed Mr. Farrell to use the aircraft for all travel, including personal travel, whenever it is feasible to do so. His family and guests may accompany Mr. Farrell on any personal trips. The use of company aircraft for personal travel by other executive officers is limited and usually related to (i) travel with the CEO or (ii) personal travel to accommodate business demands on an executive’s schedule. With the exception of Mr. Farrell, personal use of aircraft is not available when there is a company need for the aircraft. Use of company aircraft saves substantial time and allows |
of the NEOs or other executive officers used company aircraft for personal travel in |
Other than costs associated with comprehensive executive physical exams (which are exempt from taxation under the Internal Revenue Code)IRC), these perquisites are fully taxable to officers. There is no tax gross-up for imputed income on any perquisites.
EMPLOYMENT CONTINUITY AGREEMENTS
Dominion has entered into Employment Continuity Agreements with all officers to ensure continuity in the event of a change in control ofat Dominion. While Dominion has determined these agreements are consistent with the practices of its peer companies, the most important reason for these agreements is to protect the company in the event of an anticipated or actual change in control of Dominion. In a time of transition, it is critical to protect shareholder value by retaining and continuing to motivate the company’s core management team. In a change in control situation, workloads typically increase dramatically, outside competitors are more likely to attempt to recruit top performers away from the company, and officers and other key employees may consider other opportunities when faced with uncertainties at their own company. Therefore, the Employment Continuity Agreements provide security and protection to officers in such circumstances for the long-term benefit of the companyDominion and its shareholders.
In determining the appropriate multiples of compensation and benefits payable upon a change in control, Dominion evaluated peer group and general practices and considered the levels of protection necessary to retain officers in such situations. The Employment Continuity Agreements are double-trigger agreements that require both a change in control and a qualifying termination of employment to trigger a benefit. The specific terms of the Employment Continuity Agreements are discussed inAdditional Post-Employment Benefits for NEOsunderPotential Payments Upon Termination or Change in Control.
In January 2013, the CGN Committee approved the elimination of the excise tax gross up provision included in the Employment Continuity Agreement for any new officer elected after February 1, 2013.
OTHER AGREEMENTS
Dominion does not have comprehensive employment agreements or severance agreements for its NEOs. Although the CGN Committee believes the compensation and benefit programs described in this CD&A are appropriate, Dominion, as one of the nation’s largest producers and transporters of energy, is part of a constantly changing and increasingly competitive environment. In recognition of their valuable knowledge and experience and to secure and retain their services, Dominion has entered into letter agreements with eachcertain of theits NEOs to provide certain benefit enhancements or other protections, as described inAdditional Post-Employment Benefits for NEOsDominion Retirement Benefit Restoration Plan, Dominion Executive Supplemental Retirement PlanunderandPotential Payments Upon Termination or Change in Control. No new letter agreements were entered into in 2012.
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OTHER RELEVANT COMPENSATION PRACTICES
Share Ownership Guidelines
Dominion requires officers to own and retain significant amounts of Dominion stock during their careers to align their interests with those of Dominion’s shareholders by promoting a long-term focus through long-term share ownership. The guidelines ensure that management maintains a personal stake in Dominionthe company through significant equity investment in Dominion. Targeted ownership levels are the lesser of the following value or number of shares:
Position | Value/# of Shares | |||
Chairman, President & Chief Executive Officer | 8 x salary/145,000 | |||
Executive Vice | 5 x salary/35,000 | |||
Senior Vice | 4 x salary/20,000 | |||
Vice | 3 x salary/10,000 |
The levels of ownership reflect the increasing level of responsibility for that officer’s position. Shares owned by an officer and his or her immediate family members as well as shares held under companyDominion benefit plans contribute to the ownership targets. Restricted stock, goal-based stock and shares underlying stock options do not contribute to the ownership targets.targets until the shares vest or the options are exercised. Dominion prohibits certain types of transactions related to Dominion stock, including owning derivative securities, hedging transactions, using margin accounts and pledging shares as collateral.
With limited exceptions, officers are expected toUntil an officer meets his or her ownership target, an officer must retain ownership of their Dominionnet shares from stock includingoption exercises and all after-tax shares from vesting restricted stock and goal-based shares that have vested, as long as they remain employed by the company.stock awards. Dominion refers to shares held by an officer that are more than 15% above his or her ownership target as “QualifyingQualifying Excess Shares.” Officers may sell, up to 50% of theirgift or transfer Qualifying Excess Shares at any time, subject to insider trading rules and other policy provisions and may sell all Qualifying Excess Shares duringas long as the one-year period preceding retirement. Qualifying Excess Shares may also be giftedsale, gift or transfer does not cause an executive to a charitable organizationfall below his or put into a trust outside of the officer’s control for estate planning purposes at any time.her ownership target.
At least annually, the CGN Committee reviews the share ownership guidelines and monitors compliance by executive officers, both individually and by the officer group as a whole. The NEOs’ ownership is shown in theDirector and Officer Share Ownershiptable;As of January 1, 2013, each NEO exceedsexceeded his share ownership target.
Shares Owned and Counted Toward Target(1) | Share Ownership Target(2) | |||||||
Thomas F. Farrell II | 573,972 | 145,000 | ||||||
Mark F. McGettrick | 160,559 | 35,000 | ||||||
David A. Christian | 78,642 | 35,000 | ||||||
Paul D. Koonce | 75,278 | 35,000 | ||||||
David A. Heacock | 24,262 | 20,000 |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Amounts shown are actual and not reduced by their Virginia Power allocation factor.
(1) | Amounts in this column do not include shares of unvested restricted stock which are not counted toward ownership targets |
(2) | Share ownership target is the lesser of salary multiple or number of shares |
Recovery of Incentive Compensation
Consistent with standards established by the Sarbanes-Oxley Act of 2002, Dominion’s Corporate Governance Guidelines authorize the Board to seek recovery of performance-based compensation paid to officers who are found to be personally responsible for fraud or intentional misconduct that causes a restatement of financial results filed with the SEC. Beginning in 2009, the CGN Committee approved a broader clawback provision for inclusion in Dominion’s AIP and long-term incentive performance grant documents. This clawback provision authorizes the CGN Committee, in its discretion and based on facts and circumstances, to recoup AIP and performance grant payouts from any employee whose fraudulent or intentional misconduct (i) directly causes or partially causes the need for a restatement of a financial statement or (ii) relates to or materially affects Dominion’s operations or the employee’s duties at the company. Dominion reserves the right to recover a payout by seeking repayment from the employee, by reducing the amount that would otherwise be payable to the employee under another Dominioncompany benefit plan or compensation program to the extent permitted by applicable law, by withholding future incentive compensation, or any combination of these actions. The clawback provision is in addition to, and not in lieu of, other actions Dominion may take to remedy or discipline misconduct, including termination of employment or a legal action for breach of fiduciary duty, and any actions imposed by law enforcement agencies.
Tax Deductibility of Compensation
CodeIRC Section 162(m) generally disallows a deduction by publicly-heldpublicly held corporations for compensation in excess of $1 million paid to the CEO and next three most highly-compensatedhighly compensated officers other than the CFO. If certain requirements are met, performance-based compensation qualifies for an exemption from the CodeIRC Section 162(m) deduction limit. Dominion intends to provide competitive executive compensation while maximizing Dominion’s tax deduction. While the CGN Committee considers CodeIRC Section 162(m) tax implications when designing annual and long-term compensation programs and approving payouts under such programs, it reserves the right to approve, and in some cases has approved, non-deductible compensation when corporate objectives justify the cost of being unable to deduct such compensation. Dominion’s tax department has advised the CGN Committee that the cost of any such lost tax deductions is not material to the company.
Accounting for Stock-Based Compensation
Dominion measures and recognizes compensation expense in accordance with the FASB guidance for share-based payments, which requires that compensation expense relating to share-based payment transactions be recognized in the financial statements based on the fair value of the equity or liability instruments issued. The CGN Committee considers the accounting treatment of equity and performance-based compensation when approving awards.
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Executive Compensation
SUMMARY COMPENSATION TABLE – AN OVERVIEW
The Summary Compensation Table provides information in accordance with SEC requirements regarding compensation earned by the NEOs, stock awards made to the NEOs, as well as amounts accrued or accumulated during years reported with respect to retirement plans and other items. The NEOs include the CEO, the CFO, and the three most highly compensated executive officers of Virginia Power other than the CEO and CFO.
The amounts reported in the Summary Compensation Table and the other tables below represent the pro-ratedprorated compensation amounts attributable to each NEO’s services performed for Virginia Power. The percentage of each NEO’s overall Dominion services performed for Virginia Power during 20102012 was as follows: Mr. Farrell, 28%29%; Mr. McGettrick, 46%; Mr. Koonce, 85%83%; Mr. Christian, 53%54%; and Mr. Stutts, 42%Heacock, 47%.
The following highlights some of the disclosures contained in this table for the NEOs. Detailed explanations regarding certain types of compensation paid to an NEO are included in the footnotes to the table.
Salary. The amounts in this column are the base salaries earned by the NEOs for the years indicated. For 2010, this amount also includes a 2% merit lump sum payment to all NEOs.
Stock Awards. The amounts in this column reflect the full grant date fair value of the stock awards for accounting purposes for the respective year. The amounts shown for 2008Stock awards are different fromreported in the amounts shownyear in prior years due to a change in SEC reporting requirements.which the awards are granted regardless of when or if the awards vest or are exercised.
Non-Equity Incentive Plan Compensation. This column includes amounts earned under two performance-based programs: the AIP and cash-based performance grant awards under Dominion’s long-term incentive programs.LTIP. These performance programs are based on performance criteria established by the CGN Committee at the beginning of the performance period, with actual performance scored against the pre-set criteria by the CGN Committee at the end of the performance period.
Change in Pension Value and Nonqualified Deferred Compensation Earnings. This column shows any year-over-year increases in the annual accrual of pension and supplemental retirement benefits for the NEOs. These are accruals for future benefits that may be earned under the terms of the retirement plans, and doare not reflect actual payments made during the year to the NEOs. The amounts disclosed reflect the annual change in the
actuarial present value of benefits under defined benefit plans sponsored by the
company,Dominion, which include Dominion’sthe tax-qualified Pension PlanDPP and the nonqualified plans described in the narrative following thePension Benefitstable. The annual change equals the difference in the accumulated amount for the current fiscal year and the accumulated amount for the prior fiscal year, generally using the same actuarial assumptions used for Dominion’s audited financial statements for the applicable fiscal year. For 2009 and 2010, accruedAccrued benefit calculations are based on assumptions that the NEOs would retire at the earliest age at which they are projected to become eligible for full, unreduced pension benefits (including the effect of future service for eligibility purposes), instead of their unreduced retirement age based on current years of service. The application of these assumptions results in a greater increase in the accumulated amount of pension benefits for certain NEOs than would result without the application of these assumptions. This method of calculation does not increase actual benefits payable at retirement but only how much of that benefit is allocated to the increase during 2009 and 2010, respectively. For Mr. McGettrick, the accrued benefit calculation for 2010 also reflectsyears presented in the clarification of the commencement date of his lifetime ESRP benefits.Summary Compensation Table. Please refer to the footnotes to thePension Benefitstable and the narrative following that table for additional information related to actuarial assumptions used to calculate pension benefits.
