Form 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2012
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from
to
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Commission File Number |
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Exact name of registrants as specified in their charters |
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I.R.S. Employer Identification Number |
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001-08489 |
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DOMINION RESOURCES, INC. |
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54-1229715 |
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001-02255 |
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VIRGINIA ELECTRIC AND POWER COMPANY |
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54-0418825 |
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VIRGINIA (State or other jurisdiction of incorporation or organization) |
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120 TREDEGAR STREET
RICHMOND, VIRGINIA (Address of principal executive offices) |
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23219 (Zip Code) |
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(804) 819-2000 (Registrants telephone number) |
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Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class |
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Name of Each Exchange
on Which Registered |
DOMINION RESOURCES, INC. |
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Common Stock, no par value |
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New York Stock Exchange |
2009 Series A 8.375% Enhanced Junior Subordinated Notes |
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New York Stock Exchange |
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VIRGINIA ELECTRIC AND POWER COMPANY |
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Preferred Stock (cumulative), $100 par value, $5.00 dividend |
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by
check mark whether the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.
Dominion
Resources,
Inc. Yes x No ¨
Virginia Electric and Power Company Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Dominion Resources,
Inc. Yes ¨ No x
Virginia Electric and Power Company Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Dominion Resources,
Inc. Yes x No ¨
Virginia Electric and Power Company Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Dominion Resources,
Inc. Yes x No ¨
Virginia Electric and Power Company Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is
not contained herein, and will not be contained, to the best of registrants 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.
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Large accelerated filer x |
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Accelerated filer ¨ |
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Non-accelerated filer ¨ |
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Smaller reporting company ¨ |
Virginia Electric and Power Company
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Large accelerated filer ¨ |
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Accelerated filer ¨ |
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Non-accelerated filer x |
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Smaller reporting company ¨ |
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(Do not check if a smaller reporting company)
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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 Dominions common stock as reported on the New York Stock Exchange as of the last day of Dominions 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 Dominions 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 Dominions
other operations.
Dominion Resources, Inc. and
Virginia Electric and Power Company
Glossary of Terms
The following abbreviations or acronyms used in this Form 10-K are defined below:
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Abbreviation or Acronym |
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Definition |
2009 Base Rate Review |
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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 |
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Dominion 2013 Proxy Statement, File No. 001-08489 |
ABO |
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Accumulated benefit obligation |
AES |
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Alternative Energy Solutions |
AFUDC |
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Allowance for funds used during construction |
AIP |
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Annual Incentive Plan |
AMI |
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Advanced Metering Infrastructure |
AMR |
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Automated meter reading program deployed by East Ohio |
AOCI |
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Accumulated other comprehensive income (loss) |
AROs |
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Asset retirement obligations |
ARP |
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Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the
CAA |
ASA |
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Average Speed of Answer, a primary metric used to measure customer service |
ASLB |
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Atomic Safety and Licensing Board |
ATEX line |
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Appalachia to Texas Express ethane line |
bcf |
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Billion cubic feet |
Bear Garden |
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A 590 MW combined cycle, natural gas-fired power station in Buckingham County, Virginia |
Biennial Review Order |
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Order issued by the Virginia Commission in November 2011 concluding the 2009 - 2010 biennial review of Virginia Powers base rates,
terms and conditions |
Blue Racer |
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Blue Racer Midstream, LLC |
BOEM |
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Bureau of Ocean Energy Management |
BP |
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BP Wind Energy North America Inc. |
Brayton Point |
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Brayton Point power station |
BREDL |
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Blue Ridge Environmental Defense League |
Bremo |
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Bremo power station |
BRP |
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Dominion Retirement Benefit Restoration Plan |
Brunswick County |
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A proposed 1,358 MW combined cycle, natural gas-fired power station in Brunswick County, Virginia |
CAA |
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Clean Air Act |
Caiman |
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Caiman Energy II, LLC |
CAIR |
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Clean Air Interstate Rule |
CAO |
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Chief Accounting Officer |
Carson-to-Suffolk line |
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Virginia Power 60-mile 500 kV transmission line in southeastern Virginia |
CD&A |
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Compensation Discussion and Analysis |
CDO |
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Collateralized debt obligation |
CEO |
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Chief Executive Officer |
CERCLA |
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Comprehensive Environmental Response, Compensation and Liability Act of 1980 |
CFO |
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Chief Financial Officer |
CFTC |
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Commodity Futures Trading Commission |
CGN Committee |
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Compensation, Governance and Nominating Committee of Dominions Board of Directors |
Chesapeake |
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Chesapeake power station |
CNG |
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Consolidated Natural Gas Company |
CNO |
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Chief Nuclear Officer |
CO2 |
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Carbon dioxide |
COL |
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Combined Construction Permit and Operating License |
Companies |
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Dominion and Virginia Power, collectively |
CONSOL |
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CONSOL Energy, Inc. |
COO |
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Chief Operating Officer |
Cooling degree days |
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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 |
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Dominion Cove Point LNG, LP |
CSAPR |
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Cross State Air Pollution Rule |
CWA |
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Clean Water Act |
DCI |
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Dominion Capital, Inc. |
DEI |
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Dominion Energy, Inc. |
Dodd-Frank Act |
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The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 |
DOE |
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Department of Energy |
Dominion |
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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 |
Glossary of Terms, continued
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Abbreviation or Acronym |
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Definition |
Dominion
Direct® |
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A dividend reinvestment and open enrollment direct stock purchase plan |
Dooms-to-Bremo line |
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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 |
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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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Dominions Defined Benefit Pension Plan |
DRS |
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Dominion Resources Services, Inc. |
DSM |
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Demand-side management |
DTI |
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Dominion Transmission, Inc. |
DVP |
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Dominion Virginia Power operating segment |
E&P |
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Exploration & production |
East Ohio |
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The East Ohio Gas Company, doing business as Dominion East Ohio |
EGWP |
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Employer Group Waiver Plan |
Elwood |
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Elwood power station |
Enterprise |
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Enterprise Product Partners, L.P. |
EPA |
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Environmental Protection Agency |
EPACT |
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Energy Policy Act of 2005 |
EPS |
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Earnings per share |
ERISA |
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The Employment Retirement Income Security Act of 1974 |
ERM |
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Enterprise Risk Management |
ERO |
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Electric Reliability Organization |
ESRP |
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Dominion Executive Supplemental Retirement Plan |
Excess Tax Benefits |
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Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation |
Fairless |
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Fairless power station |
FASB |
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Financial Accounting Standards Board |
FCM |
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Futures Commission Merchant |
FERC |
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Federal Energy Regulatory Commission |
Fitch |
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Fitch Ratings Ltd. |
Fowler Ridge |
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A wind-turbine facility joint venture with BP in Benton County, Indiana |
Frozen Deferred Compensation Plan |
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Dominion Resources, Inc. Executives Deferred Compensation Plan |
Frozen DSOP |
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Dominion Resources, Inc. Security Option Plan |
FTRs |
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Financial transmission rights |
GAAP |
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U.S. generally accepted accounting principles |
GHG |
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Greenhouse gas |
GWSA |
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Global Warming Solutions Act |
Harrisonburg-to-Endless Caverns line |
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Virginia Power project to construct a 20-mile 230 kV line from the Harrisonburg substation to the Endless Caverns
substation |
Hayes-to-Yorktown line |
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Virginia Power project to construct an approximately eight-mile 230 kV transmission line in southeastern Virginia |
Heating degree days |
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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 |
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Hope Gas, Inc., doing business as Dominion Hope |
INPO |
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Institute of Nuclear Power Operations |
IRC |
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Internal Revenue Code |
IRS |
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Internal Revenue Service |
ISO |
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Independent system operator |
ISO-NE |
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ISO New England |
Joint Committee |
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U.S. Congressional Joint Committee on Taxation |
June 2006 hybrids |
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2006 Series A Enhanced Junior Subordinated Notes due 2066 |
June 2009 hybrids |
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2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to extensions no later than 2079 |
Juniper |
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Juniper Capital L.P. |
Kewaunee |
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Kewaunee nuclear power station |
Kincaid |
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Kincaid power station |
kV |
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Kilovolt |
kWh |
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Kilowatt-hour |
LIBOR |
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London Interbank Offered Rate |
LIFO |
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Last-in-first-out inventory method |
LNG |
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Liquefied natural gas |
LTIP |
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Long-term incentive program |
MATS |
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Utility Mercury and Air Toxics Standard Rule |
Manchester Street |
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Manchester Street power station |
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Abbreviation or Acronym |
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Definition |
mcf |
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million cubic feet |
MD&A |
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Managements Discussion and Analysis of Financial Condition and Results of Operations |
Meadow Brook-to-Loudoun line |
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Virginia Power 65-mile 500 kV transmission line that begins in Warren County, Virginia and terminates in Loudoun County,
Virginia |
Medicare Act |
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The Medicare Prescription Drug, Improvement and Modernization Act of 2003 |
Medicare Part D |
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Prescription drug benefit introduced in the Medicare Act |
MF Global |
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MF Global Inc. |
MGD |
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Million gallons a day |
Millstone |
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Millstone nuclear power station |
MISO |
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Midwest Independent Transmission System Operators, Inc. |
Moodys |
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Moodys Investors Service |
Mt. Storm-to-Doubs line |
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Virginia Power project to rebuild approximately 96 miles of an existing 500 kV transmission line in Virginia and West
Virginia |
MW |
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Megawatt |
MWh |
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Megawatt hour |
NAAQS |
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National Ambient Air Quality Standards |
NAV |
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Net asset value |
NCEMC |
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North Carolina Electric Membership Corporation |
NedPower |
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A wind-turbine facility joint venture with Shell in Grant County, West Virginia |
NEIL |
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Nuclear Electric Insurance Limited |
NEOs |
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Named executive officers |
NERC |
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North American Electric Reliability Corporation |
NGLs |
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Natural gas liquids |
NO2 |
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Nitrogen dioxide |
Non-Employee Directors Plan |
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Non-Employee Directors Compensation Plan |
North Anna |
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North Anna nuclear power station |
North Branch |
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North Branch power station |
North Carolina Commission |
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North Carolina Utilities Commission |
North Carolina Settlement Approval Order |
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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 |
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Nitrogen oxide |
NPDES |
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National Pollutant Discharge Elimination System |
NRC |
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Nuclear Regulatory Commission |
NSPS |
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New Source Performance Standards |
NYMEX |
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New York Mercantile Exchange |
NYSE |
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New York Stock Exchange |
ODEC |
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Old Dominion Electric Cooperative |
Ohio Commission |
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Public Utilities Commission of Ohio |
OSHA |
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Occupational Safety and Health Administration |
PBGC |
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Pension Benefit Guaranty Corporation |
Peoples |
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The Peoples Natural Gas Company |
Pipeline Safety Act |
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The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 |
PIPP |
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Percentage of Income Payment Plan |
PIR |
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Pipeline Infrastructure Replacement program deployed by East Ohio |
PJM |
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PJM Interconnection, LLC |
PM&P |
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Pearl Meyer & Partners |
PNG Companies LLC |
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An indirect subsidiary of Steel River Infrastructure Fund North America |
ppb |
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Parts-per-billion |
Radnor Heights Project |
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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 |
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Replacement Capital Covenants |
RCRA |
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Resource Conservation and Recovery Act |
Regulation Act |
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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 |
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Real estate investment trust |
RGGI |
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Regional Greenhouse Gas Initiative |
Rider A1 |
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A rate adjustment clause to reduce anticipated over-collected fuel expense for the second half of 2012, effective November 1, 2012 to
December 31, 2012 |
Rider B |
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A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Powers coal-fired
power stations to biomass |
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Abbreviation or Acronym |
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Definition |
Rider BW |
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A rate adjustment clause associated with the recovery of costs related to Brunswick County |
Rider R |
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A rate adjustment clause associated with the recovery of costs related to Bear Garden |
Rider S |
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A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center |
Rider T |
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A rate adjustment clause associated with the recovery of certain electric transmission-related expenditures |
Rider T1 |
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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 |
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A rate adjustment clause associated with the recovery of costs related to Warren County |
Riders C1 and C2 |
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Rate adjustment clauses associated with the recovery of costs related to certain DSM programs |
Riders C1A and C2A |
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Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in the 2011 DSM
case |
ROE |
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Return on equity |
ROIC |
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Return on invested capital |
RPS |
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Renewable Portfolio Standard |
RTEP |
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Regional transmission expansion plan |
RTO |
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Regional transmission organization |
SAFSTOR |
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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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System Average Interruption Duration Index, metric used to measure electric service reliability |
Salem Harbor |
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Salem Harbor power station |
SEC |
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Securities and Exchange Commission |
September 2006 hybrids |
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2006 Series B Enhanced Junior Subordinated Notes due 2066 |
Shell |
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Shell WindEnergy, Inc. |
SO2 |
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Sulfur dioxide |
Standard & Poors |
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Standard & Poors Ratings Services, a division of the McGraw-Hill Companies, Inc. |
State Line |
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State Line power station |
Surry |
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Surry nuclear power station |
Surry-to-Skiffes Creek-to-Whealton lines |
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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 |
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Tennessee Gas Pipeline Company |
TSR |
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Total shareholder return |
U.S. |
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United States of America |
U.S. DOT |
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United States Department of Transportation |
UAO |
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Unilateral Administrative Order |
UEX Rider |
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Uncollectible Expense Rider |
VEBA |
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Voluntary Employees Beneficiary Association |
VIE |
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Variable interest entity |
Virginia City Hybrid Energy Center |
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A 600 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County,
Virginia |
Virginia Commission |
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Virginia State Corporation Commission |
Virginia Power |
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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 |
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Order issued by the Virginia Commission in March 2010 concluding Virginia Powers 2009 Base Rate Review |
Warren County |
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A 1,329 MW combined-cycle, natural gas-fired power station under construction in Warren County, Virginia |
Waxpool-Brambleton-BECO line |
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Virginia Power project to construct an approximately 1.5-mile double circuit 230 kV line to a new Waxpool substation, and a new 230 kV
line between the Brambleton and BECO substations |
West Virginia Commission |
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Public Service Commission of West Virginia |
Yorktown |
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Yorktown power station |
Part I
Item 1. Business
GENERAL
Dominion, headquartered in Richmond, Virginia and
incorporated in Virginia in 1983, is one of the nations largest producers and transporters of energy. Dominions 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. Dominions portfolio of assets includes approximately 27,500 MW of generating capacity, 6,300 miles of electric transmission lines, 56,900 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 operates one of the nations largest underground natural gas storage systems, with
approximately 947 bcf of storage capacity, and serves nearly 6 million utility and retail energy customers in 15 states.