All Other Compensation. The amounts in this column disclose compensation that is not classified as compensation reportable in another column, including perquisites and benefits with an aggregate value of at least $10,000, the value of company-paid life insurance premiums, company matching contributions to an NEO’s 401(k) Plan account, and company matching contributions paid directly to the NEO that would be credited to the 401(k) Plan if Internal Revenue CodeIRC contribution limits did not apply. For 2010, dividends paid on outstanding restricted stock are not included in All Other Compensation in accordance with SEC rules as the value of the dividends is factored into the grant date fair value of the restricted stock.
Total. The number in this column provides a single figure that represents the total compensation either earned by each NEO for the years indicated or accrued benefits payable in later years and required to be disclosed by SEC rules in this table. It does not reflect actual compensation paid to the NEO during the year, but is the sum of the dollar values of each type of compensation quantified in the other columns in accordance with SEC rules.
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SUMMARY COMPENSATION TABLE
The following table presents information concerning compensation paid or earned by the NEOs for the years ended December 31, 2010, 20092012, 2011 and 20082010, as well as the grant date fair value of stock awards and changes in pension value.
Name and Principal Position | Year | Salary(1) | Stock Awards(2) | Non-Equity Incentive Plan Compensation(3) | Change in Pension Value and Nonqualified Deferred Compensation Earnings(4) | All Other Compensation(5) | Total | Year | Salary(1) | Stock Awards(2) | Non-Equity Incentive Plan Compensation(3) | Change in Pension Value and Nonqualified Deferred Compensation Earnings(4) | All Other Compensation(5) | Total | ||||||||||||||||||||||||||||||||||||||||||
Thomas F. Farrell II Chairman and Chief Executive Officer | 2010 | $ | 342,720 | $ | 2,164,671 | $ | 1,634,640 | $ | 551,838 | $ | 44,950 | $ | 4,738,819 | 2012 | $ | 381,827 | $ | 1,027,602 | $ | 946,561 | $ | 1,171,041 | $ | 54,815 | $ | 3,581,846 | ||||||||||||||||||||||||||||||
2009 | 348,000 | 870,001 | 1,604,280 | 461,615 | 188,429 | 3,472,325 | 2011 | 393,084 | 1,127,702 | 2,351,094 | 584,944 | 51,827 | 4,508,651 | |||||||||||||||||||||||||||||||||||||||||||
2008 | 452,833 | 1,140,010 | 2,559,300 | 997,551 | 238,040 | 5,387,734 | 2010 | 342,720 | 2,164,671 | 1,634,640 | 551,838 | 44,950 | 4,738,819 | |||||||||||||||||||||||||||||||||||||||||||
Mark F. McGettrick Executive Vice President and Chief Financial Officer | 2010 | 305,402 | 413,970 | 841,435 | 1,590,831 | 33,281 | 3,184,919 | 2012 | 311,880 | 1,632,701 | 480,389 | 1,169,718 | 31,291 | 3,625,979 | ||||||||||||||||||||||||||||||||||||||||||
2009 | 298,195 | 345,010 | 766,034 | 861,244 | 83,450 | 2,353,933 | 2011 | 320,948 | 485,013 | 1,008,431 | 802,520 | 33,962 | 2,650,874 | |||||||||||||||||||||||||||||||||||||||||||
2008 | 327,253 | 390,014 | 1,061,894 | 376,799 | 87,288 | 2,243,248 | 2010 | 305,402 | 413,970 | 841,435 | 1,590,831 | 33,281 | 3,184,919 | |||||||||||||||||||||||||||||||||||||||||||
Paul D. Koonce Executive Vice President and COO—DVP | 2010 | 431,679 | 478,139 | 998,467 | 642,025 | 40,721 | 2,591,031 | |||||||||||||||||||||||||||||||||||||||||||||||||
2009 | 242,983 | 220,508 | 533,418 | 188,154 | 58,545 | 1,243,608 | ||||||||||||||||||||||||||||||||||||||||||||||||||
David A. Christian President and COO— Generation | 2010 | �� | 299,384 | 225,247 | 554,103 | 661,527 | 49,013 | 1,789,274 | ||||||||||||||||||||||||||||||||||||||||||||||||
2009 | 259,229 | 152,752 | 434,621 | 588,777 | 67,838 | 1,503,217 | ||||||||||||||||||||||||||||||||||||||||||||||||||
2008 | 263,498 | 159,252 | 517,672 | 299,988 | 64,877 | 1,305,287 | ||||||||||||||||||||||||||||||||||||||||||||||||||
James F. Stutts Senior Vice President & General Counsel | 2010 | 184,212 | 178,497 | 327,583 | 117,069 | 57,295 | 864,656 | |||||||||||||||||||||||||||||||||||||||||||||||||
David A. Christian President and COO—Dominion Generation | 2012 | 323,858 | 1,166,905 | 364,726 | 1,188,167 | 51,191 | �� | 3,094,847 | ||||||||||||||||||||||||||||||||||||||||||||||||
2011 | 309,329 | 309,058 | 608,095 | 682,795 | 52,785 | 1,962,062 | ||||||||||||||||||||||||||||||||||||||||||||||||||
2010 | 299,384 | 225,247 | 554,103 | 661,527 | 49,013 | 1,789,274 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Paul D. Koonce President and COO—DVP | 2012 | 429,614 | 1,764,103 | 531,159 | 1,115,497 | 46,657 | 3,887,030 | |||||||||||||||||||||||||||||||||||||||||||||||||
2011 | 423,840 | 471,012 | 1,107,655 | 695,145 | 49,323 | 2,746,975 | ||||||||||||||||||||||||||||||||||||||||||||||||||
2010 | 431,679 | 478,139 | 998,467 | 642,025 | 40,721 | 2,591,031 | ||||||||||||||||||||||||||||||||||||||||||||||||||
David A. Heacock President and CNO | 2012 | 206,435 | 117,665 | 159,303 | 462,314 | 22,968 | 968,685 | |||||||||||||||||||||||||||||||||||||||||||||||||
2011 | 215,395 | 128,803 | 318,493 | 388,820 | 20,921 | 1,072,432 | ||||||||||||||||||||||||||||||||||||||||||||||||||
2010 | 195,288 | 114,750 | 292,961 | 346,705 | 19,595 | 969,299 |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the appropriateapplicable portion related to their service for Virginia Power in the year presented.
(1) |
|
(2) | The amounts in this column reflect the |
(3) | The |
(4) | All amounts in this column are for the aggregate change in the actuarial present value of the NEO’s accumulated benefit under the |
(5) | All Other Compensation amounts for |
Name | Executive Perquisites(a) | Life Insurance Premiums | Employee 401(k) Plan Match(b) | Company Match Above IRS Limits(c) | Other Cash Payments(d) | Total All Other Compensation(e) | Executive Perquisites(a) | Life Insurance Premiums | Employee 401(k) Plan Match(b) | Company Match Above IRS Limits(c) | Total All Other Compensation | |||||||||||||||||||||||||||||||||
Thomas F. Farrell II | $ | 21,889 | $ | 10,307 | $ | 2,058 | $ | 10,696 | $ | — | $ | 44,950 | $ | 31,629 | $ | 8,646 | $ | 2,202 | $ | 12,338 | $ | 54,815 | ||||||||||||||||||||||
Mark F. McGettrick | 15,173 | 6,131 | 4,508 | 7,469 | — | 33,281 | 12,145 | 6,670 | 4,583 | 7,893 | 31,291 | |||||||||||||||||||||||||||||||||
David A. Christian | 15,491 | 22,745 | 5,396 | 7,559 | 51,191 | |||||||||||||||||||||||||||||||||||||||
Paul D. Koonce | 17,583 | 10,441 | 6,248 | 6,449 | — | 40,721 | 22,768 | 11,000 | 6,190 | 6,699 | 46,657 | |||||||||||||||||||||||||||||||||
David A. Christian | 17,037 | 20,235 | 5,194 | 6,547 | — | 49,013 | ||||||||||||||||||||||||||||||||||||||
James F. Stutts | 10,425 | 19,576 | 3,087 | 3,108 | 21,099 | 57,295 | ||||||||||||||||||||||||||||||||||||||
David A. Heacock | 9,068 | 5,642 | 4,706 | 3,552 | 22,968 |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the appropriate NEOs listed in the table reflects only the appropriateapplicable portion related to their service for Virginia Power in the year presented.
(a) | Unless noted, the amounts in this column for all NEOs are comprised of the following: personal use of company vehicle and financial planning and health and wellness allowance. For Mr. Farrell, the amounts in this column also include personal use of the corporate aircraft. The value of Mr. Farrell’s personal use of the aircraft during |
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(b) | Employees initially hired before 2008 who contribute to the 401(k) Plan receive a matching contribution of 50 cents for each dollar contributed up to 6% of compensation (subject to IRS limits) for employees who have less than 20 years of service, and 67 cents for each dollar contributed up to 6% of compensation (subject to IRS limits) for employees who have 20 or more years of service. |
(c) | Represents each payment of |
GRANTSOF PLAN-BASED AWARDS
The following table provides information about stock awards and non-equity incentive awards granted to the NEOs during the year ended December 31, 2010.2012.