Dominion is focused on expanding its investment in regulated electric generation, transmission and distribution and regulated natural gas
transmission and distribution infrastructure within and around its existing footprint. Dominion expects this will continue to increase its earnings contribution from regulated operations, while reducing the sensitivity of its earnings to commodity
prices.
Dominion continues to expand and improve its regulated electric and natural gas businesses, in accordance with its
five-year capital investment program. A major impetus for this program is to meet the anticipated increase in electricity demand in its electric utility service territory. Other drivers for the capital investment program include the construction of
infrastructure to handle the increase in natural gas production from the Marcellus and Utica Shale formations; and to upgrade Dominions gas distribution and electric transmission and distribution networks. Planned investments to gather and
process natural gas production from the Utica Shale formation, in eastern Ohio and western Pennsylvania, are expected to be made by the newly-formed Blue Racer joint venture.
Dominions 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. Dominions 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 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 Powers common stock is owned by Dominion.
Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.
EMPLOYEES
As of December 31, 2012, Dominion had approximately 15,500 full-time employees, of which approximately 5,800 employees are subject to collective bargaining agreements. As of
December 31, 2012, Virginia Power had approximately 6,800 full-time employees, of which approximately 3,100 employees are subject to collective bargaining agreements.
PRINCIPAL EXECUTIVE OFFICES
Dominion and
Virginia Powers principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and their telephone number is (804) 819-2000.
WHERE YOU
CAN FIND MORE INFORMATION ABOUT DOMINION AND VIRGINIA POWER
Dominion and Virginia Power file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are
available to the public over the Internet at the SECs website at http://www.sec.gov. You may also read and copy any document they file at the SECs 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 Dominions 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 Dominions website is not incorporated by reference in this report.
ACQUISITIONS AND
DISPOSITIONS
Following are significant divestitures by Dominion and Virginia Power during the last five years. There were
no significant acquisitions by either registrant during this period.
SALE OF E&P
PROPERTIES
In 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations, including its
rights to associated Marcellus acreage, to a subsidiary of CONSOL for approximately $3.5 billion. See Note 3 to the Consolidated Financial Statements for additional information. The historical results of the Appalachian E&P operations are
included in the Dominion Energy segment.
SALE OF PEOPLES
In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The historical
results of these operations are included in the Corporate and Other segment and presented in discontinued operations. See Note 3 to the Consolidated Financial Statements for additional information.
ASSIGNMENT OF MARCELLUS ACREAGE
In 2008, Dominion completed a transaction with Antero Resources to assign drilling rights to approximately 117,000 acres in the Marcellus
Shale formation located in West Virginia and Pennsylvania. Dominion received proceeds of approximately $347 million. Under the agreement, Dominion received a 7.5% overriding royalty interest on future natural gas production from the assigned
acreage. The overriding royalty interest was transferred to CONSOL as part of the sale of substantially all of Dominions Appalachian E&P operations in 2010.
SALE OF CERTAIN DCI OPERATIONS
In March 2008, Dominion reached an agreement to sell its remaining interest in the subordinated notes of a third-party CDO entity held as an investment by
DCI and in April 2008 received proceeds of $54 million, including accrued interest. Dominion deconsolidated the CDO entity as of March 31, 2008.
OPERATING SEGMENTS
Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion
also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are expected to be or are currently discontinued, which is discussed in
Note 3 to the Consolidated Financial Statements. In addition, Corporate and Other includes specific items attributable to Dominions 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:
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Primary Operating Segment |
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Description of Operations |
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Dominion |
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Virginia Power |
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DVP |
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Regulated electric distribution |
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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 25 to the
Consolidated Financial Statements. For additional information on operating revenue related to Dominions and Virginia Powers principal products and services, see Notes 2 and 4 to the
Consolidated Financial Statements, which information is incorporated herein by reference.
DVP
The DVP Operating Segment of Virginia Power includes Virginia Powers 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.
DVP has announced its five-year investment plan, which includes spending approximately $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 customer growth and increases in electricity
consumption by the typical consumer. In addition, data centers continue to contribute to anticipated demand growth, with an expected load of approximately 715 MW by the end of 2013.
Revenue provided by electric distribution operations is based primarily on rates established by state regulatory authorities and state
law. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures. Operationally,
electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. As a result, electric service reliability and customer service have improved. The three-year average
SAIDI has improved from 125 minutes at the end of 2007 to 105 minutes at the end of 2012. Likewise, ASA has also shown significant improvement. The three-year average ASA has improved from 57 seconds at the end of 2007 to 38 seconds at the end
of 2012. Customer service options continue to be enhanced and expanded through the use of technology. Customers now have the ability to use the Internet for routine billing and payment transactions, connecting and disconnecting service, reporting
outages and obtaining outage updates. Additionally, customers can follow progress of electric 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 for electric distribution.
Revenue provided by Virginia Powers 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 Powers electric transmission operations are committed to meeting NERC standards, modernizing its infrastructure and maintaining superior system reliability. Virginia Powers electric transmission operations will continue to focus
on
safety, operational performance, NERC compliance and execution of PJMs RTEP.
The DVP Operating Segment of Dominion includes all of Virginia Powers regulated electric transmission and distribution operations as discussed above, as well as Dominions nonregulated
retail energy marketing operations.
Dominions retail energy marketing operations compete in nonregulated energy markets.
The retail business requires limited capital investment and currently employs approximately 190 people. The retail customer base includes 2.1 million customer accounts and is diversified across three product lines-natural gas, electricity and
energy-related products and services. Dominion has a heavy concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice. Dominion pursues customers in electricity markets where utilities have
divested of generation assets and where customers are permitted and have opted to purchase from the market. Major growth drivers are net customer additions, new market penetration, product development and expanded sales channels and supply
optimization.
COMPETITION
DVP Operating SegmentDominion and Virginia Power
Within Virginia Powers
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 Powers service territory by entities other than Virginia Power beginning in 2013.
DVP Operating SegmentDominion
Dominions 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 Powers 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 Powers wholesale electric transmission rates, tariffs and terms of service are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the
Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. See State Regulations and Federal Regulations in Regulation and Note 13 to the Consolidated Financial
Statements for additional information, including a discussion of the 2011 Biennial Review Order.
PROPERTIES
Virginia Power has approximately 6,300 miles of electric transmission lines of 69 kV or more located in the states of North Carolina, Virginia and West Virginia. Portions of Virginia Powers 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 PJMs RTEP process, reliability projects are authorized. In December 2012, Virginia Power completed construction of the Hayes-to-Yorktown line at a total project cost of $79
million. This previously authorized PJM project was designed to improve the reliability of service to customers and the region. Previously approved PJM-authorized reliability projects such as the Waxpool-Brambleton-BECO line ($49 million), the
Harrisonburg-to-Endless Caverns line ($66 million) the Radnor Heights Project ($81 million), and the Dooms-to-Bremo line ($65 million) continue to progress and are expected to be completed on time.
As part of subsequent annual PJM RTEP processes, PJM authorized additional electric transmission upgrade projects including the Mt.
Storm-to-Doubs line ($350 million) in December 2010 and the Surry-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 the
Consolidated Financial Statements for additional information regarding electric transmission projects.
In addition, Virginia
Powers electric distribution network includes approximately 56,900 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 owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on
publicly-owned property, where permission to operate can be revoked.
SOURCES OF ENERGY
SUPPLY
DVP Operating SegmentDominion and Virginia Power
DVPs supply of electricity to serve Virginia Power customers is produced or procured by Dominion Generation. See Dominion Generation for
additional information.
DVP Operating SegmentDominion
The supply of electricity to serve Dominions retail energy marketing customers is procured through market wholesalers and RTO or ISO transactions. The supply of gas to serve Dominions retail
energy marketing customers is procured through market wholesalers or by Dominion Energy. See Dominion Energy for additional information.
SEASONALITY
DVP
Operating SegmentDominion and Virginia Power
DVPs earnings vary seasonally as a result of the impact of changes in
temperature, the impact of storms and other cata-
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 days for DVPs electric-utility related operations
does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
DVP Operating SegmentDominion
The earnings of Dominions 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 Powers utility generation operations primarily serve the supply
requirements for the DVP segments utility customers.
Earnings for the Generation operating segment of Virginia Power
primarily result from the sale of electricity generated by its utility fleet. Revenue is based primarily on rates established by state regulatory authorities and state law. Approximately 80% of revenue comes from serving Virginia jurisdictional
customers. Rates for the Virginia jurisdiction are set using a modified cost-of-service rate model. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially
impact net income. Variability in earnings for Virginia Powers generation operations results from changes in rates, the demand for services, which is primarily weather dependent, and labor and benefit costs, as well as the timing, duration and
costs of scheduled and unscheduled outages. See Electric Regulation in Virginia under Regulation and Note 13 to the Consolidated Financial Statements for additional information.
The Dominion Generation Operating Segment of Dominion includes Virginia Powers generation facilities and its related energy
supply operations described above as well as the generation operations of Dominions merchant fleet and energy marketing and price risk management activities for these assets. The Generation operating segment of Dominion derives its earnings
primarily from the sale of electricity generated by Virginia Powers utility and Dominions merchant generation assets, as well as from associated capacity and ancillary services.
Variability in earnings provided by Dominions 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 Dominions 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 SegmentDominion and
Virginia Power
Virginia Powers generation operations are not subject to significant competition as only a limited number of its
Virginia jurisdictional electric utility customers have retail choice. See Regulation-State Regulations-Electric for more information. Currently, North Carolina does not offer retail choice to electric customers.
Dominion Generation Operating SegmentDominion
Unlike Dominion Generations 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 fleets ability to profit from the sale of
electricity and related products and services.
Dominion Generations 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, the majority of which expire between December 31, 2012 and December 31, 2013, and is
therefore largely unaffected by price competition during the terms of these contracts. It was announced during the third quarter of 2012 that Dominion would pursue the sale of these Midwest assets, excluding its wind facilities. In the fourth
quarter of 2012, Dominion announced that Kewaunee is expected to be decommissioned beginning in 2013.
Dominion
Generations 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 Generations merchant units compete in the spot market with other generators to sell a variety of products including energy, capacity and ancillary services. It is
difficult to compare various types of generation given the wide range of fuels, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, Dominion applies its expertise in operations,
dispatch and risk management to maximize the degree to which its merchant fleet is competitive compared to similar assets within the region.
REGULATION
Virginia Powers utility generation fleet and Dominions 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 Powers utility generation fleet is also subject to regulation by the Virginia Commission and the North Carolina Commission. See State Regulations and Federal Regulations in Regulation
for more information.
PROPERTIES
For a listing of Dominions and Virginia Powers existing generation facilities, see Item 2. Properties.
Dominion Generation Operating SegmentDominion and Virginia Power
The generation
capacity of Virginia Powers electric utility fleet totals 17,708 MW. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro and renewables. Virginia Powers generation facilities are located in Virginia, West
Virginia and North Carolina and serve load in Virginia and northeastern North Carolina.
Based on available generation capacity
and current estimates of growth in customer demand in its utility service area, Virginia Power will need additional generation capacity over the next decade. Virginia Power has announced a comprehensive generation growth program, referred to as
Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the anticipated growing demand in its core market in Virginia. Significant projects under
construction or development are set forth below:
|
|
In February 2012, the Virginia Commission authorized the construction of Warren County which is estimated to cost approximately $1.1 billion, excluding
financing costs. It is expected to generate approximately 1,329 MW of electricity when operational. Commercial operations are scheduled to commence by late 2014. In connection with the air permit process for Warren County, Virginia Power reached an
agreement to permanently retire North Branch, a 74 MW coal-fired plant located in West Virginia, once Warren County begins commercial operations. During the fourth quarter of 2012, Virginia Power sold North Branch to a salvage company that plans to
demolish the station and resell the land. |
|
|
Virginia Power is converting three coal-fired Virginia generating stations to biomass, a renewable energy source. The conversions of the power stations
in Altavista, Hopewell and Southampton County will increase Dominions renewable generation by more than 150 MW and are expected to cost approximately $157 million, excluding financing costs. Construction activities have started at all three
sites, and these conversions are expected to be complete by the end of 2013. |
|
|
Subject to the receipt of certain regulatory approvals, Virginia Power plans to construct Brunswick County, which is expected to generate approximately
1,358 MW when operational. If the project is approved, commercial operations are expected to commence in 2016, at an estimated cost of approximately $1.3 billion, excluding financing costs. A
|
|
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. |
|
|
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.
See Note 13 to the Consolidated Financial Statements for more information on this project.
Dominion Generation Operating
SegmentDominion
The generation capacity of Dominions merchant fleet totals 7,880 MW, including 3,954 MW of announced 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 to determine
which assets fit strategically and support its objectives to improve ROIC and shareholder value. In connection with these efforts, previously Dominion had announced its intention to retire State Line and Salem Harbor. During the second quarter of
2012, Dominion sold State Line, which ceased operations in March 2012, and in August 2012, Dominion completed the sale of Salem Harbor. 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, 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.
SOURCES OF ENERGY SUPPLY
Dominion Generation Operating SegmentDominion and Virginia Power
Dominion Generation
uses a variety of fuels to power its electric generation and purchases power for utility system load requirements and to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are included
as contractual obligations in Future Cash Payments for Contractual Obligations and Planned Capital Expenditures in Item 7. MD&A.
Nuclear FuelDominion 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 FuelDominion Generation primarily utilizes coal and natural gas in its fossil fuel plants.
Dominion Generations coal supply is obtained through long-term contracts and short-term spot agreements from both domestic and international suppliers.
Dominion Generations 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 PowerDominion 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 SegmentVirginia Power
Presented below is a summary of Virginia Powers actual system output by energy source:
|
|
|
|
|
|
|
|
|
|
|
|
|
Source |
|
2012 |
|
|
2011 |
|
|
2010 |
|
Nuclear(1) |
|
|
33 |
% |
|
|
28 |
% |
|
|
28 |
% |
Purchased power, net |
|
|
27 |
|
|
|
33 |
|
|
|
29 |
|
Coal(2) |
|
|
22 |
|
|
|
26 |
|
|
|
31 |
|
Natural gas |
|
|
17 |
|
|
|
12 |
|
|
|
10 |
|
Other(3) |
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
(1) |
Excludes ODECs 11.6% ownership interest in North Anna. |
(2) |
Excludes ODECs 50.0% ownership interest in the Clover power station. The average cost of coal for 2012 Virginia in-system generation was $33.00 per MWh.
|
(3) |
Includes oil, hydro and biomass. |
SEASONALITY
Sales of
electricity for Dominion Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for
electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials 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 Dominions or Virginia Powers units.
Dominion Generation
Operating SegmentDominion 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 minimum
financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC.
The estimated cost to decommission Virginia Powers four nuclear units is reflected in the 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 SegmentDominion
In addition to the four nuclear units discussed above, Dominion has three licensed, operating nuclear reactors, two at Millstone in Connecticut and one at
Kewaunee in Wisconsin. A third Millstone unit ceased operations before Dominion acquired the power station. 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 Dominions acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunees trust after
decom-
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 financial assurance requirements, which may include, if needed, the use of parent
company guarantees, surety bonding or other financial guarantees recognized by the NRC. The estimated cost to decommission Dominions eight units is reflected in the table below and is primarily based upon site-specific studies completed in
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 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 in SAFSTOR decommissioning status and 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.
The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion and
Virginia Power are shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRC
license expiration
year |
|
|
Most
recent cost
estimate (2012
dollars)(1) |
|
|
Funds in
trusts at December 31,
2012 |
|
|
2012
contributions to trusts |
|
(dollars in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Surry |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit 1 |
|
|
2032 |
|
|
$ |
496 |
|
|
$ |
429 |
|
|
$ |
0.6 |
|
Unit 2 |
|
|
2033 |
|
|
|
520 |
|
|
|
422 |
|
|
|
0.6 |
|
North Anna |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit 1(2) |
|
|
2038 |
|
|
|
432 |
|
|
|
342 |
|
|
|
0.4 |
|
Unit
2(2) |
|
|
2040 |
|
|
|
443 |
|
|
|
322 |
|
|
|
0.3 |
|
Total (Virginia Power) |
|
|
|
|
|
|
1,891 |
|
|
|
1,515 |
|
|
|
1.9 |
|
Millstone |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit 1(3) |
|
|
n/a |
|
|
|
455 |
|
|
|
356 |
|
|
|
|
|
Unit 2 |
|
|
2035 |
|
|
|
568 |
|
|
|
444 |
|
|
|
|
|
Unit 3(4) |
|
|
2045 |
|
|
|
671 |
|
|
|
437 |
|
|
|
|
|
Kewaunee |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit 1 |
|
|
2033 |
|
|
|
666 |
|
|
|
578 |
|
|
|
|
|
Total (Dominion) |
|
|
|
|
|
$ |
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 Dominions and Virginia Powers nuclear decommissioning AROs. |
(2) |
North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts
reflect 89.26% of the decommissioning cost for both of North Annas units. |
(3) |
Unit 1 permanently ceased operations in 1998, before Dominions acquisition of Millstone. |
(4) |
Millstone Unit 3 is jointly owned by Dominion Nuclear Connecticut, with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric
Company and Green Mountain Power Corporation. Decommissioning cost is shown at Dominions ownership percentage. At December 31, 2012, the minority owners held approximately $28 million of trust funds related to Millstone Unit 3 that are not
reflected in the table above. |
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 Dominions regulated natural gas distribution companies, regulated gas transmission pipeline and storage operations, natural gas gathering and by-products extraction
activities, regulated LNG 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 Dominions gas transmission pipeline and storage business is its gas gathering and extraction activity, which sells
extracted products at market rates. Dominions LNG operations involve the import and storage of LNG at Cove Point and the transportation of regasified LNG to the interstate pipeline grid and mid-Atlantic and Northeast markets. In connection
with the recent increase in Eastern U.S. natural gas production, including from the Marcellus and Utica Shale formations, Dominion has requested regulatory authority to operate Cove Point as a bi-directional facility, able to import LNG, and
vaporize it as natural gas, and liquefy natural gas and export it as LNG. See Future Issues and Other Matters in MD&A for more information. 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 Dominions 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. Dominions gas distribution operations
serve residential, commercial and industrial gas sales, transportation and gathering 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 Dominions ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from operating and
maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.
In October 2008, East Ohio implemented a rate case settlement which provided for a straight-fixed-variable rate design 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 Ohios revenue is less impacted by weather-related fluctuations in natural gas consumption than under
the traditional rate design.
Earnings from Dominion Energys producer services business are unregulated, and are
subject to variability associated with changes in commodity prices. Producer services uses physical and financial arrangements to hedge this price risk.
COMPETITION
Dominion Energys 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 Dominions gas distribution subsidiaries operate. In Ohio, there has been no legislation enacted to require
supplier choice for residential natural gas consumers. However, Dominion has offered an Energy Choice program to residential and commercial customers since October 2000. In January 2013, the Ohio Commission granted East Ohios 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 Dominions 1.2 million Ohio customers were participating in this Energy Choice Program. West Virginia does not require customers to choose their provider in its retail natural gas markets at this time. See
Regulation-State Regulations-Gas for additional information.
REGULATION
Dominion Energys natural gas transmission pipeline, storage and LNG operations are regulated primarily by FERC. Dominion Energys gas
distribution service, including the rates that it may charge customers, is regulated by the Ohio and West Virginia Commissions. See State Regulations and Federal Regulations in Regulation for more information.
PROPERTIES
Dominion
Energys 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 owners of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many
natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.
Dominion Energy has approximately 11,000 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New
York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy operates gas processing and fractionation facilities in West Virginia with a total processing capacity of
267,000 mcf per day and fractionation capacity of 582,000 gallons per day. Dominion Energy also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West
Virginia, with almost 2,000 storage wells and approximately 349,000 acres of operated leaseholds.
The total designed capacity
of the underground storage fields operated by Dominion Energy is approximately 947 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy. The capacity of those fields owned by Dominions partners totals about 242 bcf.
Dominion Energy also has about 15 bcf of above-ground storage capacity at Cove Point. Dominion Energy has 133 compressor stations with more than 832,000 installed compressor horsepower.
In 2012, DTI completed the Gathering Enhancement Project, a $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 DTIs West Virginia system.
In September 2012, DTI completed the $575 million Appalachian Gateway Project. The project provides approximately 484,000
dekatherms per day of firm transportation services for new Appalachian gas supplies in West Virginia and southwestern Pennsylvania to an interconnection with Texas Eastern Transmission, LP at Oakford, Pennsylvania.
In November 2012, DTI completed the $97 million Northeast Expansion Project. The project provides approximately 200,000 dekatherms per day
of firm transportation services for CONSOLs 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.
In November 2012, DTI completed the $46 million Ellisburg-to-Craigs project. The projects capacity of approximately 150,000
dekatherms per day is leased by TGP to move Marcellus Shale natural gas supplies from TGPs 300 Line pipeline system in northern Pennsylvania to its 200 Line pipeline system in upstate New York.
In November 2011, DTI filed a FERC application for approval to construct the $17 million Sabinsville-to-Morrisville project, a pipeline to
move additional Marcellus supplies from a TGP pipeline in northeast Pennsylvania to its line in upstate New York. DTI executed a binding precedent agreement with TGP in October 2010 to provide this firm transportation service up to 92,000 dekatherms
per day for a 14-year term. Construction is expected to commence 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 7.5 bcf of incremental storage service and 125,000 dekatherms per day of
associated year-round firm transportation service to three local distribution companies under 15-year contracts. Storage capacity for the project will be provided from storage pool enhancements at DTI and capacity leased from East Ohio. DTI intends
to construct additional compression facilities and upgrade measurement and regulation in order to provide 115,000 dekatherms per day of transportation service. The remaining 10,000 dekatherms per day of transportation service will not require
construction of additional facilities. The $112 million project is expected to be in service in 2014.
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 DTIs Crayne interconnect with Texas Eastern
Transmission, LP in Greene County, Pennsylvania and the Leidy interconnect with Transcontinental Gas Pipe Line Company in Clinton County, Pennsylvania. Two customers have contracted for the service under 15-year terms. DTI filed a certificate
application with FERC in November 2011. Subject to the receipt of regulatory approvals, the project is anticipated to be in service in November 2013.
In January 2011, Dominion announced the development of a natural gas processing and fractionation facility in Natrium, West Virginia, and in July 2011 it executed a contract for the construction of the
first phase of the facility. This 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 Follansbee, West Virginia. Dominion NGL 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 interconnect between DTI and the Natrium facility to DTIs 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 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.
SOURCES OF
ENERGY SUPPLY
Dominion Energys 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. Dominions large underground natural gas storage network and the location of its pipeline system are a
significant link between the countrys major interstate gas pipelines and large markets in the Northeast
and mid-Atlantic regions. Dominions 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.
Dominions 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 Energys natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet
heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March; however implementation of the straight-fixed-variable rate design at East Ohio has reduced the
earnings impact of weather-related fluctuations. Demand for services at Dominions 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. Dominions 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
SegmentVirginia Power
Virginia Powers 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 SegmentDominion
Dominions Corporate and Other segment
includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are expected to be and are currently discontinued, which is discussed in Note 3 to the Consolidated Financial Statements.
In addition, Corporate and Other includes specific items attributable to Dominions operating segments that are not included in profit measures evaluated by executive management in assessing the segments performance or allocating
resources among the segments.
ENVIRONMENTAL STRATEGY
Dominion and Virginia Power are committed to being good environmental stewards. Their ongoing objective is to provide reliable, affordable energy for their customers while being environmentally
responsible. The integrated strategy to meet this objective consists of five major elements:
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Compliance with applicable environmental laws, regulations and rules; |
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Conservation and load management; |
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Renewable generation development; |
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Other generation development to maintain fuel diversity, including clean coal, advanced nuclear energy, and natural gas; and
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Improvements in other energy infrastructure.
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This strategy incorporates Dominions and Virginia Powers efforts to voluntarily
reduce GHG emissions, which are described below. See Dominion GenerationProperties for more information on certain of the projects described below, as well as other projects under current development. In addition to the environmental
strategy described above, Dominion formed the AES department in April 2009 to conduct research in the renewable and alternative energy technologies sector and to support strategic investments to advance Dominions 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 Dominions and
Virginia Powers environmental compliance matters can be found in Future Issues and Other Matters in Item 7. MD&A and in Note 22 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 Powers DSM programs provide important incremental steps toward achieving the voluntary ten percent energy conservation
goal. The conservation and load management plan includes the following DSM programs, which were approved by the Virginia Commission in March 2010 and rolled out in May 2010:
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Residential Lighting Programan 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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Residential Low Income Programfree energy audit for income-qualifying customers, which identifies, installs improvements and suggests additional
implementation measures that will help these customers save money on energy bills; |
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Residential Air Conditioner Cycling Programincentives for residential customers who allow Virginia Power to cycle their central air conditioners
and heat pump systems during peak periods; |
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Commercial Heating, Ventilating and Air Conditioning Upgrade Programincentives for commercial customers to improve the energy efficiency of their
heating and/or cooling units; and |
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Commercial Lighting Programincentives for commercial customers to install energy-efficient lighting. |
In September 2011, Virginia Power filed 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 costs. In April 2012, the Virginia Commission approved the following programs:
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Commercial Energy Audit Programan on-site energy audit providing commercial customers information to evaluate potential energy cost savings
options; |
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Commercial Duct Testing & Sealingan incentive for commercial customers to seal duct and air distribution systems to improve system
efficiency; |
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Commercial Distributed Generationa program for customers to operate their on-site back-up generators when requested by Virginia Power during
periods of peak demand; and |
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Residential Bundle Programa 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 began 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 extend 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 Power also filed for approval of updated rate adjustment clauses for DSM program cost recovery, and 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 initially approved in Virginia in 2010, as well as the distributed generation program. In February 2011, the North Carolina Commission approved the five DSM programs approved in Virginia, and Virginia Power
subsequently launched the residential lighting program in May 2011 and the remainder of the approved 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 denied approval of Virginia Powers proposed distributed generation program.
In August 2011, Virginia Power filed with the North Carolina Commission an application for approval and its updated request for cost recovery of the five DSM programs approved in North Carolina, as well
as the then-pending distributed generation program. In December 2011, the North Carolina 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 Powers request to suspend the Commercial 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 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
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 Virginias goals of 12% of base year electric energy
sales from renewable power sources by 2022, and 15% by 2025, and North Carolinas RPS of 12.5% by 2021. In May 2010, the Virginia Commission approved Virginia Powers participation in the states RPS program. As a participant,
Virginia Power is permitted to seek recovery, through rate adjustment clauses, of the costs of programs designed to meet RPS goals. Virginia Power plans to meet the respective RPS targets in Virginia and North Carolina by utilizing existing
renewable facilities, as well as through additional renewable generation. In addition, Virginia Power intends to purchase renewable energy certificates, as permitted by each RPS program, to help meet any remaining annual requirement 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. Virginia Power is converting three coal-fired Virginia generating power stations to biomass, which will increase Dominions renewable generation by more than 150 MW. The
conversions are expected to be completed by the end of 2013. In November 2012, the Virginia Commission approved a voluntary demonstration program for Company-owned solar distributed generation facilities, to be located at selected commercial,
industrial and community locations throughout its Virginia service territory.
Dominion has invested in wind energy through two
joint ventures. Dominion is a 50% owner with Shell of NedPower. Dominions 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.
See Note 13 to the Consolidated Financial Statements for additional information.
Other Generation
Development
Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which
involves the development, financing, construction and operation of new
multi-fuel, multi-technology generation capacity to meet the anticipated growth in demand in its core market of Virginia. Virginia Power expects that these investments collectively will provide
the following benefits: expanded electricity production capability, increased technological and fuel diversity and a reduction in the CO2 emission intensity of its generation fleet.
Improvements in Other Energy Infrastructure
Virginia Powers five-year investment plan includes
significant capital expenditures to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability. These enhancements are primarily
aimed at meeting Virginia Powers continued goal of providing reliable service, and are intended to address both continued population growth and increases in electricity consumption by the typical consumer. An additional benefit will be added
capacity to efficiently deliver electricity from the renewable projects now being developed or to be developed in the future.