Name | Grant Date(1) | Grant Approval Date(1) | Estimated Future Payouts Under Non- Equity Incentive Plan Awards(1) | All Other Awards: | Grant Date of Stock and Options | |||||||||||||||||||
Threshold ($) | Target ($) | Maximum ($) | ||||||||||||||||||||||
Thomas F. Farrell II | ||||||||||||||||||||||||
2010 Annual Incentive Plan(2) | $ | 0 | $ | 420,000 | $ | 840,000 | ||||||||||||||||||
2010 Performance Grant(3) | $ | 0 | 980,000 | 1,960,000 | ||||||||||||||||||||
2010 Restricted Stock Grant(4) | 2/1/2010 | 1/21/2010 | 26,161 | $ | 979,991 | |||||||||||||||||||
Executive Restricted Stock Grant(5) | 12/17/2010 | 12/16/2010 | 28,000 | $ | 1,184,680 | |||||||||||||||||||
Mark F. McGettrick | ||||||||||||||||||||||||
2010 Annual Incentive Plan(2) | $ | 0 | 299,414 | 598,828 | ||||||||||||||||||||
2010 Performance Grant(3) | $ | 0 | 414,000 | 828,000 | ||||||||||||||||||||
2010 Restricted Stock Grant(4) | 2/1/2010 | 1/21/2010 | 11,051 | $ | 413,970 | |||||||||||||||||||
Paul D. Koonce | ||||||||||||||||||||||||
2010 Annual Incentive Plan(2) | $ | 0 | 380,894 | 761,787 | ||||||||||||||||||||
2010 Performance Grant(3) | $ | 0 | 478,125 | 956,250 | ||||||||||||||||||||
2010 Restricted Stock Grant(4) | 2/1/2010 | 1/21/2010 | 12,764 | $ | 478,139 | |||||||||||||||||||
David A. Christian | ||||||||||||||||||||||||
2010 Annual Incentive Plan(2) | $ | 0 | 249,487 | 498,974 | ||||||||||||||||||||
2010 Performance Grant(3) | $ | 0 | 225,250 | 450,500 | ||||||||||||||||||||
2010 Restricted Stock Grant(4) | 2/1/2010 | 1/21/2010 | 6,013 | $ | 225,247 | |||||||||||||||||||
James F. Stutts | ||||||||||||||||||||||||
2010 Annual Incentive Plan(2) | $ | 0 | 144,480 | 288,960 | ||||||||||||||||||||
2010 Performance Grant(3) | $ | 0 | 178,500 | 357,000 | ||||||||||||||||||||
2010 Restricted Stock Grant(4) | 2/1/2010 | 1/21/2010 | 4,765 | $ | 178,497 |
Name | Grant Date(1) | Grant Approval Date(1) | Estimated Future Payouts Under Non-Equity Incentive Plan Awards | All Other Stock Awards: Number of Shares of Stock or Units | Grant Date of Stock and | |||||||||||||||||||
Threshold | Target | Maximum | ||||||||||||||||||||||
Thomas F. Farrell II | ||||||||||||||||||||||||
2012 Annual Incentive Plan(2) | $ | 0 | $ | 482,899 | $ | 965,797 | ||||||||||||||||||
2012 Cash Performance Grant(3) | 0 | 1,027,600 | 2,055,200 | |||||||||||||||||||||
2012 Restricted Stock Grant(4) | 2/1/2012 | 1/19/2012 | 20,380 | $ | 1,027,602 | |||||||||||||||||||
Mark F. McGettrick | ||||||||||||||||||||||||
2012 Annual Incentive Plan(2) | 0 | 313,402 | 626,804 | |||||||||||||||||||||
2012 Cash Performance Grant(3) | 0 | 486,944 | 973,888 | |||||||||||||||||||||
2012 Restricted Stock Grant(4) | 2/1/2012 | 1/19/2012 | 9,657 | 486,944 | ||||||||||||||||||||
Executive Restricted Stock Grant(5) | 12/20/2012 | 12/17/2012 | 21,949 | 1,145,757 | ||||||||||||||||||||
David A. Christian | ||||||||||||||||||||||||
2012 Annual Incentive Plan(2) | 0 | 294,901 | 589,802 | |||||||||||||||||||||
2012 Cash Performance Grant(3) | 0 | 357,485 | 714,970 | |||||||||||||||||||||
2012 Restricted Stock Grant(4) | 2/1/2012 | 1/19/2012 | 7,090 | 357,495 | ||||||||||||||||||||
Executive Restricted Stock Grant(5) | 12/20/2012 | 12/17/2012 | 15,505 | 809,410 | ||||||||||||||||||||
Paul D. Koonce | ||||||||||||||||||||||||
2012 Annual Incentive Plan(2) | 0 | 388,538 | 777,076 | |||||||||||||||||||||
2012 Cash Performance Grant(3) | 0 | 526,129 | 1,052,258 | |||||||||||||||||||||
2012 Restricted Stock Grant(4) | 2/1/2012 | 1/19/2012 | 10,435 | 526,137 | ||||||||||||||||||||
Executive Restricted Stock Grant(5) | 12/20/2012 | 12/17/2012 | 23,715 | 1,237,966 | ||||||||||||||||||||
David A. Heacock | ||||||||||||||||||||||||
2012 Annual Incentive Plan(2) | 0 | 145,437 | 290,873 | |||||||||||||||||||||
2012 Cash Performance Grant(3) | 0 | 117,650 | 235,300 | |||||||||||||||||||||
2012 Restricted Stock Grant(4) | 2/1/2012 | 1/19/2012 | 2,333 | 117,665 |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the appropriateapplicable portion related to their service for Virginia Power in the year presented.
(1) | On January |
(2) | Amounts represent the range of potential payouts under the |
CGN Committee establishes target awards for each NEO based on his salary level and expressed as a percentage of the individual NEO’s base salary. The target award is the amount of cash that will be paid if the plan is fully funded and payout goals are achieved. For the |
(3) | Amounts represent the range of potential payouts under the |
The performance grant is forfeited in its entirety if an officer voluntarily terminates employment or is terminated with cause before the vesting date. The grants have pro-rated vesting for retirement, termination without cause, death or disability. In the case of retirement, pro-rated vesting will not occur if the CEO (or, for the CEO, the CGN Committee) determines the officer’s retirement is detrimental to the company. Payout for an officer who retires or whose employment is terminated without cause, is made following the end of the performance period so that the officer is rewarded only to the extent the performance goals are achieved. In the case of death or disability, payout is made as soon as possible to facilitate the administration of the officer’s estate or financial planning. The payout amount will be the greater of the officer’s target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominion’s financial statements. |
In the event of a change in control, the performance grant is vested in its entirety and payout of the performance grant will occur as soon as administratively feasible following the change in control date at an amount that is the greater of an officer’s target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominion’s financial statements. |
(4) | The |
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CEO, the CGN Committee) determines the officer’s retirement is detrimental to |
(5) | On December |
OUTSTANDING EQUITY AWARDSAT FISCAL YEAR-END
The following table summarizes equity awards made to NEOs that were outstanding as of December 31, 2010.2012. There were no unexercised or unexercisable option awards outstanding for any NEOs as of December 31, 2010.2012.
Name
| Stock Awards | |||||||||||||||
Stock Awards | ||||||||||||||||
Name
| Number of (#) | Market Value of ($) | Number of Shares or Units of Stock that Have Not Vested (#) | Market Value of Shares or Units of Stock That Have Not Vested(1)($) | ||||||||||||
20,568 | (2) | $ | 878,665 | 27,431 | (2) | $ | 1,420,926 | |||||||||
23,877 | (3) | 1,020,025 | 23,601 | (3) | 1,222,532 | |||||||||||
26,161 | (4) | 1,117,598 | 20,380 | (4) | 1,055,684 | |||||||||||
28,000 | (5) | 1,196,160 | 31,839 | (5) | 1,649,260 | |||||||||||
Mark F. McGettrick | 8,447 | (2) | 360,856 | 11,011 | (2) | 570,370 | ||||||||||
9,806 | (3) | 418,912 | 10,526 | (3) | 545,247 | |||||||||||
11,051 | (4) | 472,099 | 9,657 | (4) | 500,233 | |||||||||||
Paul D. Koonce | 9,366 | (2) | 400,116 | |||||||||||||
10,873 | (3) | 464,495 | ||||||||||||||
12,764 | (4) | 545,278 | 21,949 | (6) | 1,136,958 | |||||||||||
David A. Christian | 4,217 | (2) | 180,150 | 6,122 | (2) | 317,120 | ||||||||||
4,896 | (3) | 209,157 | 6,971 | (3) | 361,098 | |||||||||||
6,013 | (4) | 256,875 | 7,090 | (4) | 367,262 | |||||||||||
James F. Stutts(6) | 2,571 | (2) | 109,833 | |||||||||||||
15,505 | (6) | 803,159 | ||||||||||||||
Paul D. Koonce | 12,393 | (2) | 641,957 | |||||||||||||
2,984 | (3) | 127,476 | 10,662 | (3) | 552,292 | |||||||||||
4,765 | (4) | 203,561 | 10,435 | (4) | 540,533 | |||||||||||
23,715 | (6) | 1,228,437 | ||||||||||||||
David A. Heacock | 2,826 | (2) | 146,387 | |||||||||||||
2,702 | (3) | 139,964 | ||||||||||||||
2,333 | (4) | 120,849 |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. CompensationAmounts for the NEOs listed in the table reflectsreflect only the appropriateapplicable portion related to their service for Virginia Power forin the year presented.
The market value is based on closing stock price of |
(2) | Shares scheduled to vest on |
(3) | Shares scheduled to vest on February 1, |
(4) | Shares scheduled to vest on February 1, |
(5) | Shares scheduled to vest on December 17, 2015. Amount includes dividends reinvested into additional shares that are restricted and subject to the same terms and conditions of the underlying restricted stock grant. |
(6) |
|
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OPTION EXERCISESAND STOCK VESTED
The following table provides information about the value realized by NEOs during the year ended December 31, 20102012 on vested restricted stock awards. There were no option exercises by NEOs in 2010.2012.
Stock Awards | ||||||||||||||||
Name | Number of (#) | Value ($) | Number of Shares Acquired on Vesting | Value Realized on Vesting | ||||||||||||
Thomas F. Farrell II | 18,773 | $ | 785,275 | 25,037 | $ | 1,262,366 | ||||||||||
Mark F. McGettrick | 7,710 | 322,509 | 9,770 | 492,603 | ||||||||||||
David A. Christian | 4,985 | 251,344 | ||||||||||||||
Paul D. Koonce | 8,549 | 357,605 | 10,557 | 532,284 | ||||||||||||
David A. Christian | 3,849 | 161,004 | ||||||||||||||
James F. Stutts | 9,304 | 362,468 | ||||||||||||||
David A. Heacock | 2,341 | 118,033 |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the appropriateapplicable portion related to their service for Virginia Power forin the year presented.
PENSION BENEFITS
The following table shows the actuarial present value of accumulated benefits payable to NEOs, together with the number of years of benefit service credited to each NEO, under the plans listed in the table. Values are computed as of December 31, 2010,2012, using the same interest rate and mortality assumptions used in determining the aggregate pension obligations disclosed in Dominion’s financial statements. The years of credited service and the present value of accumulated benefits used in the table below were determined by ourthe plan actuaries, using the appropriate accrued service, and pay and other assumptions similar to those used for accounting and disclosure purposes. Please refer toActuarial Assumptions Used to Calculate Pension Benefitsfor detailed information regarding these assumptions.
Name | Plan Name | Number of Years Credited Service(1) | Present Value of Accumulated Benefit(2) | Plan Name | Number of Years Credited Service(1) | Present Value of Accumulated Benefit(2) | ||||||||||||||
Thomas F. Farrell II | Pension Plan | 15.00 | $ | 164,027 | Dominion Pension Plan | 17.00 | $ | 299,495 | ||||||||||||
Benefit Restoration Plan | 26.00 | 1,983,467 | Benefit Restoration Plan | 28.00 | 3,079,682 | |||||||||||||||
Supplemental Retirement Plan | 26.00 | 3,291,133 | Supplemental Retirement Plan | 28.00 | 4,027,674 | |||||||||||||||
Mark F. McGettrick | Pension Plan | 26.50 | 406,415 | Dominion Pension Plan | 28.50 | 659,443 | ||||||||||||||
Benefit Restoration Plan | 30.00 | 2,244,665 | Benefit Restoration Plan | 30.00 | 3,049,238 | |||||||||||||||
Supplemental Retirement Plan | 30.00 | 2,284,161 | Supplemental Retirement Plan | 30.00 | 3,136,378 | |||||||||||||||
David A. Christian | Dominion Pension Plan | 28.50 | 965,441 | |||||||||||||||||
Benefit Restoration Plan | 28.50 | 1,930,290 | ||||||||||||||||||
Supplemental Retirement Plan | 28.50 | 2,567,957 | ||||||||||||||||||
Paul D. Koonce | Pension Plan | 12.00 | 305,759 | Dominion Pension Plan | 14.00 | 559,634 | ||||||||||||||
Benefit Restoration Plan | 12.00 | 453,179 | Benefit Restoration Plan | 14.00 | 753,813 | |||||||||||||||
Supplemental Retirement Plan | 12.00 | 2,133,063 | Supplemental Retirement Plan | 14.00 | 3,295,194 | |||||||||||||||
David A. Christian | Pension Plan | 26.50 | 572,903 | |||||||||||||||||
David A. Heacock | Dominion Pension Plan | 25.50 | 697,260 | |||||||||||||||||
Benefit Restoration Plan | 26.50 | 1,250,127 | Benefit Restoration Plan | 25.50 | 487,554 | |||||||||||||||
Supplemental Retirement Plan | 26.50 | 1,717,741 | Supplemental Retirement Plan | 25.50 | 663,178 | |||||||||||||||
James F. Stutts(3) | Pension Plan | 12.75 | 230,285 | |||||||||||||||||
Benefit Restoration Plan | 21.00 | 587,375 | ||||||||||||||||||
Supplemental Retirement Plan | 21.00 | 728,642 |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the appropriateapplicable portion related to their service for Virginia Power forin the year presented.
(1) | Years of credited service shown in this column for the DPP are actual years accrued by an NEO from his date of participation to December 31, |
(2) | The amounts in this column are based on actuarial assumptions that all of the NEOs would retire at the earliest age they become eligible for unreduced benefits, which is (i) age 60 for Messrs. Farrell, Koonce, Christian and |
|
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Dominion Pension Plan
The Dominion Pension PlanDPP is a tax-qualified defined benefit pension plan. All of the NEOs participate in the Pension Plan.DPP. The Pension PlanDPP provides unreduced retirement benefits at termination of employment at or after age 65 or, with three years of service, at age 60. A participant who has attained age 55 with three years of service may elect early retirement benefits at a reduced amount. If a participant retires between ages 55 and 60, the benefit is reduced 0.25% per month for each month after age 58 and before age 60, and reduced 0.50% per month for each month between ages 55 and 58. All of the NEOs have more than three years of service.
The Pension PlanDPP basic benefit is calculated using a formula based on (1) age at retirement; (2) final average earnings; (3) estimated Social Security benefits; and (4) credited service. Final average earnings are the average of the participant’s 60 highest consecutive months of base pay during the last 120 months worked. Final average earnings do not include compensation payable under the AIP, the value of equity awards, gains from the exercise of stock options, long-term cash incentive awards, perquisites or any other form of compensation other than base pay.
Credited service is measured in months, up to a maximum of 30 years of credited service. The estimated Social Security benefit taken into account is the assumed Social Security benefit payable starting at age 65 or actual retirement date, if later, assuming that the participant has no further employment after leaving Dominion. These factors are then applied in a formula.
The formula has different percentages for credited service through December 31, 2000 and on and after January 1, 2001. The benefit is the sum of the amounts from the following two formulas.
For | ||||||
2.03%times Final Average Earningstimes Credited
| Minus | 2.00%times estimated Social Security benefittimes Credited Service before 2001 | ||||
For | ||||||
1.80%times Final Average Earningstimes Credited
| Minus | 1.50%times estimated Social Security benefittimes Credited Service after 2000 |
Credited Serviceservice is limited to a total of 30 years for all parts of the formula and Credited Servicecredited service after 2000 is limited to 30 years minus Credited Servicecredited service before 2001.
Benefit payment options are (1) a single life annuity or (2) a choice of a 50%, 75% or 100% joint and survivor annuity. A Social Security leveling option is available with any of the benefit forms. The normal form of benefit is a single life annuity for unmarried participants and a 50% joint and survivor annuity for married participants. All of the payment options are actuarially equivalent in value to the single life annuity. The Social Security leveling option pays a larger benefit equal to the estimated Social Security benefit until the participant is age 62 and then reduced payments after age 62.
The DPP also includes a special retirement account, which is in addition to the pension benefit. The special retirement account is credited with 2% of base pay each month as well as interest
based on the 30-year Treasury bond rate set annually (4.19%(3.18% in 2010)2012). The special retirement account can be paid in a lump sum or paid in the form of an annuity benefit.
A participant becomes vested in his or her benefit after completing three years of service. A vested participant who terminates employment before age 55 can start receiving benefit payments calculated using terminated vested reduction factors at any time after attaining age 55. If payments begin before age 65, then the following reduction factors for the portion of the benefits earned after 2000 apply: age 64 – 9%; age 63 – 16%; age 62 – 23%; age 61 – 30%; age 60 – 35%; age 59 – 40%; age 58 – 44%; age 57 – 48%; age 56 – 52%; and age 55 – 55%.
The Internal Revenue CodeIRC limits the amount of compensation that may be included in determining pension benefits under qualified pension plans. For 2010,2012, the compensation limit was $245,000.$250,000. The Internal Revenue CodeIRC also limits the total annual benefit that may be provided to a participant under a qualified defined benefit plan. For 2010,2012, this limitation was the lesser of (i) $195,000$200,000 or (ii) the average of the participant’s compensation during the three consecutive years in which the participant had the highest aggregate compensation.
Dominion Retirement Benefit Restoration Plan
The BRP is a nonqualified defined benefit pension plan designed to make up for benefit reductions under the DPP due to the limits imposed by the Internal Revenue Code.IRC.
A Dominion employee is eligible to participate in the BRP if (1) he or she is a member of management or a highly compensated employee, (2) his or her DPP benefit is or has been limited by the Internal Revenue CodeIRC compensation or benefit limits, and (3) he or she has been designated as a participant by the CGN Committee. A participant remains a participant until he or she ceases to be eligible for any reason other than retirement or until his or her status as a participant is revoked by the CGN Committee.
Upon retirement, a participant’s BRP benefit is calculated using the same formula (except that the IRC salary limit is not applied) used to determine the participant’s default annuity form of benefit under the DPP (single life annuity for unmarried participants and 50% joint and survivor annuity for married participants), and then subtracting the benefit the participant is entitled to receive under the DPP. To accommodate the enactment of Internal Revenue CodeIRC Section 409A, the portion of a participant’s BRP benefit that had accrued as of December 31, 2004 is frozen, but the calculation of the overall restoration benefit is not changed.
The restoration benefit is generally paid in the form of a single lump sum cash payment. However, a participant may elect to receive a single life or 50% or 100% joint and survivor annuity for the portion of his or her benefit that accrued prior to 2005. For the portion of his or her benefit that accrued in 2005 or later, a participant may also elect to receive a 75% joint and survivor annuity. The lump sum calculation includes an amount approximately equivalent to the amount of taxes the participant will owe on the lump sum payment so that the participant will have sufficient funds, on an after-tax basis, to purchase an annuity contract.
A participant who terminates employment before he or she is eligible for benefits under the DPP generally is not entitled to a restoration benefit. Messrs. Farrell and McGettrick have been granted age and service credits for purposes of calculating their DPP and BRP benefits. Per Mr. Farrell,Farrell’s letter agreement, he was granted 25 years of service when he reached age 55 and will continue to accrue service as long as he remains employed. At age 60, benefits will be calculated based on 30 years of service, if he remains employed. Mr. McGettrick, having attained age 55,50, has earned benefits based on 25 years of service; if he remains
146 |
employed until age 60, benefits will be calculated based on 30 years of service. Mr. McGettrick, having attained age 50, has earned benefits calculated based on five additional years of age and service. Mr. Stutts, having attained age 65, has earned benefits based on 20 years of service. For each of these NEOs, the additional years of service count for determining both the amount of benefits and the eligibility to receive them. For additional information regarding service credits, seeAdditional Post-Employment Benefits for NEOsDominion Executive Supplemental Retirement Plan.underPotential Payments Upon Termination or Change in Control.
If a vested participant dies when he or she is retirement eligible (on or after age 55), the participant’s beneficiary will receive the restoration benefit in a single lump sum payment. If a participant dies while employed but before he or she has attained age 55 and the participant is married at the time of death, the participant’s spouse will receive a restoration benefit calculated in the same way as the 50% Qualified Pre-Retirement Survivor Annuityqualified pre-retirement survivor annuity payable under the Pension PlanDPP and paid in a lump sum payment.
Dominion Executive Supplemental Retirement Plan
The ESRP is a nonqualified defined benefit plan that provides for an annual retirement benefit equal to 25% of a participant’s final cash compensation (base salary plus target annual incentive award) payable for a period of 10 years or, for certain participants designated by the CGN Committee, for the participant’s lifetime. To accommodate the enactment of Internal Revenue CodeIRC Section 409A, the portion of a participant’s ESRP benefit that had accrued as of December 31, 2004 is frozen, but the calculation of the overall benefit is not changed.
A Dominion employee is eligible to participate in the ESRP if (1) he or she is a member of management or a highly-compensatedhighly compensated employee, and (2) he or she has been designated as a participant by the CGN Committee. A participant remains a participant until he or she ceases to be eligible for any reason other than retirement or until his or her status as a participant is revoked by the CGN Committee.
A participant is entitled to the full ESRP benefit if he or she separates from service with Dominion after reaching age 55 and achieving 60 months of service. An officer who becomes a participant on or after December 1, 2006, must have reached age 55 and completed 60 months of service as an officer in order to be entitled to a full ESRP benefit. A participant who separates from service with Dominion with at least 60 months of service but who has not yet reached age 55 is entitled to a reduced, pro-rated retirement benefit. A participant who separates from service with Dominion with fewer than 60 months of service is generally not entitled to an ESRP benefit unless the participant separated from service on account of disability or death.
The ESRP benefit is generally paid in the form of a single lump sum cash payment. However, a participant may elect to receive the portion of his or her benefit that had accrued as of December 31, 2004 in monthly installments. For any new participants, the ESRP benefit must be paid in the form of a single lump sum cash payment. The lump sum calculation includes an amount approximately equivalent to the amount of taxes the participant will owe on the lump sum payment so that the participant will have sufficient funds, on an after-tax basis, to purchase a 10-year or lifetime annuity contract.