Virginia Power is taking measures to ensure that its electrical infrastructure can support the expected demand from electric vehicles,
which have significantly lower carbon intensity than conventional vehicles. Virginia Power has partnered with Ford Motor Company to help prepare Virginia for the operation of electric vehicles, in a collaboration that involves consumer outreach,
educational programs and the exchange of information on vehicle charging requirements. In July 2011, the Virginia Commission approved Virginia Powers 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 Powers Strategy for Voluntarily Reducing
GHG Emissions
While Dominion and Virginia Power have not established a standalone GHG emissions reduction target or timetable, they are
actively engaged in voluntary reduction efforts, as well as working toward achieving required RPS standards established by existing state regulations, as set forth above. The Companies have an integrated voluntary strategy for reducing overall GHG
emission intensity that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, oil, hydro and renewable energy, investing in renewable energy projects and promoting energy conservation and efficiency efforts. Below are some of the
Companies efforts that have or are expected to reduce the Companies overall carbon emissions or intensity:
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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. |
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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. |
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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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Dominion has over 800 MW of wind energy in operation or development. |
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Virginia Power is constructing the natural gas-fired Warren County power station. |
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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. |
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Virginia Power has stated that coal-fired units at Chesapeake and Yorktown are planned to be retired by 2015. |
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Virginia Power has received an Early Site Permit from the NRC for the possible addition of approximately 1,500 MW of nuclear generation in Virginia.
Virginia Power has not yet committed to building a new nuclear unit. |
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Virginia Power has developed and implemented the DSM programs described above. |
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Virginia Power has initiated a demonstration of smart grid technologies as described above. |
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In October 2011, Virginia Power announced plans to develop a community solar power program. |
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In 2012, Dominion sold Salem Harbor and State Line, two coal-and fuel oil-fired facilities. |
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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.
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In December 2012, Dominion announced its plans to develop a 15 MW fuel cell power generating facility in Bridgeport, Connecticut.
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While Virginia Powers 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, Dominions and Virginia Powers 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 segments 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, DTIs (including Cove Point) direct CO2 equivalent emissions were approximately 1.2 million metric tonnes and East Ohios direct CO2 equivalent emissions were approximately 1.1 million metric tonnes.
The emissions appear to have decreased significantly compared to previous years 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. Dominions 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 Powers 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 Powers 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 Dominions 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 Dominions 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.
State Regulations
ELECTRIC
Virginia Powers 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 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 Powers transactions with affiliates, transfers of certain facilities and the
issuance of certain securities.
Electric Regulation in Virginia
The enactment of the Regulation Act in 2007 significantly changed electric service regulation in Virginia by instituting a modified cost-of-service rate model. With respect to most classes of customers,
the Regulation Act ended Virginias planned transition to retail competition for its electric supply service. Base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. The Virginia Commission reviews
Virginia Powers base rates, terms and conditions for generation and distribution services on a biennial basis in a proceeding that involves the determination of Virginia Powers actual earned ROE during a combined
two-year historic test period, and the determination of Virginia Powers authorized ROE prospectively. If, as a result of the earnings test review, the Virginia Commission determines that Virginia
Powers 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 may also order a base rate increase or reduction during the biennial review. Circumstances where the Virginia Commission may order a base rate decrease
include a determination by the Virginia Commission that Virginia Power has exceeded its authorized level of earnings by more than 50 basis points for two consecutive biennial review periods. Virginia Powers authorized ROE can be set
no lower than the average, for a three-year historic period, of the actual returns reported to the SEC by not less than a majority of comparable utilities within the Southeastern U.S., with certain limitations as described in the
Regulation Act. Virginia Powers ROE may be increased or decreased by up to 100 basis points based on operating performance criteria, or alternatively, will be increased by 50 basis points for compliance with Virginias RPS.
In addition, the Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation
facilities or major unit modifications of existing facilities, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It provides for enhanced returns on capital
expenditures relating to the construction or major modification of facilities that are nuclear-powered, clean coal/carbon capture compatible-powered, or renewable-powered, as well as conventional coal and combined-cycle
combustion turbine facilities.
Costs of fuel used for the generation of electricity, along with costs of purchased power, are recovered from customers through an annually approved fuel rider, as provided
under a separate section of the Virginia Code. Decisions of the Virginia Commission may be appealed to the Supreme Court of Virginia.
If the Virginia Commissions future rate decisions, including actions relating to Virginia Powers rate adjustment clause filings, differ materially from Virginia Powers expectations, it
could adversely affect its results of operations, financial condition and cash flows.
See Future 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
Virginia Powers retail electric base rates in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes and the rules and procedures of the North
Carolina Commission. North Carolina base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the North Carolina Commission,
retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Powers future earnings. Additionally, if the North Carolina Commission does not allow recovery of costs
incurred in providing service on a timely basis, Virginia Powers future earnings could be negatively impacted. Fuel rates are subject to revision under annual fuel cost adjustment proceedings.
Virginia Powers transmission service rates in North Carolina are regulated by the North Carolina Commission as part of Virginia
Powers bundled retail service to North Carolina customers.
In March 2012, Virginia Power filed an application with the North Carolina
Commission to increase base non-fuel revenues with January 1, 2013 as the proposed effective date for the permanent rate revision. See Note 13 to the Consolidated Financial Statements for additional information.
GAS
Dominions 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.
OhioSince October 2000, East Ohio has offered the Energy Choice program,
under which residential and commercial customers are encouraged to purchase gas directly from retail suppliers or through a community aggregation program. In October 2006, East Ohio restructured its commodity service by entering into gas purchase
contracts with selected suppliers at a fixed price above the NYMEX month-end settlement and passing that gas cost to customers under the Standard Service Offer 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
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 Ohios 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 Dominions 1.2 million Ohio
customers were participating in the Energy Choice program. Subject to the Ohio Commissions 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 VirginiaAt this time, West Virginia has not enacted legislation to require customers to choose in the retail natural gas markets served by Hope. However, the West Virginia Commission has
issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customers a choice in the future and has issued rules requiring competitive gas service providers to be licensed in West
Virginia.
Rates
Dominions gas
distribution subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operateOhio and West Virginia. When necessary, Dominions gas distribution subsidiaries seek general base rate
increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost of service by rate class. A straight-fixed-variable rate design, in which the majority of operating costs are recovered
through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohios 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, Dominions gas distribution subsidiaries make routine separate filings with their respective state
regulatory commissions to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery
through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are
deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective one-, three- or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with
corresponding increases or decreases in net purchased gas cost expenses. The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure projects and certain other costs
that vary widely over time; such costs are excluded from general base rates. See Note 13 to the Consolidated Financial Statements for additional information.
Federal Regulations
FEDERAL ENERGY REGULATORY COMMISSION
Electric
Under the Federal Power Act, FERC
regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominions merchant generators sell electricity in the PJM,
MISO and ISO-NE wholesale markets under Dominions 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 Powers service territory. Any such sales would be voluntary.
Dominion and Virginia Power are subject to FERCs 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 FERCs affiliate restrictions that (1) prohibit power
sales between Virginia Power and Dominions merchant plants without first receiving FERC authorization, (2) require the merchant plants and Virginia Power to conduct their wholesale power sales operations separately, and (3) prohibit
Virginia Power from sharing market information with merchant plant operating personnel. The rules are designed to prohibit Virginia Power from giving the merchant plants a competitive advantage.
EPACT included provisions to create an ERO. The ERO is required to promulgate mandatory reliability standards governing the operation of
the bulk power system in the U.S. FERC has certified NERC as the ERO and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of between $1 thousand
and $1 million per day, and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
Dominion and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion and Virginia Power employees participate on various NERC committees, track
the development and implementation of standards, and maintain proper compliance registration with NERCs regional organizations. Dominion and Virginia Power anticipate incurring additional compliance expenditures over the next several years as
a result of the implementation of new cybersecurity programs as well as efforts to ensure appropriate facility ratings for Virginia Powers transmission lines. In October 2010, NERC issued an industry alert identifying possible discrepancies
between the design and actual field conditions of transmission facilities as a potential reliability issue. The alert recommends that entities review their current facilities rating methodology to verify that the methodology is based on actual field
conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power is evaluating its transmission facilities for any discrepancies between design and
actual field conditions. In addition, NERC has requested the industry to increase the number of assets subject to NERC reliability standards that are designated as critical assets, including
cybersecurity assets. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.
In April 2008, FERC granted an application for Virginia Powers 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
Dominions 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.
Dominions interstate gas transmission and storage activities are generally conducted on an open access basis, in
accordance with certificates, tariffs and service agreements on file with FERC.
Dominion is also subject to the Pipeline
Safety Acts of 2002 and 2011, which mandate inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those located in areas of high-density population. Dominion has evaluated its natural gas transmission
and storage properties, as required by the Department of Transportation regulations under these Acts, and has implemented a program of identification, testing and potential remediation activities. These activities are ongoing.
See Future Issues and Other Matters in Item 7. MD&A and Note 13 to the Consolidated Financial Statements for additional
information.
Environmental Regulations
Each of Dominions and Virginia Powers operating segments faces substantial laws, regulations and compliance costs with respect to
environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of
complying with applicable environmental laws, regulations and rules is expected to be material to the Companies. If expenditures for pollution control technologies and associated operating costs are not recoverable from customers through regulated
rates (in regulated jurisdictions) or market prices (in deregulated jurisdictions), those costs could adversely affect future results of operations and cash flows. Dominion and Virginia Power have applied for or obtained the necessary environmental
permits for the operation of their facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned
capital expenditures relating to environmental compliance required to be discussed in this Item, see Environmental Matters in Future Issues and Other Matters in Item 7.
MD&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 22 to the Consolidated Financial Statements.
GLOBAL CLIMATE CHANGE
The national and international attention in recent years on GHG emissions and their relationship to climate change has resulted in federal, regional and state legislative or regulatory action in this
area. Dominion and Virginia Power support national climate change legislation that would provide a consistent, economy-wide approach to addressing this issue and are currently taking action to protect the environment and address climate change while
meeting the future needs of their growing service territory. Dominions CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including climate change, and Dominions
Board of Directors receives periodic updates on these matters. See Environmental Strategy above, Environmental Matters in Future Issues and Other Matters in Item 7. MD&A and Note 22 to the Consolidated Financial
Statements for information on climate change legislation and regulation, which information is incorporated herein by reference.
Nuclear Regulatory
Commission
All aspects of the operation and maintenance of Dominions and Virginia Powers nuclear power stations are regulated
by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.
From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new
regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining Dominions
and Virginia Powers nuclear generating units. See Nuclear Matters in Future 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, see Dominion Generation-Nuclear Decommissioning and Note 9 to the Consolidated Financial Statements. See Note 22 to the Consolidated Financial Statements for information
on spent nuclear fuel.
CYBERSECURITY
In an
effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, Dominion
and Virginia Power are subject to mandatory cybersecurity regulatory requirements, interface regularly with a wide range of external organizations, and participate in classified briefings to maintain an awareness of current cybersecurity threats and
vulnerabilities. The Companies current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats.
Item 1A. Risk Factors
Dominions and Virginia Powers 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.
Dominions and
Virginia Powers 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. Changes in weather conditions can result in reduced water levels or changes in water temperatures that could adversely affect operations at some of the Companies power stations. Furthermore, the Companies operations could be
adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and
extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level or sea temperatures.
The rates of Dominions gas transmission and distribution operations and Virginia Powers electric transmission, distribution and generation
operations are subject to regulatory review. Revenue provided by Virginia Powers electric transmission, distribution and
generation operations and Dominions 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 Powers 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
Powers wholesale electric transmission cost of service is estimated and thereafter adjusted to reflect Virginia Powers 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 Powers wholesale revenue requirement is no longer just and reasonable.
Similarly, various rates and charges assessed by Dominions gas transmission businesses are subject to review by FERC. In addition,
the rates of Dominions gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate.
Virginia Powers 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 Powers actual earned ROE during a combined two-year historic test period, and the determination of Virginia Powers 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 Powers 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 Powers 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 Powers future earnings could be negatively impacted.
Dominion and Virginia Power are subject to complex governmental regulation that could
adversely affect their results of operations and subject the Companies to monetary penalties. Dominions and Virginia
Powers operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. These operations are also subject to legislation governing taxation at
the federal, state and local level. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that the business is conducted in
accordance with applicable laws. The 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.
Dominions and Virginia Powers 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. Dominions and Virginia Powers 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 FERCs 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 Dominions authority to sell
at market-based rates. Material changes by FERC to the design of the wholesale markets, Dominions or Virginia Powers 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 Dominions or Virginia Powers generation business.
Dominion and Virginia Power infrastructure 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 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. 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 weather
conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of their counterparties or vendors,
or other factors beyond their control. Even if plant construction and expansion projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of Dominion and Virginia Power following the
projects may not meet expectations. Additionally, Dominion and Virginia Power may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or
unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies ability to realize the
anticipated benefits from the plant construction and expansion projects.
Dominions and Virginia Powers current costs of compliance with environmental laws
are significant. The costs of compliance with future environmental laws, including laws and regulations designed to address global climate change, air quality, coal combustion by-products, cooling water and other matters could make certain of the
Companies generation facilities uneconomical to maintain or operate. Dominions and Virginia Powers operations
are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the
Companies to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible
for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant
in the past, and Dominion and Virginia Power expect that they will remain significant in the future.
Existing
environmental laws and regulations may be revised and/or new laws may be adopted or become applicable to Dominion or Virginia Power. The EPA is expected to issue additional regulations with respect to air quality under the CAA, including revised
NAAQS and regulations governing the emissions of GHGs from electric generating units. Risks relating to potential regulation of GHG emissions are discussed below. Dominion and Virginia Power also expect additional federal water and waste
regulations, including regulations concerning cooling water intake structures and coal combustion by-product handling and disposal practices that are expected to be applicable to at least some of its generating facilities.
Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any
new environmental rules or regulations. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that
impose joint and several liability on all responsible parties. However, such expenditures, if material, could make the Companies facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect
Dominions or Virginia Powers results of operations, financial performance or liquidity.
If additional federal and/or state requirements
are imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements, such requirements may result in compliance costs that alone or in combination could make some of Dominions or Virginia Powers electric generation units or natural gas facilities uneconomical
to maintain or operate. The EPA, environmental advocacy groups, other organizations and some state and other federal agencies are
focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. Dominion and Virginia Power expect that additional EPA regulations, and possibly additional state legislation and/or
regulations, may be issued resulting in the imposition of additional limitations on GHG emissions or requiring efficiency improvements from fossil fuel-fired electric generating units.
There are also potential impacts on Dominions natural gas businesses as federal or state GHG legislation or
regulations may require GHG emission reductions from the natural gas sector and could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products. Several regions of
the U.S. have moved forward with GHG emission regulations including regions where Dominion has operations. For example, Massachusetts and Rhode Island have implemented regulations requiring reductions in CO2 emissions through RGGI, a cap and trade program covering CO2 emissions from power plants in the Northeast, which affects several of
Dominions facilities.