All of the NEOs except Mr. Koonce are currently entitled to a full ESRP retirement benefit. If Mr. Koonce terminates employment before he attainsattaining age 55, he will receive a pro-rated ESRP
benefit. Based on determinations made by the CGN Committee,terms of their individual letter agreements, Messrs. Farrell, McGettrick and Koonce will receive an ESRP benefit calculated as a lifetime benefit, andbenefit. Mr. McGettrick will receivehas earned five years of additional age and service credit for purposes of computing his retirement benefits and eligibility for benefits under the ESRP, benefits calculatedlong-term incentive grants, and retiree medical and life insurance plans as a lifetime benefit provided he remainshas met the requirement of remaining employed with Dominion until attainment ofhe attained age 55.50. Under his letter agreement, Mr. Christian will receive ESRP benefits calculated as a lifetime benefit provided he remains employed with Dominion until attainment of age 60. As consideration for this benefit, Mr. Christian has agreed not to compete with Dominion for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.
Actuarial Assumptions Used to Calculate Pension Benefits
Actuarial assumptions used to calculate DPP benefits are prescribed by the terms of the DPP based on Internal Revenue CodeIRC and Pension Benefit Guaranty CorporationPBGC requirements. The present value of the accumulated benefit is calculated using actuarial and other factors as determined by the plan actuaries and approved by Dominion. Actuarial assumptions used for the December 31, 20102012 benefit calculations shown in thePension Benefits table useinclude a discount rate of 5.90%4.40% to determine the present value of the future benefit obligations for the DPP, BRP and ESRP and a lump sum interest rate of 5.15%3.65% to estimate the lump sum values of BRP and ESRP benefits. Each NEO is assumed to retire at the earliest age at which he is projected to become eligible for full, unreduced pension benefits. Beginning with the 2009 calculations, for purposes of estimating future eligibility for unreduced DPP and ESRP benefits, the effect of future service is considered. Each NEO is assumed to commence DPP payments at the same age as BRP payments. The longevity assumption used to determine the present value of benefits is the same assumption used for financial reporting of the DPP liabilities, with no assumed mortality before retirement age. Assumed mortality after retirement is based on tables from the Society of Actuaries’ RP-2000 study, projected from 2000 to 2010a point five years beyond the calculation date (this year, to 2017) with 50%100% of the Scale AA factors, and further adjusted for Dominion experience by using an age set-forward factor. For BRP and ESRP benefits, other actuarial assumptions include an assumed tax rate of 40%42%. BRP and ESRP benefits are assumed to be paid as lump sums; pension plan benefits are assumed to be paid as annuities.
The discount rate for calculating lump sum BRP and ESRP payments at the time an officer terminates employment is selected by Dominion’s Administrative Benefits Committee and adjusted periodically. For 2010,year 2012, a 5.28%5.09% discount rate was used to determine the lump sum payout amounts. For 2010 and later years, theThe discount rate for each year will be based on a rolling average of the blended rate published by the Pension Benefit Guaranty CorporationPBGC in October of the previous five years.
147
NONQUALIFIED DEFERRED COMPENSATION
Name | Aggregate Earnings (as of 12/31/2010) | Aggregate Balance (as of 12/31/2010) | Aggregate Earnings (as of 12/31/2012)* | Aggregate Distributions | Aggregate Balance (as of 12/31/2012) | |||||||||||||||
Thomas F. Farrell II | $ | 1,305 | $ | 3,900 | $ | — | $ | — | $ | — | ||||||||||
Mark F. McGettrick | 39,837 | 354,081 | — | — | — | |||||||||||||||
David A. Christian | 256 | — | 15,891 | |||||||||||||||||
Paul D. Koonce | 86,965 | 987,292 | 22,404 | — | 1,146,855 | |||||||||||||||
David A. Christian | 636 | 14,957 | ||||||||||||||||||
James F. Stutts | 32,207 | 250,851 | ||||||||||||||||||
David A. Heacock | — | — | — |
*No preferential earnings are paid and therefore no earnings from these plans are included in the Summary Compensation Table. Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the appropriateapplicable portion related to their service for Virginia Power forin the year presented.
At this time, Dominion does not offer any nonqualified elective deferred compensation plans to its officers or other employees. TheNonqualified Deferred Compensation table reflects, in aggregate, the plan balances for two former plans offered to Dominion officers and other highly compensated employees: Dominion Resources, Inc. Executives’the Frozen Deferred Compensation Plan (Frozen Deferred Compensation Plan) and Dominion Resources, Inc. Security Option Plan (Frozen DSOP),the Frozen DSOP, which were frozen as of December 31, 2004. Although the Frozen DSOP was an option plan rather than a deferred compensation plan, Dominion is including information regarding the plan and any balances in this table to make full disclosure about possible future payments to officers under Dominion’s employee benefit plans.
Frozen Deferred Compensation Plan
The Frozen Deferred Compensation Plan includes amounts previously deferred from one of the following categories of compensation: (i) salary; (ii) bonus; (iii) vesting restricted stock,stock; and (iv) gains from stock option exercises. The plan also provided for company contributions of lost company 401(k) Plan match contributions and transfers from several CNG deferred compensation plans. The Frozen Deferred Compensation Plan offers 2827 investment funds for the plan balances, including a Dominion Resources Stock Fund. Participants may change investment elections on any business day. Any vested restricted stock and gains from stock option exercises that were deferred were automatically allocated to the Dominion Resources Stock Fund and this allocation cannot be changed. Earnings are calculated based on the performance of the underlying investment fund.
The NEOs invested in the following funds withhad rates of returns for 20102012 as follows: Vanguard 500 Index Fund, 14.9%; Dominion Resources Stock Fund, 14.47%1.66%; and Dominion Fixed Income Fund, 4.19%3.31%. The Vanguard 500 Index Fund has the same rate of return as the corresponding publicly available mutual fund.
The Dominion Fixed Income Fund is an investment option that provides a fixed rate of return each year based on a formula that is tied to the adjusted federal long-term rate published by the IRS in November prior to the beginning of the year. Dominion’s Asset Management Committee determines the rate based on its estimate of the rate of return on Dominion assets in the trust for the Frozen Deferred Compensation Plan.
The default Benefit Commencement Date is February 28 after the year in which the participant retires, but the participant may select a different Benefit Commencement Date in accordance with the plan. Participants may change their Benefit Commencement Date election; however, a new election must be made
at least six months before an existing Benefit Commencement Date. Withdrawals less than six months prior to an existing Benefit Commencement Date are subject to a 10% early withdrawal penalty. Account balances must be fully paid out no later than the February 28 that is 10 calendar years after a participant retires or becomes disabled. If a participant retires from Dominion, he or she may continue to defer an account balance provided that the total balance is distributed by this deadline. In the event of termination of employment for reasons other than death, disability or retirement before an elected Benefit Commencement Date, benefit payments will be distributed in a lump sum as soon as administratively practicable. Hardship distributions, prior to an elected Benefit Commencement Date, are available under certain limited circumstances.
Participants may elect to have their benefit paid in a lump sum payment or equal annual installments over a period of whole years from one to 10 years. Participants have the ability to change their distribution schedule for benefits under the plan by giving six months notice to the plan administrator. Once a participant begins receiving annual installment payments, the participant can make a one-time election to either (1) receive the remaining account balance in the form of a lump sum distribution or (2) change the remaining installment payment period. Any election must be approved by the company before it is effective. All distributions are made in cash with the exception of the Deferred Restricted Stock Account and the Deferred Stock Option Account, which are distributed in the form of Dominion common stock.
Frozen DSOP
The Frozen DSOP enabled employees to defer all or a portion of their salary and bonus and receive options on various mutual funds. Participants also received lost company matching contributions to the 401(k) Plan in the form of options under this plan. DSOP options can be exercised at any time before their expiration date. On exercise, the participant receives the excess of the value, if any, of the underlying mutual funds over the strike price. The participant can currently choose among options on 27 mutual funds, and there is not a Dominion stock alternative or a fixed income fund. Participants may change options among the mutual funds on any business day. Benefits grow/decline based on the total return of the mutual funds selected. Any options that expire do not have any value. Options expire under the following terms:
Ÿ | Options expire on the last day of the 120th month after retirement or disability; |
Ÿ | Options expire on the last day of the 24th month after the participant’s death (while employed); |
Ÿ | Options expire on the last day of the 12th month after the participant’s severance; |
Ÿ | Options expire on the 90th day after termination with cause; and |
Ÿ | Options expire on the last day of the 120th month after severance following a change in control. |
The NEOsNEO participating in the Frozen DSOP held options on the following publicly available mutual funds,fund, Vanguard Short-Term Bond Index, which had ratesa rate of return for 2010 as noted.2012 of 1.95%.
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POTENTIAL PAYMENTS UPON TERMINATIONOR CHANGEIN CONTROL
Under certain circumstances, Dominion provides benefits to eligible employees upon termination of employment, including a termination of employment involving a change in control of the
company,Dominion, that are in addition to termination benefits for other employees in the same situation.
Change in Control
As discussed in theEmployee and Executive Benefits section of the CD&A, Dominion has entered into an Employment Continuity Agreement with each of its officers, including the NEOs. Each agreement has a three-year term and is automatically extended annually for an additional year, unless cancelled by Dominion.
The Employment Continuity Agreements require two triggers for the payment of most benefits:
Ÿ | There must be a change in control; and |
Ÿ | The executive must either be terminated without cause, or terminate his or her employment with the surviving company after a |
For purposes of the Employment Continuity Agreements, a change in control will occur if (i) any person or group becomes a beneficial owner of 20% or more of the combined voting power of Dominion voting stock or (ii) as a direct or indirect result of, or in connection with, a cash tender or exchange offer, merger or other business combination, sale of assets, or contested election, the directors constituting the Dominion Board before any such transaction cease to represent a majority of Dominion’s or its successor’s Board within two years after the last of such transactions.
If an executive’s employment following a change in control is terminated without cause or due to a constructive termination, the executive will become entitled to the following termination benefits:
Ÿ | Lump sum severance payment equal to three times base salary plus AIP award (determined as the greater of (i) the target annual award for the current year or (ii) the highest actual AIP payout for any one of the three years preceding the year in which the change in control occurs). |
Ÿ | Full vesting of benefits under ESRP and BRP with five years of additional credited age and five years of additional credited service from the change in control date. |
Ÿ | Group-term life insurance. If the officer elects to convert group-term insurance to an individual policy, the company pays the premiums for 12 months. |
Ÿ | Executive life insurance. Premium payments will continue to be paid by Dominion until the earlier of: (1) the fifth anniversary of the termination date, or (2) the later of the 10th anniversary of the policy or the date the officer attains age 64. |
Ÿ | Retiree medical coverage will be determined under the relevant plan with additional age and service credited as provided under an officer’s letter of agreement (if any) and including five additional years credited to age and five additional years credited to service. |
Ÿ | Outplacement services for one year (up to $25,000). |
Ÿ | If any payments are classified as |
executive incurs the excise tax, Dominion will pay the executive an amount equal to the 280G excise tax plus a gross-up multiple. |
In January 2013, the CGN Committee approved the elimination of the excise tax gross up provision included in the Employment Continuity Agreement for any new officer elected after February 1, 2013.
The terms of awards made under the LTIP, rather than the terms of Employment Continuity Agreements, will determine the vesting of each award in the event of a change in control. These provisions are described in theLong-Term Incentive Program section of the CD&A.&A and footnotes to theGrants of Plan-Based Awards table.
Additional Post-Employment BenefitsOther Post Employment Benefit for NEOsMr. Farrell
Under the terms of letter agreements with the NEOs, the following benefits are available in addition to the benefits described above. These benefits are quantified in the table below to the extent they would be payable if the triggering event set forth in the table occurred on December 31, 2010.
Mr. Farrell. Mr. Farrell has earned a lifetime benefit under the ESRP. For purposes of calculating his benefits under the DPP and BRP, Mr. Farrell has earned 25 years of credited service as he has met the requirement of remaining employed until he attained age 55. He will be credited with 30 years of service if he remains employed until he attains age 60. Mr. Farrell will become entitled to a payment of one times salary upon his retirement as consideration for his agreement not to compete with Dominion for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.
Mr. McGettrick. Mr. McGettrick will earn a lifetime benefit under the ESRP if he remains employed until he attains age 55. He has earned five years of additional age and service credit for purposes of computing his retirement benefits and eligibility for benefits under the ESRP, long-term incentive grants, and retiree medical and life insurance plans as he has met the requirement of remaining employed until he attained age 50. If Mr. McGettrick terminates employment before he attains age 55, he will be deemed to have retired for purposes of determining his vesting credit under the terms of his restricted stock and performance grant awards.
Mr. Koonce. Mr. Koonce earned a lifetime benefit under the ESRP in early 2010 upon his attainment of age 50. If Mr. Koonce leaves Dominion before age 55, he will be entitled to a pro-rated ESRP benefit.
Mr. Christian. Mr. Christian will earn a lifetime benefit under the ESRP if he remains employed with Dominion until he attains age 60. As consideration for this benefit, Mr. Christian has agreed not to compete with Dominion for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.
Mr. Stutts. Mr. Stutts joined Dominion mid-career in 1997. At the time of his employment, Dominion agreed to credit him with 20 years of service (eight additional years) if he remained employed until he attained age 65 for purposes of computing his retirement benefits under the Pension Plan and BRP; he has attained age 65. Mr. Stutts retired effective January 1, 2011.
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The following table below provides the incremental payments that would be earned by each NEO if his employment had been terminated, or constructively terminated, as of December 31, 2010.2012. These benefits are in addition to retirement benefits that would be payable on any termination of employment. Please refer to thePension Benefits table for information related to the present value of accumulated retirement benefits payable to the NEOs.
Incremental Payments Upon Termination andor Change in Control
Name | Non-Qualified Plan Payment | Restricted Stock(1) | Performance Grant(1) | Non-Compete Payments(2) | Severance Payments | Retiree Medical and Executive Life Insurance (3) | Outplacement Services | Excise Tax & Tax Gross-Up | Total | Non-Qualified Plan Payment | Restricted Stock(1) | Performance Grant(1) | Non-Compete Payments(2) | Severance Payments | Retiree Medical and Executive Life Insurance(3) | Outplacement Services | Excise Tax & Tax Gross-Up | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Thomas F. Farrell II(4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirement | — | $ | 1,798,614 | $ | 468,696 | $ | 336,000 | $— | $— | $— | $— | $ | 2,603,310 | $— | $ | 2,485,126 | $ | 491,461 | $ | 386,319 | $— | $— | $— | $— | $ | 3,362,906 | ||||||||||||||||||||||||||||||||||||||||||||
Death / Disability | — | 1,818,550 | 468,696 | — | — | — | — | — | 2,287,246 | — | 3,144,840 | 491,461 | — | — | — | — | — | 3,636,301 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in Control(5) | 1,170,788 | 2,413,834 | 511,304 | — | 3,026,016 | — | 7,000 | — | 7,128,942 | 588,482 | 1,873,837 | 536,139 | — | 2,929,365 | — | 7,340 | — | 5,935,163 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Mark F. McGettrick(4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirement | — | 742,675 | 198,000 | — | — | — | — | — | 940,675 | — | 1,055,715 | 232,886 | — | — | — | — | — | 1,288,601 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Death / Disability | — | 1,087,289 | 232,886 | — | — | — | — | — | 1,320,175 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in Control(5) | — | 1,697,168 | 254,058 | — | 2,139,402 | — | 11,458 | — | 4,102,086 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
David A. Christian(4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirement | — | 651,237 | 170,971 | — | — | — | — | — | 822,208 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Death / Disability | — | 673,542 | 170,971 | — | — | — | — | — | 844,513 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in Control(5) | 309,120 | 509,192 | 216,000 | — | 2,205,244 | — | 11,500 | — | 3,251,056 | 375,375 | 1,197,516 | 186,514 | — | 2,004,106 | — | 13,490 | 1,329,761 | 5,106,762 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Paul D. Koonce | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Termination Without Cause | — | 830,146 | 228,669 | — | — | — | — | — | 1,058,815 | — | 1,142,123 | 251,627 | — | — | — | — | — | 1,393,750 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Voluntary Termination | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Termination With Cause | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Death / Disability | — | 830,146 | 228,669 | — | — | — | — | — | 1,058,815 | — | 1,176,238 | 251,627 | — | — | — | — | — | 1,427,865 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in Control(5) | 2,246,648 | 579,742 | 249,456 | — | 3,084,276 | 49,330 | 21,250 | — | 6,230,702 | 2,120,693 | 1,821,216 | 274,502 | — | 2,781,824 | 11,102 | 20,633 | — | 7,029,970 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
David A. Christian(4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
David A. Heacock(4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirement | — | 377,256 | 107,728 | — | — | — | — | — | 484,984 | — | 268,709 | 56,267 | — | — | — | — | — | 324,976 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in Control(5) | 1,110,554 | 268,927 | 117,522 | — | 1,908,890 | — | 13,250 | 1,237,067 | 4,656,210 | 756,132 | 138,584 | 61,383 | — | 1,119,029 | 75,093 | 11,765 | 783,353 | 2,945,339 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
James F. Stutts(4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirement | — | 244,323 | 85,370 | — | — | — | — | — | 329,693 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in Control(5) | 269,988 | 196,547 | 93,130 | — | 1,100,127 | — | 10,500 | 586,005 | 2,256,297 |
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the appropriateapplicable portion related to their service for Virginia Power forin the year presented.
(1) | Grants made in |
(2) | Pursuant to a letter agreement dated February 28, 2003, Mr. Farrell will be entitled to a special payment of one times salary upon retirement in exchange for a two-year non-compete agreement. Mr. Farrell would not be entitled to this non-compete payment in the event of his death. |
(3) | Amounts in this column represent the value of the annual incremental benefit the NEOs would receive for executive life insurance and retiree medical coverage. Mr. McGettrick is eligible for retiree medical and executive life insurance upon any termination due to his letter agreement. Messrs. Farrell |
(4) | For the NEOs who are eligible for retirement (Messrs. Farrell, McGettrick, Christian and Heacock), this table above assumes they would retire in connection with any termination event. |
(5) | Change in control amounts assume that a change in control and a termination or constructive termination takes place on December 31, 2012. The amounts indicated upon a change in control are the incremental amounts attributable to five years of additional age and service credited pursuant to the Employment Continuity Agreements that each NEO would receive over the amounts payable upon a retirement (Messrs. Farrell, McGettrick, Christian, and |
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
DOMINION
The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the headingsDirectorShare Ownership-Director and Officer Share Ownership andSignificant Shareholders in the 20112013 Proxy Statement is incorporated by reference.
The information regarding equity securities of Dominion that are authorized for issuance under its equity compensation plans contained under the headingExecutive Compensation-EquityCompensation Plans in the 20112013 Proxy Statement is incorporated by reference.
VIRGINIA POWER
The table below sets forth as of February 18, 2011,15, 2013, the number of shares of Dominion common stock owned by thedirectors and executive officers of Virginia Power named on the Summary Compensation Table and directors.Table. Dominion owns all of the outstanding common stock of Virginia Power. None of the executive officers or directors own any of the outstanding preferred stock of Virginia Power.
Name of Beneficial Owner | Shares | Restricted Shares | Total(1) | Shares | Restricted Shares | Total(1) | ||||||||||||||||||
Thomas F. Farrell II | 469,137 | 432,553 | 901,690 | 624,714 | 335,782 | 960,496 | ||||||||||||||||||
Mark F. McGettrick | 123,411 | 86,678 | 210,089 | 175,794 | 113,510 | 289,304 | ||||||||||||||||||
Steven A. Rogers | 40,870 | 17,953 | 58,823 | 53,431 | 11,368 | 64,799 | ||||||||||||||||||
David A. Christian | 67,126 | 41,463 | 108,589 | 86,198 | 68,250 | 154,448 | ||||||||||||||||||
David A. Heacock | 28,315 | 16,240 | 44,555 | |||||||||||||||||||||
Paul D. Koonce | 90,514 | 51,748 | 142,262 | 69,099 | 67,754 | 136,853 | ||||||||||||||||||
James F. Stutts | 91,096 | — | 91,096 | |||||||||||||||||||||
All directors and executive officers as a group (8 persons)(2) | 869,542 | 680,341 | 1,549,883 | 1,082,890 | 637,935 | 1,720,825 |
(1) | Includes |
(2) |
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Item 13. Certain Relationships and Related Transactions, and Director Independence
DOMINION
The information regarding related party transactions required by this item found under the headingRelated Party Transactions, and information regarding director independence found under the headingDirector Independence, in the 20112013 Proxy Statement is incorporated by reference.
VIRGINIA POWER
Related Party Transactions
Virginia Power’s Board of Directors has adopted the Related Party Guidelines also approved by Dominion’s Board of Directors. These guide-Direc-
linestors. These guidelines were adopted for the purpose of identifying potential conflicts of interest arising out of financial transactions, arrangements and relations between Virginia Power and any related persons. Under the guidelines, a related person is a director, executive officer, director nominee, a beneficial owner of more than 5% of Dominion’s common stock, or any immediate family member of one of the foregoing persons. A related party transaction is any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships in excess of $120,000 in which Virginia Power (and/or any of its consolidated subsidiaries) is a party and in which the related person has or will have a direct or indirect material interest.
In determining whether a direct or indirect interest is material, the significance of the information to investors in light of all circumstances is considered. The importance of the interest to the person having the interest, the relationship of the parties to the transaction with each other and the amount involved are also among the factors considered in determining the significance of the information to the investors.