Compliance with GHG emission reduction requirements may require increasing the energy efficiency
of equipment at facilities, committing significant capital toward carbon capture and storage technology, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with
lower emitting generation facilities. The cost of compliance with GHG emission legislation and/or regulation is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the
implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon capture and storage technology, and the selected compliance alternatives. The Companies cannot estimate
the aggregate effect of such requirements on their results of operations, financial condition or their customers. However, such expenditures, if material, could make the Companies generation facilities uneconomical to operate, result in the
impairment of assets, or otherwise adversely affect Dominions or Virginia Powers results of operations, financial performance or liquidity.
Risks arising from the reliability of the Companies facilities supply chain disruptions or personnel issues could result in lost revenues
and increased expenses, including higher maintenance costs. Operation of
the Companies facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply 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 operation of the Companies facilities. Because Virginia Powers transmission facilities are interconnected with
those of third parties, the operation of its facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
Operation of the Companies facilities below expected capacity levels could result in
lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of the Companies facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an
inherent risk of the Companies business. Unplanned outages typically increase the Companies operation and maintenance expenses and may reduce their revenues as a result of selling less output or may require the Companies to incur
significant costs as a result of operating higher cost units or obtaining replacement output from third parties in the open market to satisfy forward energy and capacity or other contractual obligations. Moreover, if the Companies are unable to
perform their contractual obligations, penalties or liability for damages could result.
Dominion and Virginia Power have substantial ownership interests in and operate nuclear generating units; as a result, each may incur substantial costs and liabilities.
Dominions and Virginia Powers 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 Dominions and Virginia Powers 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.
Dominions and Virginia Powers 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 Dominions
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 Dominions facilities, although the producers that have
con-
tracted to supply natural gas to Dominions 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 Dominions 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.
Dominions merchant power business is operating in a challenging
market, which could adversely affect its results of operations and future growth. The success of Dominions merchant power business depends upon favorable market conditions including
the ability to sell power at prices sufficient to cover its operating costs. Dominion operates in active wholesale markets that expose it to price volatility for electricity and fuel as well as the credit risk of counterparties. Dominion attempts to
manage its price risk by entering into hedging transactions, including short-term and long-term fixed price sales and purchase contracts.
In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases,
the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost
to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion does not enter into long-term power purchase agreements or otherwise
effectively hedge its output, these changes in market prices could adversely affect its financial results.
Dominion purchases
fuel under a variety of terms, including long-term and short-term contracts and spot market purchases. Dominion is exposed to fuel cost volatility for the portion of its fuel obtained through short-term contracts or on the spot market, including as
a result of market supply shortages. Fuel prices can be volatile and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs, thus adversely impacting Dominions financial results.
Energy conservation could negatively impact Dominions and Virginia
Powers 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 adversely affect the Companies financial results of operations. Dominion and Virginia Power are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including
but not limited to payment for services. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Such defaults by customers, suppliers or
other third parties may adversely affect the Companies financial results.
Market performance and other changes may
decrease the value of decommissioning trust funds and benefit plan assets or increase Dominions liabilities, which could then require significant additional funding. The performance
of the capital markets affects the value of the assets that are held in trusts to satisfy future obligations to decommission Dominions nuclear plants and under its pension and other postretirement benefit plans. Dominion has significant
obligations in these areas and holds significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates.
With respect to decommissioning trust funds, a decline in the market value of these assets may increase the funding requirements of the
obligations to decommission Dominions 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 Dominions pension and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates affect
the liabilities under Dominions pension and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of
retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans.
If the decommissioning trust funds and benefit plan assets are negatively impacted by market fluctuations or other factors,
Dominions results of operations, financial condition and/or cash flows could be negatively affected.
The use of derivative instruments could result in financial losses and liquidity constraints.
Dominion and Virginia Power use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity and financial market risks. In addition, Dominion
purchases and sells commodity-based contracts primarily in the natural gas market for trading purposes. The Companies could recognize financial losses on these contracts, including as a result of volatility in the market values of the underlying
commodities, if a counterparty fails to perform under a contract or upon the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these transactions. In the absence of actively-quoted market
prices and pricing information from external sources, the valuation of these contracts involves managements judgment or use of estimates. As a result, changes in the under-lying assumptions or use of alternative valuation methods could affect
the reported fair value of these contracts.
The use of derivatives to hedge future sales may limit the benefit Dominion
would otherwise receive from increases in commodity prices. These hedge arrangements generally include collateral requirements that require Dominion to deposit funds or post letters of credit with counterparties, financial intermediaries or
clearinghouses to cover the fair value of covered contracts in excess of agreed upon credit limits. For instance, when commodity prices rise to levels substantially higher than the levels where it has hedged future sales, Dominion may be required to
use a material portion of its available liquidity or obtain additional liquidity to cover these collateral requirements. In some circumstances, this could have a compounding effect on Dominions 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 Dominions results of operations.
Dominions and Virginia Powers operations in regards to these transactions are subject to multiple market risks including
market liquidity, price volatility, credit strength of the Companies counterparties and the financial condition of the financial intermediaries, exchanges and clearinghouses used for the types of transactions. These market risks are beyond the
Companies control and could adversely affect their results of operations, liquidity and future growth.
The Dodd-Frank
Act 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 derivative-related provisions of the Dodd-Frank Act will continue to be established through the ongoing rulemaking process of the applicable regulators. If, as a result of the rulemaking process,
Dominions or Virginia Powers derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs, including from higher margin requirements, for their
derivative activities. In addition, implementation of, and compliance with, the 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.
Changing rating agency requirements could negatively
affect Dominions and Virginia Powers 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 Dominions 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 Dominions and Virginia Powers 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 Dominions and Virginia Powers control could increase their cost of borrowing or restrict their
ability to access one or more financial markets. Further market disruptions could stem from delays in the current economic recovery, the bankruptcy of an unrelated company, general market
disruption due to general credit market or political events, or the failure of financial institutions on which the Companies rely. Increased costs and restrictions on the Companies ability to access financial markets may be severe enough to
affect their ability to execute their business plans as scheduled.
Potential changes in accounting practices may adversely affect Dominions and
Virginia Powers 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
earnings or could increase liabilities.
War, acts and threats of terrorism,
natural disaster and other significant events could adversely affect Dominions and Virginia Powers 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 Dominions and Virginia Powers operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on Dominions and Virginia Powers
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 Dominions and Virginia Powers operations. Dominions and Virginia Powers 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.
Item 2. Properties
As of December 31, 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 Powers DVP and Generation segments share certain leased buildings and equipment. See Item 1. Business for additional information about each segments principal
properties, which information is incorporated herein by reference.
Dominions 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 Powers 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, 2012; however, by leaving the indenture open, Virginia
Power retains the flexibility to issue mortgage bonds in the future. Certain of Dominions 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, 2012, Dominion Generations total utility
and merchant generating capacity was approximately 27,500 MW.
The following tables list Dominion Generations utility and merchant generating units and capability, as of
December 31, 2012:
VIRGINIA POWER UTILITY GENERATION
|
|
|
|
|
|
|
|
|
|
|
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) |
Certain coal-fired units are expected to be retired at Chesapeake and Yorktown by 2015 as a result of the issuance of the MATS rule. |
(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. |
(4) |
In the first quarter of 2012, the facility received regulatory approval to convert to biomass. |
(5) |
Excludes 50% undivided interest owned by ODEC. |
(6) |
Excludes 11.6% undivided interest owned by ODEC. |
(7) |
Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc. |
DOMINION MERCHANT GENERATION
|
|
|
|
|
|
|
|
|
|
|
Plant |
|
Location |
|
Net Summer
Capability (MW) |
|
|
Percentage
Net Summer
Capability |
|
Nuclear |
|
|
|
|
|
|
|
|
|
|
Millstone |
|
Waterford, CT |
|
|
2,016
|
(5)
|
|
|
|
|
Kewaunee(1) |
|
Kewaunee, WI |
|
|
556 |
|
|
|
|
|
Total Nuclear |
|
|
|
|
2,572 |
|
|
|
33 |
% |
Gas |
|
|
|
|
|
|
|
|
|
|
Fairless
(CC)(2),(3) |
|
Fairless Hills, PA |
|
|
1,196 |
|
|
|
|
|
Elwood
(CT)(2),(4) |
|
Elwood, IL |
|
|
712
|
(6)
|
|
|
|
|
Manchester (CC) |
|
Providence, RI |
|
|
432 |
|
|
|
|
|
Total Gas |
|
|
|
|
2,340 |
|
|
|
30 |
|
Coal |
|
|
|
|
|
|
|
|
|
|
Kincaid(2),(4) |
|
Kincaid, IL |
|
|
1,158 |
|
|
|
|
|
Brayton Point(4) |
|
Somerset, MA |
|
|
1,083 |
|
|
|
|
|
Total Coal |
|
|
|
|
2,241 |
|
|
|
28 |
|
Oil |
|
|
|
|
|
|
|
|
|
|
Brayton Point(4) |
|
Somerset, MA |
|
|
435 |
|
|
|
|
|
Total Oil |
|
|
|
|
435 |
|
|
|
6 |
|
Wind |
|
|
|
|
|
|
|
|
|
|
Fowler
Ridge(2) |
|
Benton County, IN |
|
|
150
|
(7)
|
|
|
|
|
NedPower Mt. Storm(2) |
|
Grant County, WV |
|
|
132 |
(8) |
|
|
|
|
Total Wind |
|
|
|
|
282 |
|
|
|
3 |
|
Various |
|
|
|
|
|
|
|
|
|
|
Brayton Point(4),(9) |
|
Somerset, MA |
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Merchant Generation |
|
|
|
|
7,880 |
|
|
|
100 |
% |
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) |
In the fourth quarter of 2012, Dominion announced that it would permanently cease operations at Kewaunee in 2013 and commence decommissioning of this facility.
|
(2) |
Subject to a lien securing the facilitys debt. Also see Note 17 to the Consolidated Financial Statements for additional information on liens related to Kincaid
and Fairless. |
(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 Green Mountain Power Corporation.
|
(6) |
Excludes 50% membership interest owned by J-POWER Elwood, LLC. |
(7) |
Excludes 50% membership interest owned by BP. |
(8) |
Excludes 50% membership interest owned by Shell. |
(9) |
Represents four diesel generators. |
Item 3. Legal Proceedings
From time to time, Dominion and Virginia Power are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the
environment, compliance plans imposed upon or agreed to by the Companies, or permits issued by various local, state and/or federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these
matters. In addition, in the ordinary course of business, the Companies and their subsidiaries are involved in various legal proceedings.
In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at
State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming
violations of the CAA New Source Review requirements, NSPS, and Title V permit program and the stations respective State Implementation Plans. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA
provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPAs 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. 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 and Future Issues and Other Matters in MD&A, which information is
incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which the Companies are a party.
Item 4. Mine Safety Disclosures
Not applicable.
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 (58) |
|
Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date; Chairman of the Board of Directors and CEO of Virginia Power
from February 2006 to date. |
|
|
Mark F. McGettrick (55) |
|
Executive Vice President and CFO of Dominion and Virginia Power from June 2009 to date; Executive Vice President of Dominion from April 2006 to May 2009; President and COO-Generation of
Virginia Power from February 2006 to May 2009. |
|
|
Paul D. Koonce (53) |
|
Executive Vice President and Chief Executive Officer Energy Infrastructure 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 April 2006 to February 2013. |
|
|
David A. Christian (58) |
|
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 2009. |
|
|
David A. Heacock (55) |
|
President and CNO of Virginia Power from June 2009 to date; Senior Vice President of Dominion and President and COO-DVP of Virginia Power from June 2008 to May 2009; Senior Vice President-DVP
of Virginia Power from October 2007 to May 2008. |
|
|
Gary L. Sypolt (59) |
|
Executive Vice President of Dominion from May 2011 to date; President of DTI from June 2009 to date; President-Transmission of DTI from January 2003 to May 2009. |
|
|
Robert M. Blue (45) |
|
Senior Vice President-Law, Public Policy and Environment of Dominion and Virginia Power from January 2011 to date; Senior Vice President-Public Policy and Environment of Dominion from
February 2010 to December 2010; Senior Vice President-Public Policy and Corporate Communications of Dominion from May 2008 to January 2010; Vice President-State and Federal Affairs of DRS from September 2006 to May 2008. |
|
|
Steven A. Rogers
(51)(2) |
|
Senior Vice President and Chief Administrative Officer of Dominion from October 2007 to December 2012; Senior Vice President and CAO of Dominion and Virginia Power from January 2007 to
September 2007 and CNG from January 2007 to June 2007. |
|
|
Ashwini Sawhney (63) |
|
Vice President-Accounting and Controller (CAO) of Dominion from May 2010 to date; Vice President and Controller (CAO) of Dominion from July 2009 to May
2010; Vice President-Accounting of Virginia Power from April 2006 to date; Vice President and Controller of Dominion from April 2007 to June 2009. |
(1) |
Any service listed for Virginia Power, DTI and DRS reflects service at a subsidiary of Dominion. |
(2) |
Steven A. Rogers ceased to be an executive officer of Dominion as of January 1, 2013. |
Part II
Item 5. Market for the Registrants
Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Dominion
Dominions common stock is listed on the NYSE. At January 31, 2013, there were approximately 139,000 record holders of Dominions common
stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominions transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct
Registration System and (3) book-entry under Dominion Direct. Discussions of expected dividend payments and restrictions on Dominions payment of dividends required by this Item are contained in Liquidity and Capital Resources in
Item 7. MD&A and Notes 17 and 20 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 2012 and 2011. Quarterly information concerning stock prices and dividends is disclosed in Note 26 to the Consolidated
Financial Statements, which information is incorporated herein by reference.
The following table presents certain information
with respect to Dominions common stock repurchases during the fourth quarter of 2012:
DOMINION PURCHASES
OF EQUITY SECURITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period |
|
Total
Number of Shares
(or Units) Purchased(1) |
|
|
Average Price Paid per Share (or Unit)(2) |
|
|
Total Number
of Shares (or Units)
Purchased as Part
of Publicly Announced Plans or
Programs |
|
|
Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(3) |
|
10/1/2012-10/31/12 |
|
|
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) |
In October 2012, 467 shares were tendered by employees to satisfy tax withholding obligations on vested restricted stock. |
(2) |
Represents the weighted-average price paid per share. |
(3) |
The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Board of Directors in February 2005, as modified in June 2007. The
aggregate authorization granted by the Dominion Board of Directors was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion. |
Virginia Power
There is no established public
trading market for Virginia Powers common stock, all of which is owned by Dominion. Restrictions on Virginia Powers payment of dividends are discussed in Dividend 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
Second Quarter |
|
|
Third Quarter |
|
|
Fourth Quarter |
|
|
Full Year |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 |
|
$ |
149 |
|
|
$ |
120 |
|
|
$ |
110 |
|
|
$ |
180 |
|
|
$ |
559 |
|
2011 |
|
|
131 |
|
|
|
118 |
|
|
|
199 |
|
|
|
109 |
|
|
|
557 |
|
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 Dominions 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 managements 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 Dominions 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 Powers 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 22 to the Consolidated Financial Statements.
2009 results include a $427 million
after-tax charge in connection with the settlement of Virginia Powers 2009 base rate case proceedings.
Item 7. Managements Discussion and Analysis of Financial Condition and
Results of Operations
MD&A discusses Dominions and Virginia Powers results of operations and general financial
condition. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data.
CONTENTS OF MD&A
MD&A consists of the following
information:
|
|
Forward-Looking Statements |
|
|
|
Segment Results of Operations |
|
|
|
Segment Results of Operations |
|
|
Selected InformationEnergy Trading Activities |
|
|
Liquidity and Capital Resources |
|
|
Future Issues and Other Matters |
FORWARD-LOOKING
STATEMENTS
This report contains statements concerning Dominions and Virginia Powers 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:
|
|
Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; |
|
|
Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, earthquakes and changes in water temperature and
availability that can cause outages and property damage to facilities; |
|
|
Federal, state and local legislative and regulatory developments; |
|
|
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; |
|
|
Cost of environmental compliance, including those costs related to climate change; |
|
|
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; |
|
|
Unplanned outages of the Companies facilities;
|
|
|
Fluctuations in energy-related commodity prices and the effect these could have on Dominions earnings and Dominions and Virginia
Powers liquidity position and the underlying value of their assets; |
|
|
Counterparty credit and performance risk; |
|
|
Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; |
|
|
Risks associated with Virginia Powers membership and participation in PJM, including risks related to obligations created by the default of other
participants; |
|
|
Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion;
|
|
|
Fluctuations in interest rates; |
|
|
Changes in federal and state tax laws and regulations; |
|
|
Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; |
|
|
Changes in financial or regulatory accounting principles or policies imposed by governing bodies; |
|
|
Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; |
|
|
Risks of operating businesses in regulated industries that are subject to changing regulatory structures; |
|
|
Impacts of acquisitions, divestitures and retirements of assets based on asset portfolio reviews; |
|
|
Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; |
|
|
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; |
|
|
Political and economic conditions, including inflation and deflation; |
|
|
Domestic terrorism and other threats to the Companies physical and intangible assets, as well as threats to cybersecurity;
|
|
|
Changes in demand for the Companies services, including industrial, commercial and residential growth or decline in the Companies service
areas, changes in customer growth or usage patterns, including as a result of energy conservation programs, and changes in demand for Dominions natural gas services; |
|
|
Additional competition in the electric industry, including in electric markets in which Dominions merchant generation facilities operate, and
competition in the construction and ownership of electric transmission facilities in Virginia Powers service territory, in connection with FERC Order 1000; |
|
|
Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;
|
|
|
Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG
storage, collected by Dominion; |
|
|
Timing and receipt of regulatory approvals necessary for planned construction or expansion projects; |
|
|
The inability to complete planned construction projects within the terms and time frames initially anticipated; and |
|
|
Adverse outcomes in litigation matters or regulatory proceedings. |
Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.
Managements 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 Committees of their Boards of Directors. Virginia Powers Board of Directors also serves as its Audit
Committee.
ACCOUNTING FOR REGULATED OPERATIONS
The accounting for Virginia Powers regulated electric and Dominions regulated gas operations differs from the accounting for nonregulated
operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to
accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs are deferred as
regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from
customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.
The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally
based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period
such assessment is made. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.
ASSET
RETIREMENT OBLIGATIONS
Dominion and Virginia Power recognize liabilities for the expected cost of retiring
tangible long-lived assets for which a legal obligation exists and the ARO can be reasonably estimated. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of
quoted market prices, the Companies estimate the fair value of their AROs using present value techniques, in which they make various assumptions including estimates of the amounts and timing of future cash flows associated with retirement
activities, credit-adjusted risk free rates and cost escalation rates. The impact on measurements of new AROs or remeasurements of existing AROs, using different cost escalation rates in the future, may be significant. When the Companies revise any
assumptions used to calculate the fair value of existing AROs, they adjust the carrying amount of both the ARO liability and the related long-lived asset. The Companies accrete the ARO liability to reflect the passage of time.
In 2012, 2011 and 2010, Dominion recognized $77 million, $84 million and $85 million,
respectively, of accretion, and expects to recognize $88 million in 2013. In 2012, 2011 and 2010, Virginia Power recognized $34 million, $36 million and $35 million, respectively, of accretion, and expects to recognize $38 million in 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 Dominions merchant and Virginia Powers utility nuclear facilities. These nuclear decommissioning AROs
are reported in the Dominion Generation segment. At December 31, 2012, Dominions nuclear decommissioning AROs totaled $1.5 billion, representing approximately 86% of its total AROs. At December 31, 2012, Virginia
Powers nuclear decommissioning AROs totaled $633 million, representing approximately 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 Companies determine cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each
nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be a critical assumption.
In September 2012, Dominion recorded an increase of $246 million in the nuclear decommissioning AROs for its units. The ARO revision was primarily driven by managements 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.
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, 2012, Dominion had $293 million
and Virginia Power had $57 million of unrecognized tax benefits.
Deferred income tax assets and liabilities are recorded
representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power evaluate quarterly the probability of realizing deferred tax
assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve
forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. The Companies establish a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax
asset will not be realized. At December 31, 2012, Dominion had established $93 million of valuation allowances and Virginia Power had no valuation allowances.
ACCOUNTING FOR DERIVATIVE CONTRACTS AND OTHER INSTRUMENTS AT FAIR
VALUE
Dominion and Virginia Power use derivative contracts such as futures, swaps, forwards, options and FTRs to manage
commodity and financial market risks of their business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities
are complex and may be subject to further clarification by standard-setting bodies. The majority of investments held in Dominions and Virginia Powers nuclear decommissioning and Dominions rabbi and benefit plan trust funds are also
subject to fair value accounting. See Notes 6 and 21 to the Consolidated Financial Statements for further information on these fair value measurements.
Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker
quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, the Companies consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an
active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable
pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, the Companies must estimate prices based on available historical and near-term future price information and use of
statistical methods, including regression analysis, that reflect their market assumptions.
The Companies maximize the use of observable inputs and minimize the use of unobservable
inputs when measuring fair value.
USE OF ESTIMATES IN GOODWILL
IMPAIRMENT TESTING
As of December 31, 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 2012, 2011 and 2010 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 Dominions Appalachian E&P operations and Peoples and Hope operations, negotiated sales prices were used as fair value for the tests conducted in 2010. Fair
value estimates are dependent on subjective factors such as Dominions 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 Dominions estimates of future cash flows, could result in a future impairment of goodwill.
Although Dominion has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at
the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair values would have still been
greater than the carrying values of each of those reporting units tested, indicating that no impairment was present. See Note 11 to the Consolidated Financial Statements for additional information.
USE OF ESTIMATES IN LONG-LIVED ASSET
IMPAIRMENT TESTING
Impairment testing for an individual or group of long-lived assets or for intangible
assets with definite lives is required when circumstances indicate those assets may be impaired. When an assets carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to
the extent that the assets 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
Managements 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, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. See Note 6 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets.
EMPLOYEE BENEFIT PLANS
Dominion sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing
benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate
of return on plan assets, discount rates applied to benefit obligations 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 Dominions 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:
|
|
Expected inflation and risk-free interest rate assumptions; |
|
|
Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;
|
|
|
Expected future risk premiums, asset volatilities and correlations; |
|
|
Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; and
|
|
|
Investment allocation of plan assets. The strategic target asset allocation for Dominions 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 Dominions 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 Dominions assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans actual
asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future
asset/
liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns.
Dominion develops assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An
internal committee selects the final assumptions. Dominion calculated its pension cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2012, 2011 and 2010. Dominion calculated its other postretirement benefit cost
using an expected long-term rate of return on plan assets assumption of 7.75% for 2012, 2011 and 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. Dominion
selected a discount rate of 4.40% for determining its December 31, 2012 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. Dominions healthcare cost trend rate assumption as of December 31, 2012 was 7% and is expected to gradually decrease to 4.60% by 2061 and continue at that rate for years thereafter.
The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed, while holding all
other assumptions constant:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in Net Periodic Cost |
|
|
|
Change in Actuarial Assumption |
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
(0.25 |
)% |
|
$ |
17 |
|
|
$ |
4 |
|
Long-term rate of return on plan assets |
|
|
(0.25 |
)% |
|
|
13 |
|
|
|
3 |
|
Healthcare cost trend rate |
|
|
1 |
% |
|
|
N/A |
|
|
|
17 |
|
In addition to the effects on cost, at December 31, 2012, a 0.25% decrease in the discount rate would
increase Dominions projected pension benefit obligation by $219 million and its accumulated postretirement benefit obligation by $54 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated
postretirement benefit obligation by $218 million. See Note 21 to the Consolidated Financial Statements for additional information.
REVENUE RECOGNITIONUNBILLED REVENUE
Virginia Power recognizes and records revenues when energy is delivered to the customer. The determination of sales to individual customers is based on
the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, the amount of electric energy delivered to customers, but not yet billed, is estimated and recorded as unbilled revenue. This
estimate is reversed in the following month and actual revenue is recorded based on meter readings. Virginia
Powers customer receivables included $348 million and $360 million of accrued unbilled revenue at December 31, 2012 and 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 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 Powers results of operations and financial condition.
DOMINION
RESULTS OF OPERATIONS
Presented below is a
summary of Dominions consolidated results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
$ Change |
|
|
2011 |
|
|
$ Change |
|
|
2010 |
|
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income attributable to Dominion |
|
$ |
302 |
|
|
$ |
(1,106 |
) |
|
$ |
1,408 |
|
|
$ |
(1,400 |
) |
|
$ |
2,808 |
|
Diluted EPS |
|
|
0.53 |
|
|
|
(1.92 |
) |
|
|
2.45 |
|
|
|
(2.31 |
) |
|
|
4.76 |
|
Overview
2012
VS. 2011
Net income attributable to Dominion decreased by 79%. Unfavorable drivers include impairment and other charges
related to bids received for Brayton Point and Kincaid and managements 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.
2011
VS. 2010
Net income attributable to Dominion decreased by 50%. Unfavorable drivers include the absence of a gain on the
sale of Dominions Appalachian E&P operations, lower margins from merchant generation operations, and the impact of less favorable weather, including Hurricane Irene, on electric utility operations. Favorable drivers include the absence of
charges related to a workforce reduction program and the absence of a loss on the sale of Peoples, and higher earnings from rate adjustment clauses.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominions results of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
$ Change |
|
|
2011 |
|
|
$ Change |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue |
|
$ |
13,093 |
|
|
$ |
(1,052 |
) |
|
$ |
14,145 |
|
|
$ |
(782 |
) |
|
$ |
14,927 |
|
Electric fuel and other energy-related purchases |
|
|
3,748 |
|
|
|
(349 |
) |
|
|
4,097 |
|
|
|
63 |
|
|
|
4,034 |
|
Purchased electric capacity |
|
|
387 |
|
|
|
(67 |
) |
|
|
454 |
|
|
|
1 |
|
|
|
453 |
|
Purchased gas |
|
|
1,177 |
|
|
|
(587 |
) |
|
|
1,764 |
|
|
|
(285 |
) |
|
|
2,049 |
|
Net Revenue |
|
|
7,781 |
|
|
|
(49 |
) |
|
|
7,830 |
|
|
|
(561 |
) |
|
|
8,391 |
|
Other operations and maintenance |
|
|
4,868 |
|
|
|
1,546 |
|
|
|
3,322 |
|
|
|
(126 |
) |
|
|
3,448 |
|
Depreciation, depletion and amortization |
|
|
1,186 |
|
|
|
120 |
|
|
|
1,066 |
|
|
|
31 |
|
|
|
1,035 |
|
Other taxes |
|
|
571 |
|
|
|
23 |
|
|
|
548 |
|
|
|
24 |
|
|
|
524 |
|
Gain on sale of Appalachian E&P operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,467 |
) |
|
|
2,467 |
|
Other income |
|
|
223 |
|
|
|
45 |
|
|
|
178 |
|
|
|
8 |
|
|
|
170 |
|
Interest and related charges |
|
|
882 |
|
|
|
15 |
|
|
|
867 |
|
|
|
41 |
|
|
|
826 |
|
Income tax expense |
|
|
146 |
|
|
|
(608 |
) |
|
|
754 |
|
|
|
(1,358 |
) |
|
|
2,112 |
|
Loss from discontinued operations |
|
|
(22 |
) |
|
|
3 |
|
|
|
(25 |
) |
|
|
233 |
|
|
|
(258 |
) |
An analysis of Dominions results of operations follows:
2012 VS. 2011
Net Revenue decreased 1%, primarily reflecting:
|
|
A $161 million decrease from merchant generation operations, primarily reflecting a decrease in realized prices; and |
|
|
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:
|
|
A $184 million increase from electric utility operations, primarily reflecting: |
|
|
|
The impact of rate adjustment clauses ($138 million); |
|
|
|
The absence of a charge recorded in 2011 based on the Biennial Review Order to refund revenues to customers ($81 million); and
|
|
|
|
A decrease in net capacity expenses ($31 million); partially offset by |
|
|
|
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); |
|
|
A $57 million increase in retail energy marketing activities primarily due to price risk management activities; and |
|
|
A $6 million increase from regulated natural gas transmission operations, primarily due to new transportation assets placed in service.
|
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
Other operations and
maintenance increased 47%, primarily reflecting:
|
|
A $1.6 billion impairment charge due to bids received for Brayton Point and Kincaid; |
|
|
A $415 million impairment charge due to managements decision to cease operations and begin decommissioning Kewaunee in 2013; and
|
|
|
A $107 million increase in salaries, wages and benefits. |
These increases were partially offset by:
|
|
The absence of an impairment charge recorded in 2011 related to certain utility coal-fired generating units ($228 million);
|
|
|
A $117 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These
expenses are recovered through rates and do not impact net income; and |
|
|
The absence of restoration costs recorded in 2011 associated with damages caused by Hurricane Irene ($96 million). |
Depreciation, depletion and amortization increased 11%, primarily due to property additions.