Dominion’s CGN Committee has reviewed certain categories of transactions and determined that transactions between Dominion and a related person that fall within such categories will not result in the related person receiving a direct or indirect material interest. Under the guidelines, such transactions are not deemed related party transactions and therefore not subject to review by the CGN Committee. The categories of excluded transactions include, among other items, compensation and expense reimbursement paid to directors and executive officers in the ordinary course of performing their duties; transactions with other companies where the related party’s only relationship is as an employee, if the aggregate amount involved does not exceed the greater of $1 million or 2% of that company’s gross revenues; and charitable contributions which are less than the greater of $1 million or 2% of the charity’s annual receipts. The full text of the guidelines can be found on Dominion’s website at www.dom.com/investors/corporate-governance/pdf/related_party_guidelines.pdf.
Virginia Power collects information about potential related party transactions in its annual questionnaires completed by directors and executive officers. The General Counsel and the Chief Legal Officer reviewManagement reviews the potential related party transactions and assessassesses whether any of the identified transactions constitute a related party transaction. Any identified related party transactions are then reported to Dominion’s CGN Committee. Dominion’s CGN Committee reviews and considers relevant facts and circumstances and determines whether to ratify or approve the related party transactions identified. Dominion’s CGN Committee may only approve or ratify related party transactions that are in, or are not inconsistent with, the best interests of Dominion and its shareholders and are in compliance with Virginia Power’s Code of Ethics.
Since January 1, 20102012, there have been no related party transactions involving Virginia Power that were required either to be approved under Virginia Power’s policies or reported under the SEC related party transactions rules.
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Director Independence
Under NYSE listing standards, Messrs. Farrell, McGettrick and Rogers are not independent as they arewere executive officers of Virginia Power or of its parent company, Dominion. All of Virginia Power’s outstanding common stock is owned by Dominion and therefore, Virginia Power is a “controlled” company under the rules of the NYSE. Because Virginia Power meets the definition of a “controlled company” and has only debt securities and preferred stock listed on the NYSE, it is exempt under Section 303A of the New York Stock ExchangeNYSE Rules from the provisions relating to board committees and the requirement to have a majority of its board be independent.
Item 14. Principal Accountant Fees and Services
DOMINION
The information concerning principal accountingaccountant fees and services contained under the headingFeesAuditors-Fees and Pre-Approval Policy in the 20112013 Proxy Statement is incorporated by reference.
VIRGINIA POWER
The following table presents fees paid to Deloitte & Touche LLP for the fiscal years ended December 31, 20102012 and 2009.2011.
Type of Fees | 2010 | 2009 | ||||||
(millions) | ||||||||
Audit fees | $ | 1.36 | $ | 1.44 | ||||
Audit-related fees | — | — | ||||||
Tax fees | — | — | ||||||
All other fees | — | — | ||||||
$ | 1.36 | $ | 1.44 |
Type of Fees | 2012 | 2011 | ||||||
(millions) | ||||||||
Audit fees | $ | 1.79 | $ | 1.32 | ||||
Audit-related fees | — | — | ||||||
Tax fees | — | — | ||||||
All other fees | — | — | ||||||
$ | 1.79 | $ | 1.32 |
Audit Fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power’s annual consolidated financial statements, the review of financial statements included in Virginia Power’s quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC.
Audit-Related Fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Virginia Power’s consolidated financial statements or internal control over financial reporting. This category may include fees related to the performanceBoard of audits and attest services not required by statute or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.
Virginia Power’s boardDirectors has adopted Dominion’sthe Dominion Audit Committee Pre-Approval Policypre-approval policy for its independent auditor’s services and fees and has delegated the execution of this policy to Dominion’s audit committee (DRIthe Dominion Audit Committee).Committee. In accordance with this delegation, each year the DRIDominion Audit Committee pre-approves a schedule that details the services to be provided for the following year and an estimated charge for such services. At its December 20102012 meeting, the DRIDominion Audit Committee approved Virginia Power’s schedule of services and fees for 2011.2013. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the DRIDominion Audit Committee or a member of this committee.the Dominion Audit Committee.
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Item 15. Exhibits and Financial Statement Schedules
(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.
1. Financial Statements
See Index on page 53.
2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.
3. Exhibits (incorporated by reference unless otherwise noted)note
Exhibit Number | Description | Dominion | Virginia Power | |||||||
2 | Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1, Form 8-K filed March 15, 2010, File No. 1-8489). | X | ||||||||
3.1.a | Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489). | X | ||||||||
3.1.b | Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on | X | ||||||||
3.2.a | Dominion Resources, Inc. Amended and Restated Bylaws, effective | X | ||||||||
3.2.b | Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255). | X | ||||||||
4 | Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets. | X | X | |||||||
4.1.a | See Exhibit 3.1.a above. | X | ||||||||
4.1.b | See Exhibit 3.1.b above. | X | ||||||||
4.2 | Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); | X | X | |||||||
4.3 | ||||||||||
Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of First Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Eleventh Supplemental Indenture, dated |
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December 1, 2003 (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255); Forms of Twelfth and Thirteenth Supplemental Indentures, dated January 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Forms of Sixteenth and Seventeenth Supplemental Indentures, dated November 1, 2007 (Exhibits 4.2 and 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 | X | X |
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Exhibit Number | Description | Dominion | Virginia Power | |||||||
(Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255). | ||||||||||
Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a First Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement filed April 22, 1998, File No. 333-50653); Forms of Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits 4.6 and 4.13, Form 8-K filed January 12, 2001, File No. 1-8489). | X | |||||||||
Indenture, dated May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012); Fifteenth Supplemental Indenture, dated October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651); Seventeenth Supplemental Indenture, dated August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Eighteenth Supplemental Indenture, dated December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Nineteenth Supplemental Indenture, dated January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Twentieth Supplemental Indenture, dated March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-3196); Twenty-First Supplemental Indenture, dated June 27, 2007 (Exhibit 4.2, Form 8-K filed July 3, 2007, File No. 1-8489). | X | |||||||||
Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2, Form 8-A filed April 21, 1995, File No. 1-3196 and relating to the 7 | X | |||||||||
Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K filed June 22, 2000, File No. 1-8489); Forms of Second and Third Supplemental Indentures, dated July 1, 2000 (Exhibits 4.2 and 4.3, Form 8-K filed July 11, 2000, File No. 1-8489); Fourth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.2, Form 8-K filed September 8, 2000, File No. 1-8489); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K filed September 11, 2000, File No. 1-8489); |
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Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of | X |
154 |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Forms of Seventeenth and Eighteenth Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489; Forms of Twentieth and Twenty-First Supplemental Indentures, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Third Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011(Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K, filed March 7, 2011, File No. 1-8489);Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 15, 2011, File No. 1-8489); Forty-Fifth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489). | ||||||||||
Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K filed April 12, 2001, File No. 1-3196); Forms of Second and Third Supplemental Indentures, dated October 25, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed October 23, 2001, File No. 1-3196); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K filed May 22, 2002, File No. 1-3196); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196); Seventh Supplemental Indenture, dated June 27, 2007 (Exhibit 4.6, Form 8-K filed July 3, 2007, File No. 1-8489). | X | |||||||||
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Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489). | X | |||||||||
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489). | X |
155 |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
4.11 | Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489). | X | ||||||||
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489). | X | |||||||||
10.1 | X | |||||||||
10.2 | DRS Services Agreement, dated as of January 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company | X | ||||||||
10.3 | Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489). | X | X | |||||||
$3.0 billion Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, JP Morgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., Barclays Capital, The Royal Bank of Scotland plc, and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein. (Exhibit 10.1, Form 8-K filed September 28, 2010, File No. | X | X | ||||||||
$500 million Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, Keybank National Association, as Administrative Agent, Bayerische Landesbank, New York Branch, and U.S. Bank National Association, as Syndication Agents, and other lenders named therein. (Exhibit 10.2, Form 8-K filed September 28, 2010, File No. | X | X | ||||||||
Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003, File No. | X | X | ||||||||
Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489). | X | X | ||||||||
Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489), as amended June 20, 2007 (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489 and Exhibit 10.5, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-2255). | X | X | ||||||||
Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. | X | X | ||||||||
Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489). | X | X |
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Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489). | X | X | ||||||||
Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489), amended January 19, 2006 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2005 filed March 2, 2006, File No. 1-8489), as amended December 1, 2006 and further amended January 1, 2007 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2006, filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489). | X | X |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
10.13* | Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489), as amended January 1, 2007 (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255), as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255). | X | X | |||||||
Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489). | X | |||||||||
Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489). | X | |||||||||
Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489). | X | |||||||||
Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489). | X | |||||||||
Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489 and File No. 1-2255). | X | X | ||||||||
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011 | X | |||||||||
Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489). | X | X | ||||||||
Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489). | X | |||||||||
Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489). | X |
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Supplemental retirement agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255). | X | |||||||||
Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255). | X | |||||||||
Form of Restricted Stock Grant under 2007 Long-Term Compensation Program approved March 30, 2007 (Exhibit 10.1, Form 8-K filed April 5, 2007, File No. 1-8489). | X | X | ||||||||
Form of Restricted Stock Award Agreement under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.1, Form 8-K filed April 2, 2008, File No. 1-8489). | X | X | ||||||||
Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255). | X | X |
157 |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
10.28* | 2009 Performance Grant Plan under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.1, Form 8-K filed January 29, 2009, File No. 1-8489). | X | X | |||||||
Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489). | X | X | ||||||||
Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective | X | X | ||||||||
2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489). | X | X | ||||||||
Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489). | X | X | ||||||||
Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489). | X | X | ||||||||
2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489). | X | X | ||||||||
Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489). | X | X | ||||||||
Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian under the 2005 Incentive Compensation Plan approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012, File No. 1-8489). | X | X | ||||||||
10.37* | 2012 Performance Grant Plan under the 2012 Long-Term Incentive Program approved January 19, 2012 (Exhibit 10.1, Form 8-K filed January 20, 2012, File No. 1-8489). | X | X | |||||||
10.38* | Form of Restricted Stock Award Agreement under the 2012 Long-term incentive Program approved January 19, 2012 (Exhibit 10.2, Form 8-K filed January 20, 2012, File No. 1-8489). | X | X | |||||||
10.39* | 2013 Performance Grant Plan under 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.1, Form 8-K filed January 25, 2013, File No. 1-8489). | X | X | |||||||
10.40* | Form of Restricted Stock Award Agreement under the 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.2, Form 8-K filed January 25, 2013, File No. 1-8489). | X | X | |||||||
10.41* | Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010 (Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489). | X | X | |||||||
Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith). | X |
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Non-employee directors’ annual compensation for Dominion Resources, Inc. | ||||||||||
X | ||||||||||
12.a | Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith). | X | ||||||||
12.b | Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith). | X | ||||||||
12.c | Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith). | X | ||||||||
21 | Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith). | X | X | |||||||
23 | Consent of Deloitte & Touche LLP (filed herewith). | X | X | |||||||
31.a | Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | X | ||||||||
31.b | Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | X | ||||||||
31.c | Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | X | ||||||||
31.d | Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | X | ||||||||
32.a | Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). | X |
158 |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
32.b | Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). | X | ||||||||
99.1 | Dominion Resources, Inc. Earnings Release Kit (furnished herewith). | X | ||||||||
99.2 | Supplemental Summary of 2012 Operating Earnings (furnished herewith). | X | ||||||||
99.3 | Towers Watson Energy Services Survey participants (filed herewith). | X | ||||||||
101^ | The following financial statements from Dominion Resources, Inc. and Virginia Electric and Power Company Annual Report on Form 10-K for the year ended December 31, | X | X |
* | Indicates management contract or compensatory plan or arrangement |
^ | This exhibit will not be deemed “filed” by Virginia Electric and Power Company for purposes of Section 18 of the Securities Exchange Act of 1934 (15 U.S.C. 78r), or otherwise subject to the liability of that section. Such exhibit will not be deemed to be incorporated by reference into any filing under the Securities Act or Securities Exchange Act, except to the extent that |
159 |
Signatures
DOMINION
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DOMINION RESOURCES, | ||
By: | /S/ THOMAS F. FARRELL II | |
(Thomas F. Farrell II, Chairman, President and Chief Executive Officer) |
Date: February 28, 20112013
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2011.2013.