Other Income increased 25%, primarily due to higher realized gains (including investment income) on nuclear decommissioning trust funds.
Income tax expense
decreased 81%, primarily reflecting lower pre-tax income in 2012.
2011 VS. 2010
Net Revenue decreased 7%, primarily
reflecting:
|
|
A $504 million decrease from merchant generation operations, primarily due to a decrease in realized prices ($340 million) and lower generation ($153
million); and |
|
|
A $125 million decrease reflecting the sale of substantially all of Dominions Appalachian E&P operations in April 2010.
|
These decreases were partially offset by:
|
|
A $32 million increase from Dominions gas transmission business primarily related to an increase in revenue from NGLs;
|
|
|
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; |
|
|
A $13 million increase from electric utility operations, primarily reflecting: |
|
|
|
The impact of rate adjustment clauses ($169 million); and |
|
|
|
A decrease in net capacity expenses ($44 million); partially offset by |
|
|
|
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 |
|
|
|
A decrease due to a charge based on the Biennial Review Order to refund revenues to customers ($81 million). |
Other operations and maintenance decreased 4% primarily reflecting:
|
|
A $434 million decrease in salaries, wages and benefits primarily related to a 2010 workforce reduction program; partially offset by
|
|
|
A $228 million impairment charge related to certain utility coal-fired generating units; and |
|
|
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 the Consolidated Financial Statements.
Interest and related charges increased 5%, primarily due to the absence of a benefit
recorded in 2010 resulting from the discontinuance of hedge accounting for certain interest rate derivatives ($73 million) and an increase in debt issuances in 2011 ($18 million), partially offset by the recognition of hedging gains that had
previously been deferred as regulatory liabilities as a result of the Biennial Review Order ($50 million).
Income tax expense decreased 64%, primarily reflecting lower federal and state taxes largely due to the absence of a gain from the sale of
Dominions Appalachian E&P operations recorded in 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
Dominions 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 Dominions 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 on a per share basis as compared to 2012. Dominions anticipated 2013 results reflect the following significant factors:
|
|
The absence of impairment charges incurred in 2012 associated with certain merchant generating facilities; |
|
|
A return to normal weather in its electric utility operations; |
|
|
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 |
|
|
Growth in weather-normalized electric utility sales of approximately 2% resulting from the recovering economy and rising energy demand; partially
offset by |
|
|
An increase in interest expense; |
|
|
Increases in certain operations and maintenance expense; and |
|
|
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 Statements. Dominion expects the bonus depreciation provisions to reduce income taxes otherwise payable, resulting in cash savings in 2013 and 2014 of approximately $250 million and $350 million, respectively.
SEGMENT RESULTS OF OPERATIONS
Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. Presented below is a summary of contributions by Dominions operating
segments to net income attributable to Dominion:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
|
|
Net
Income attributable to Dominion |
|
|
Diluted EPS |
|
|
Net
Income attributable to Dominion |
|
|
Diluted EPS |
|
|
Net
Income attributable to Dominion |
|
|
Diluted EPS |
|
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DVP |
|
$ |
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 DVPs 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 key factors impacting DVPs net income contribution:
2012 VS. 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.
|
2011 VS. 2010
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
|
Amount |
|
|
EPS |
|
(millions, except EPS) |
|
|
|
|
|
|
Regulated electric sales: |
|
|
|
|
|
|
|
|
Weather |
|
$ |
(43 |
) |
|
$ |
(0.07 |
) |
Other |
|
|
10 |
|
|
|
0.02 |
|
FERC transmission equity return |
|
|
44 |
|
|
|
0.07 |
|
Retail energy marketing operations |
|
|
6 |
|
|
|
0.01 |
|
Storm damage and service restoration(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 Dominion Generations 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 Dominions 50% interest in Elwood. |
Presented below, on an after-tax basis, are the
key factors impacting Dominion Generations net income contribution:
2012 VS. 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 Points, Kincaids and Elwoods third and fourth quarter 2012 results of operations have been reflected in the Corporate and Other segment due
to Dominions decision, in the third quarter of 2012, to pursue the sale of Brayton Point, Kincaid, and its 50% interest in Elwood.
|
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
2011 VS. 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) |
Kewaunees 2011 results of operations have been reflected in the Corporate and Other segment due to Dominions 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 Energys 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 Energys net income contribution:
2012 VS. 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.
|
2011 VS. 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 segments 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 Dominions 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
RESULTS OF
OPERATIONS
Presented below is a summary of Virginia Powers consolidated results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
$ Change |
|
|
2011 |
|
|
$ Change |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
1,050 |
|
|
$ |
228 |
|
|
$ |
822 |
|
|
$ |
(30 |
) |
|
$ |
852 |
|
Overview
2012
VS. 2011
Net income increased by 28%. Favorable drivers include the absence of an impairment charge related to certain
coal-fired
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.
2011
VS. 2010
Net income decreased by 4%, primarily reflecting less favorable weather, including Hurricane Irene, and an
impairment charge related to certain coal-fired power stations, partially offset by higher earnings from rate adjustment clauses and the absence of charges related to a workforce reduction program.
Analysis of Consolidated Operations
Presented
below are selected amounts related to Virginia Powers 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 Powers results of operations follows:
2012 VS. 2011
Net Revenue increased 4%, primarily reflecting:
|
|
The impact of rate adjustment clauses ($138 million); |
|
|
The absence of a charge recorded in 2011 based on the Biennial Review Order to refund revenues to customers ($81 million); and
|
|
|
A decrease in net capacity expenses ($31 million); partially offset by |
|
|
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:
|
|
The absence of an impairment charge recorded in 2011 related to certain coal-fired generating units ($228 million); and |
|
|
The absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene ($96 million); partially offset by
|
|
|
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.
2011 VS.
2010
Net Revenue
increased $13 million, primarily reflecting:
|
|
The impact of rate adjustment clauses ($169 million); and |
|
|
A decrease in net capacity expenses ($44 million); partially offset by |
|
|
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 |
|
|
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:
|
|
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 |
|
|
A $54 million decrease in planned outage costs primarily due to fewer scheduled outage days at certain generation facilities; partially offset by
|
|
|
A $228 million impairment charge related to certain coal-fired generating units; and |
|
|
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 Powers anticipated 2013 results reflect the following significant factors:
|
|
A return to normal weather; |
|
|
Growth in weather-normalized electric sales of approximately 2% resulting from the recovering economy and rising energy demand; and
|
|
|
Construction and operation of growth projects and associated rate adjustment clause revenue; partially offset by |
|
|
Increases in certain operations and maintenance expense; and |
|
|
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
Managements 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 RESULTS OF OPERATIONS
Presented below is a summary of contributions by Virginia Powers operating segments to net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Powers DVP segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
% Change |
|
|
2011 |
|
|
% Change |
|
|
2010 |
|
Electricity delivered (million MWh) |
|
|
80.8 |
|
|
|
(2 |
)% |
|
|
82.3 |
|
|
|
(3 |
)% |
|
|
84.5 |
|
Degree days (electric service area): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
(1) |
Thirteen-month average. |
Presented below, on an after-tax basis, are the key factors impacting DVPs net income contribution:
2012 VS. 2011
|
|
|
|
|
|
|
Increase (Decrease) |
|
(millions, except EPS) |
|
|
|
Regulated electric sales: |
|
|
|
|
Weather |
|
$ |
(34 |
) |
Other |
|
|
28 |
|
FERC transmission equity return |
|
|
19 |
|
Storm damage and service restoration(1) |
|
|
14 |
|
Other |
|
|
(5 |
) |
Change in net income contribution |
|
$ |
22 |
|
(1) |
Excludes restoration costs associated with damage caused by severe storms in 2012 and 2011, which are reflected in the Corporate and Other segment.
|
2011 VS. 2010
|
|
|
|
|
|
|
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) |
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 Virginia Powers Dominion Generation segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
% Change |
|
|
2011 |
|
|
% Change |
|
|
2010 |
|
Electricity supplied (million MWh) |
|
|
80.8 |
|
|
|
(2 |
)% |
|
|
82.3 |
|
|
|
(3 |
)% |
|
|
84.5 |
|
Degree days (electric service area): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cooling |
|
|
1,787 |
|
|
|
(6 |
) |
|
|
1,899 |
|
|
|
(9 |
) |
|
|
2,090 |
|
Heating |
|
|
2,955 |
|
|
|
(12 |
) |
|
|
3,354 |
|
|
|
(12 |
) |
|
|
3,819 |
|
Presented below, on an after-tax basis, are the key factors impacting Dominion Generations net
income contribution:
2012 VS. 2011
|
|
|
|
|
|
|
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 |
) |
2011 VS. 2010
|
|
|
|
|
|
|
Increase (Decrease) |
|
(millions) |
|
|
|
Regulated electric sales: |
|
|
|
|
Weather |
|
$ |
(91 |
) |
Other |
|
|
59 |
|
Rate adjustment clause equity return |
|
|
30 |
|
Outage costs |
|
|
33 |
|
Other |
|
|
3 |
|
Change in net income contribution |
|
$ |
34 |
|
Corporate and Other
Presented below are the Corporate and Other segments after-tax results:
|
|
|
|
|
|
|
|
|
|
|
|
|
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 ATTRIBUTABLE TO OPERATING
SEGMENTS
Corporate and Other primarily includes specific items attributable to Virginia Powers 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 a discussion of
these items.
SELECTED INFORMATIONENERGY 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 Dominions 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 Dominions
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 |
|
|
20142015 |
|
|
20162017 |
|
|
2018 and thereafter |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices actively quotedLevel 1(1) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Prices provided by other external sourcesLevel
2(2) |
|
|
59 |
|
|
|
26 |
|
|
|
2 |
|
|
|
|
|
|
|
87 |
|
Prices based on models and other valuation methodsLevel 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. |
LIQUIDITY AND CAPITAL RESOURCES
Dominion and Virginia Power depend on both internal and external sources of liquidity to provide working capital and as a bridge to long-term debt
financings. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.
At December 31, 2012, Dominion had $1.1 billion of unused capacity under its credit facilities, including $256 million of unused
capacity under joint credit facilities available to Virginia Power. See additional discussion under Credit 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
Dominions liquidity.
A summary of Dominions cash flows is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
$ |
102 |
|
|
$ |
62 |
|
|
$ |
50 |
|
Cash flows provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
|
4,137 |
|
|
|
2,983 |
|
|
|
1,825 |
|
Investing activities |
|
|
(3,840 |
) |
|
|
(3,321 |
) |
|
|
419 |
|
Financing activities |
|
|
(151 |
) |
|
|
378 |
|
|
|
(2,232 |
) |
Net increase in cash and cash equivalents |
|
|
146 |
|
|
|
40 |
|
|
|
12 |
|
Cash and cash equivalents at end of year |
|
$ |
248 |
|
|
$ |
102 |
|
|
$ |
62 |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
A summary of Virginia Powers cash flows is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
$ |
29 |
|
|
$ |
5 |
|
|
$ |
19 |
|
Cash flows provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
|
2,706 |
|
|
|
2,024 |
|
|
|
1,409 |
|
Investing activities |
|
|
(2,282 |
) |
|
|
(1,947 |
) |
|
|
(2,425 |
) |
Financing activities |
|
|
(425 |
) |
|
|
(53 |
) |
|
|
1,002 |
|
Net increase (decrease) in cash and cash equivalents |
|
|
(1 |
) |
|
|
24 |
|
|
|
(14 |
) |
Cash and cash equivalents at end of year |
|
$ |
28 |
|
|
$ |
29 |
|
|
$ |
5 |
|
Operating Cash Flows
In 2012, net cash provided by Dominions operating activities increased by approximately $1.2 billion, primarily due to higher deferred fuel cost
recoveries in its Virginia jurisdiction, lower margin collateral requirements, changes in other working capital items and income tax refunds in 2012 as compared to income tax payments in 2011. The increase was partially offset by lower merchant
generation margins and the impact of less favorable weather.
In 2012, net cash provided by Virginia Powers operating
activities increased by $682 million, primarily due to higher deferred fuel cost recoveries in its Virginia jurisdiction and net changes in other working capital items, partially offset by income tax payments in 2012 as compared to income tax
refunds in 2011 and the impact of 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 2012, Dominions Board of Directors adopted a new dividend policy that raised its target payout ratio to 65-70%, and
established an annual dividend rate for 2013 of $2.25 per share of common stock, a 6.6% increase over the 2012 rate. Declarations of dividends are subject to 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
Dominions exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominions credit
exposure as of December 31, 2012 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting
rights.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Credit Exposure |
|
|
Credit Collateral |
|
|
Net Credit Exposure |
|
(millions) |
|
|
|
|
|
|
|
|
|
Investment grade(1) |
|
$ |
281 |
|
|
$ |
|
|
|
$ |
281 |
|
Non-investment grade(2) |
|
|
4 |
|
|
|
|
|
|
|
4 |
|
No external ratings: |
|
|
|
|
|
|
|
|
|
|
|
|
Internally rated-investment grade(3) |
|
|
113 |
|
|
|
|
|
|
|
113 |
|
Internally rated-non-investment grade(4) |
|
|
114 |
|
|
|
|
|
|
|
114 |
|
Total |
|
$ |
512 |
|
|
$ |
|
|
|
$ |
512 |
|
(1) |
Designations as investment grade are based upon minimum credit ratings assigned by Moodys and Standard & Poors. The five largest counterparty
exposures, combined, for this category represented approximately 28% of the total net credit exposure. |
(2) |
The five largest counterparty exposures, combined, for this category represented approximately 1% of the total net credit exposure. |
(3) |
The five largest counterparty exposures, combined, for this category represented approximately 13% of the total net credit exposure. |
(4) |
The five largest counterparty exposures, combined, for this category represented approximately 15% of the total net credit exposure. |
Virginia Powers exposure to potential concentrations of credit risk results primarily from sales to wholesale customers and was not
considered material at December 31, 2012.
Investing Cash Flows
In 2012, net cash used in Dominions investing activities increased 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 from the sale of assets, primarily related to Blue Racer, in 2012.
In 2012, net cash used in Virginia Powers investing activities increased by $335 million, primarily due to higher capital
expenditures and lower restricted cash reimbursements for the purpose of funding certain qualifying 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 in Credit 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
registra-
tion statements to register any offering of securities, other than those for exchange offers or business combination transactions.