Signature | Title | |
/S/ THOMAS F. FARRELL II Thomas F. Farrell II | Chairman of the Board of Directors, President and Chief Executive Officer | |
/S/ WILLIAM P. BARR William P. Barr | Director | |
/S/ PETER W. BROWN Peter W. Brown | ||
| Director | |
/S/ HELEN E. DRAGAS Helen E. Dragas | Director | |
/S/ JOHN W. HARRIS John W. Harris | Director | |
/S/ ROBERT S. JEPSON, JR. Robert S. Jepson, Jr. | Director | |
/S/ MARK J. KINGTON Mark J. Kington | Director | |
/S/
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| ||
Robert H. Spilman, Jr. | Director | |
/S/ MICHAEL E. SZYMANCZYK Michael E. Szymanczyk | Director | |
/S/ DAVID A. WOLLARD David A. Wollard | Director | |
/S/ MARK F. MCGETTRICK Mark F. McGettrick | Executive Vice President and Chief Financial Officer | |
/S/ ASHWINI SAWHNEY Ashwini Sawhney | Vice President—Accounting and Controller (Chief Accounting Officer) |
160 |
VIRGINIA POWER
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VIRGINIA ELECTRIC AND POWER COMPANY | ||
By: | /S/ THOMAS F. FARRELL II | |
(Thomas F. Farrell II, Chairman of the Board of Directors and Chief Executive Officer) |
Date: February 28, 20112013
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2011.2013.
Signature | Title | |
/S/ THOMAS F. FARRELL II Thomas F. Farrell II | Chairman of the Board of Directors and Chief Executive Officer | |
/S/ MARK F. MCGETTRICK Mark F. McGettrick | Director, Executive Vice President and Chief Financial Officer | |
/S/ ASHWINI SAWHNEY Ashwini Sawhney | Vice | |
/S/ STEVEN A. ROGERS Steven A. Rogers | Director |
161 |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
2 | Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1, Form 8-K filed March 15, 2010, File No. 1-8489). | X | ||||||||
3.1.a | Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489). | X | ||||||||
3.1.b | Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on | X | ||||||||
3.2.a | Dominion Resources, Inc. Amended and Restated Bylaws, effective | X | ||||||||
3.2.b | Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255). | X | ||||||||
4 | Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets. | X | X | |||||||
4.1.a | See Exhibit 3.1.a above. | X | ||||||||
4.1.b | See Exhibit 3.1.b above. | X | ||||||||
4.2 | Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); | X | X | |||||||
4.3 | ||||||||||
Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of First Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Eleventh Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255); Forms of Twelfth and Thirteenth Supplemental Indentures, dated January 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Forms of Sixteenth and Seventeenth Supplemental Indentures, dated November 1, 2007 (Exhibits 4.2 and 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255). | X | X |
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Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a First Supplemental Indenture, dated December 1, 1997 | X |
162 |
Exhibit Number | Description | Dominion | Virginia Power | ||||||||
(Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement filed April 22, 1998, File No. 333-50653); Forms of Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits 4.6 and 4.13, Form 8-K filed January 12, 2001, File No. 1-8489). | |||||||||||
Indenture, dated May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012); Fifteenth Supplemental Indenture, dated October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651); Seventeenth Supplemental Indenture, dated August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Eighteenth Supplemental Indenture, dated December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Nineteenth Supplemental Indenture, dated January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Twentieth Supplemental Indenture, dated March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-3196); Twenty-First Supplemental Indenture, dated June 27, 2007 (Exhibit 4.2, Form 8-K filed July 3, 2007, File No. 1-8489). | X | ||||||||||
Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2, Form 8-A filed April 21, 1995, File No. 1-3196 and relating to the 7 | X | ||||||||||
Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K filed June 22, 2000, File No. 1-8489); Forms of Second and Third Supplemental Indentures, dated July 1, 2000 (Exhibits 4.2 and 4.3, Form 8-K filed July 11, 2000, File No. 1-8489); Fourth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.2, Form 8-K filed September 8, 2000, File No. 1-8489); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K filed September 11, 2000, File No. 1-8489); Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Forms of Seventeenth and Eighteenth |
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Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489; Forms of Twentieth and Twenty-First Supplemental Indentures, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Third Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, | X |
163 |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011(Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K, filed March 7, 2011, File No. 1-8489);Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 15, 2011, File No. 1-8489); Forty-Fifth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489). | ||||||||||
Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K filed April 12, 2001, File No. 1-3196); Forms of Second and Third Supplemental Indentures, dated October 25, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed October 23, 2001, File No. 1-3196); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K filed May 22, 2002, File No. 1-3196); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196); Seventh Supplemental Indenture, dated June 27, 2007 (Exhibit 4.6, Form 8-K filed July 3, 2007, File No. 1-8489). | X | |||||||||
Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489). | X | |||||||||
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489). | X | |||||||||
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489). | X |
164 |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489). | X | |||||||||
10.1 | X | |||||||||
10.2 | DRS Services Agreement, dated as of January 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company | X | ||||||||
10.3 | Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489). | X | X | |||||||
$3.0 billion Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, JP Morgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., Barclays Capital, The Royal Bank of Scotland plc, and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein. (Exhibit 10.1, Form 8-K filed September 28, 2010, File No. | X | X | ||||||||
$500 million Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, Keybank National Association, as Administrative Agent, Bayerische Landesbank, New York Branch, and U.S. Bank National Association, as Syndication Agents, and other lenders named therein. (Exhibit 10.2, Form 8-K filed September 28, 2010, File No. | X | X | ||||||||
Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003, File No. | X | X | ||||||||
Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489). | X | X | ||||||||
Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489), as amended June 20, 2007 (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489 and Exhibit 10.5, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-2255). | X | X | ||||||||
Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. | X | X | ||||||||
Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489). | X | X | ||||||||
Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489). | X | X | ||||||||
Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489), amended January 19, 2006 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2005 filed March 2, 2006, File No. 1-8489), as amended December 1, 2006 and further amended January 1, 2007 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2006, filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489). | X | X | ||||||||
Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489), as amended January 1, 2007 (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File | X | X |
165 |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255), as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255). | ||||||||||
Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489). | X | |||||||||
Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489). | X | |||||||||
Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489). | X | |||||||||
Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489). | X | |||||||||
Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489 and File No. 1-2255). | X | X | ||||||||
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011 | X | |||||||||
Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489). | X | X | ||||||||
Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489). | X | |||||||||
Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489). | X | |||||||||
Supplemental retirement agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255). | X | |||||||||
Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255). | X | |||||||||
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Form of Restricted Stock Grant under 2007 Long-Term Compensation Program approved March 30, 2007 (Exhibit 10.1, Form 8-K filed April 5, 2007, File No. 1-8489). | X | X | ||||||||
Form of Restricted Stock Award Agreement under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.1, Form 8-K filed April 2, 2008, File No. 1-8489). | X | X |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
10.27* | Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255). | X | X | |||||||
2009 Performance Grant Plan under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.1, Form 8-K filed January 29, 2009, File No. 1-8489). | X | X | ||||||||
Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489). | X | X | ||||||||
Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective | X | X | ||||||||
2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489). | X | X | ||||||||
Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489). | X | X | ||||||||
Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489). | X | X | ||||||||
10.34* | 2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489). | X | X | |||||||
Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489). | X | X | ||||||||
Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian under the 2005 Incentive Compensation Plan approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012, File No. 1-8489). | X | X | ||||||||
10.37* | 2012 Performance Grant Plan under the 2012 Long-Term Incentive Program approved January 19, 2012 (Exhibit 10.1, Form 8-K filed January 20, 2012, File No. 1-8489). | X | X | |||||||
10.38* | Form of Restricted Stock Award Agreement under the 2012 Long-term incentive Program approved January 19, 2012 (Exhibit 10.2, Form 8-K filed January 20, 2012, File No. 1-8489). | X | X | |||||||
10.39* | 2013 Performance Grant Plan under 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.1, Form 8-K filed January 25, 2013, File No. 1-8489). | X | X | |||||||
10.40* | Form of Restricted Stock Award Agreement under the 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.2, Form 8-K filed January 25, 2013, File No. 1-8489). | X | X | |||||||
10.41* | Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010 (Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489). | X | X | |||||||
Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith). | X | |||||||||
Non-employee directors’ annual compensation for Dominion Resources, Inc. | ||||||||||
X | ||||||||||
12.a | Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith). | X | ||||||||
12.b | Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith). | X | ||||||||
12.c | Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith). | X | ||||||||
21 | Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith). | X | X | |||||||
23 | Consent of Deloitte & Touche LLP (filed herewith). | X | X | |||||||
31.a | Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | X | ||||||||
31.b | Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | X |
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31.c | Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | X |
167 |
Exhibit Number | Description | Dominion | Virginia Power | |||||||
31.d | Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | X | ||||||||
32.a | Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). | X | ||||||||
32.b | Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). | X | ||||||||
99.1 | Dominion Resources, Inc. Earnings Release Kit (furnished herewith). | X | ||||||||
99.2 | Supplemental Summary of 2012 Operating Earnings (furnished herewith). | X | ||||||||
99.3 | Towers Watson Energy Services Survey participants (filed herewith). | X | ||||||||
101^ | The following financial statements from Dominion Resources, Inc. and Virginia Electric and Power Company Annual Report on Form 10-K for the year ended December 31, | X | X |
* | Indicates management contract or compensatory plan or arrangement |
^ | This exhibit will not be deemed “filed” by Virginia Electric and Power Company for purposes of Section 18 of the Securities Exchange Act of 1934 (15 U.S.C. 78r), or otherwise subject to the liability of that section. Such exhibit will not be deemed to be incorporated by reference into any filing under the Securities Act or Securities Exchange Act, except to the extent that |
168 |