In 2012, net cash used in Dominions financing activities was $151 million as compared to net cash provided by financing activities
of $378 million in 2011, primarily reflecting lower net debt issuances in 2012 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 2011.
In 2012, net cash used in Virginia Powers financing activities increased by $372 million, primarily reflecting lower net debt
issuances in 2012 as compared to 2011 as a result of higher cash flow from operations.
CREDIT FACILITIES
AND 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, Dominions credit ratings and the credit quality of its counterparties.
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.
Dominion
Commercial paper and letters of
credit outstanding, as well as capacity available under credit facilities, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
Effective September 2012, the maturity date was extended from September 2016 to September 2017. This credit facility can be used to support bank borrowings and the
issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit. |
(2) |
Effective September 2012, the maturity date for $400 million of the $500 million in committed capacity of this credit facility was extended from September 2016 to
September 2017. The remaining $100 million continues to have a maturity date of September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. |
(3) |
The weighted-average interest rate of the outstanding commercial paper supported by Dominions credit facilities was 0.49% at December 31, 2012.
|
Virginia Power
Virginia Powers short-term financing is supported by two 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 Powers 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
Effective September 2012, the maturity date was extended from September 2016 to September 2017. This credit facility can be used to support bank borrowings and the
issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Powers current sub-limit under this credit facility can be increased or decreased multiple times per
year. |
(2) |
Effective September 2012, the maturity date for $400 million of the $500 million in committed capacity of this credit facility was extended from September 2016 to
September 2017. The remaining $100 million continues to have a maturity date of September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Powers current sub-limit
under this credit facility can be increased or decreased multiple times per year. |
(3) |
The weighted-average interest rate of the outstanding commercial paper supported by these credit facilities was 0.47% at December 31, 2012.
|
In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million
credit facility. Effective September 2012, the maturity date was extended from September 2016 to September 2017. This facility 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-TERM DEBT
During 2012, Dominion and Virginia Power issued the following long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type |
|
Principal |
|
|
Rate |
|
|
Maturity |
|
|
Issuing
Company |
|
|
|
(millions) |
|
|
|
|
|
|
|
|
|
|
Senior notes |
|
$ |
350 |
|
|
|
1.40 |
% |
|
|
2017 |
|
|
|
Dominion |
|
Senior notes |
|
|
350 |
|
|
|
2.75 |
% |
|
|
2022 |
|
|
|
Dominion |
|
Senior notes |
|
|
350 |
|
|
|
4.05 |
% |
|
|
2042 |
|
|
|
Dominion |
|
Senior notes |
|
|
450 |
|
|
|
2.95 |
% |
|
|
2022 |
|
|
|
Virginia Power |
|
Total notes issued |
|
$ |
1,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
In December 2011, Virginia Power borrowed $75 million in connection with the Economic Development
Authority of the County of Chesterfield Pollution Control Refunding Revenue
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
Bonds, Series 2011 A, which mature in 2017 and bear interest during the initial period at a variable rate 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 were used to refund the principal amount of the Industrial Development Authority of the County of Chesterfield, Virginia Money Market MunicipalsTM Pollution Control Revenue Bonds, Series 1987 A and Series 1987 B
that would otherwise have matured in June 2017.
During 2012, Dominion and Virginia Power repaid and repurchased $1.7 billion
and $641 million, respectively, of long-term debt.
ISSUANCE OF COMMON STOCK
Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominions 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 2012, Dominion issued approximately 6.4 million shares of common stock through various programs. Dominion received cash proceeds of $265 million from the issuance of 5.3 million of such shares
through Dominion Direct, employee savings plans, and the exercise of employee stock options.
In January 2012, Dominion filed 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 issue common stock in 2012.
In 2012, Virginia Power did not issue any shares of its common stock to Dominion.
REPURCHASE OF COMMON STOCK
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.
BORROWINGS FROM PARENT
Virginia Power has the ability to borrow funds from Dominion under both short-term and long-term borrowing arrangements. Virginia Powers short-term demand note borrowings from Dominion were $243
million at December 31, 2012. There were no long-term borrowings from Dominion at December 31, 2012. At December 31, 2012, Virginia Powers nonregulated subsidiaries had outstanding borrowings, net of repayments, under the Dominion
money pool of $192 million.
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. Dominions and Virginia Powers 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 companys 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 affected by each companys 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.
Credit ratings as of February 22, 2013 follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fitch |
|
|
Moodys |
|
|
Standard
& Poors |
|
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 22, 2013, Fitch, Moodys and Standard & Poors maintained a stable
outlook for their respective ratings of Dominion and Virginia Power.
A downgrade in an individual companys 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,
Moodys and Standard & Poors with the objective of maintaining their current credit ratings. The 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
each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion and Virginia Power.
Some of the typical covenants include:
|
|
The timely payment of principal and interest; |
|
|
Information requirements, including submitting financial reports filed with the SEC and information about changes in Dominions and Virginia
Powers credit ratings to lenders; |
|
|
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; |
|
|
Compliance with collateral minimums or requirements related to mortgage bonds; and |
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, 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) |
|
Dominion |
|
|
65 |
% |
|
|
60 |
% |
Virginia Power |
|
|
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 companys 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:
|
|
September 2006 hybrids; and |
See Note 17 to the Consolidated Financial Statements for terms of the RCCs.
At
December 31, 2012, the termination dates and covered debt under the RCCs associated with Dominions hybrids were as follows:
|
|
|
|
|
|
|
|
|
Hybrid |
|
RCC
Termination Date |
|
|
Designated Covered
Debt Under RCC |
|
June 2006 hybrids |
|
|
6/30/2036 |
|
|
|
September 2006 hybrids |
|
September 2006 hybrids |
|
|
9/30/2036 |
|
|
|
June 2006 hybrids |
|
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, 2012, there have been no events of default under or changes to Dominions or Virginia Powers debt covenants.
Virginia Power Mortgage Supplement
Substantially
all of Virginia Powers 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 Powers 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, 2012, the Virginia Commission had not restricted the payment of dividends by Virginia Power.
Certain agreements associated with Dominions and Virginia Powers credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict
Dominion or Virginia Powers ability to pay dividends or receive dividends from their subsidiaries at December 31, 2012.
See Note 17 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior
subordinated notes, 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, 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
Managements 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 Dominions and Virginia Powers current liabilities will be paid in cash in 2013.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 instruments stated maturity. See Note 17 to the Consolidated Financial Statements. Does not reflect Dominions 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 12, 14 and 21 to
the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $233 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded
since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 5 to the Consolidated Financial Statements. |
(8) |
Includes interest rate swap agreements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
(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 instruments stated maturity. See Note 17 to the Consolidated Financial Statements. |
(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) |
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 12, 14 and 21 to
the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $57 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded
since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 5 to the Consolidated Financial Statements. |
PLANNED CAPITAL EXPENDITURES
Dominions
planned capital expenditures are expected to total approximately $4.7 billion, $4.2 billion and $3.3 billion in 2013, 2014 and 2015, respectively. Dominions expenditures are expected to include construction and expansion of electric generation
and natural gas transmission and storage facilities, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel and the buyout of the lease at Fairless in 2013.
Virginia Powers planned capital expenditures are expected to total approximately $2.6 billion, $3.0 billion and $2.3 billion in
2013, 2014 and 2015, respectively. Virginia Powers expenditures are expected to include construction and expansion of electric generation facilities, 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 companys 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. See DVP, Dominion Generation and Dominion Energy-Properties in Item 1. Business for a discussion of Dominions and Virginia Powers expansion plans.
These estimates are based on a capital expenditures plan reviewed and endorsed by Dominions Board of Directors in late
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 guarantors accounting and disclosure requirements for guarantees,
including indirect guarantees of indebtedness of others. See Note 22 to the Consolidated Financial Statements for additional information, which information is incorporated herein by reference.
FUTURE ISSUES AND OTHER MATTERS
See Item 1. Business, Item 3. Legal Proceedings, and Notes 13 and 22 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other
matters that may impact future results of operations, financial condition, and/or cash flows.
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 PROTECTION AND MONITORING EXPENDITURES
Dominion incurred approximately $189 million, $184 million and $228 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 $193 million and $181 million in 2013 and 2014, respectively. In addition, capital expenditures related to
environmental controls were $213 million, $403 million, and $351 million for 2012, 2011 and 2010, respectively. These expenditures are expected to be approximately $75 million and $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 nations 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 Dominions and Virginia Powers facilities are subject to the CAAs 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 Dominions or Virginia Powers 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 Dominions or Virginia Powers 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 Dominions results of operations, and Dominions and Virginia Powers 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
Managements 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 cannot 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 benefit studies. However, the impacts of this 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 Dominions and Virginia Powers 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 their Final Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the
Clean Air Act, finding that GHGs endanger
both the public health and the public welfare of current and future generations. On April 1, 2010, the EPA and the Department of Transportations 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 the Final Prevention of Significant
Deterioration and Title V Greenhouse Gas Tailoring Rule that, combined with prior actions, 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. 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 finalized in the Spring of 2013, covers
CO2 only and does not apply to existing sources. New natural
gas combined cycle units, including Brunswick County, are expected to be able 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 a final rulemaking
governing a GHG NSPS for existing sources is uncertain.
There are other legislative proposals that 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 operate
have already adopted or may adopt GHG emission reduction programs. Any of these new or contemplated regulations may affect capital costs, or create significant permitting delays, for new or modified facilities that emit GHGs.
In July 2008, Massachusetts passed the GWSA. 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 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 established a process to develop a regional framework by 2011 and examine 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 established.
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 choose to exempt their hedging
transactions from these clearing and exchange trading requirements. Final rules for the over-the-counter derivative-related provisions of the Dodd-Frank Act will continue to be established through the ongoing rulemaking process of the applicable
regulators. If, as a result of the rulemaking process, Dominions or Virginia Powers derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs,
including from higher margin requirements, for their derivative activities. In addition, implementation of, and compliance with, the 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 Acts 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
Points 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 Points 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
Points 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
utilitys 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 utilitys 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 utilitys 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
Powers 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-
Managements 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 readers 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 INSTRUMENTS AND RISK MANAGEMENT
Dominions and Virginia Powers 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 Dominions and Virginia Powers electric operations, Dominions gas procurement
operations, and Dominions 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 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 commodity prices of Dominions non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately
$128 million and $179 million as of December 31, 2012 and 2011, respectively. A hypothetical 10% unfavorable change in commodity prices of Dominions 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, 2012 and 2011, respectively.
A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of Virginia Powers non-trading commodity-based financial derivatives as of
December 31, 2012 or 2011.
The impact of a change in energy commodity prices on Dominions and Virginia
Powers 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 variable 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 as of December 31, 2012 or 2011.
Dominion and Virginia Power may also use forward-starting interest rate swaps and interest rate lock agreements as
anticipatory hedges. As of December 31, 2012, Dominion and Virginia Power had $1.8 billion and $750 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market
interest rates would have resulted in a decrease of approximately $21 million and $9 million, respectively, in the fair value of Dominions and Virginia Powers 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 outstanding. 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 Dominions and Virginia Powers interest rate derivatives at December 31, 2011.
The impact of a change in interest rates on Dominions and Virginia Powers interest rate-based financial derivative instruments at a point in time is not necessarily representative of the
results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will
generally be offset by recognition of the hedged transaction.
Investment Price Risk
Dominion and Virginia Power are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers.
These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value.
Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $126
million and $54 million in 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 2012 and 2011, Dominion recorded, in AOCI and
regulatory liabilities, a net increase in unrealized gains on these investments of $210 million and $52 million, respectively.
Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $53 million and
$24 million in 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 2012 and 2011, Virginia Power recorded, in AOCI and
regulatory liabilities, a net increase in unrealized gains on these investments of $89 million and $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 Dominions pension and other postretirement plan assets were $743 million in 2012
and $273 million in 2011, versus expected returns of $509 million and $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, 2012 and 2011, a hypothetical 0.25% decrease in the assumed long-term rates of return on Dominions 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 of all subsidiaries, including Virginia Power. Dominion maintains credit policies that
include the evaluation of a prospective counterpartys 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 Dominions and Virginia Powers December 31, 2012 provision for credit losses,
management believes that it is unlikely that a material adverse effect on Dominions or Virginia Powers financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
Item 8. Financial Statements and Supplementary Data
|
|
|
|
|
|
|
Page No. |
|
|
|
Dominion Resources, Inc. |
|
|
|
|
Report of Independent Registered Public Accounting Firm |
|
|
53 |
|
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010 |
|
|
54 |
|
Consolidated Statements of Comprehensive Income at December 31, 2012, 2011 and 2010 and for the years then
ended |
|
|
55 |
|
Consolidated Balance Sheets at December 31, 2012 and 2011 |
|
|
56 |
|
|
|
Consolidated Statements of Equity at December 31, 2012, 2011 and 2010 and for the years then
ended |
|
|
58 |
|
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010 |
|
|
59 |
|
|
|
Virginia Electric and Power Company |
|
|
|
|
Report of Independent Registered Public Accounting Firm |
|
|
60 |
|
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010 |
|
|
61 |
|
Consolidated Statements of Comprehensive Income at December
31, 2012, 2011 and 2010 and for the years then ended |
|
|
62 |
|
Consolidated Balance Sheets at December 31, 2012 and 2011 |
|
|
63 |
|
Consolidated Statements of Common Shareholders Equity at December
31, 2012, 2011 and 2010 and for the years then ended |
|
|
65 |
|
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010 |
|
|
66 |
|
|
|
Combined Notes to Consolidated Financial Statements |
|
|
67 |
|
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the
accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (Dominion) as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, equity, and cash flows for
each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of Dominions 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period
ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
We
have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Dominions internal control over financial reporting as of December 31, 2012, based on the criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2013 expressed an unqualified opinion on Dominions internal control over
financial reporting.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 2013
Dominion Resources, Inc.
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 Dominions Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Statements of Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Dominions Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
At December 31, |
|
2012 |
|
|
2011 |
|
(millions) |
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
248 |
|
|
$ |
102 |
|
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 |
|
|
684 |
|
|
|
641 |
|
Fossil fuel |
|
|
467 |
|
|
|
541 |
|
Gas stored |
|
|
108 |
|
|
|
166 |
|
Derivative assets |
|
|
518 |
|
|
|
705 |
|
Regulatory assets |
|
|
203 |
|
|
|
541 |
|
Prepayments |
|
|
326 |
|
|
|
262 |
|
Deferred income taxes |
|
|
573 |
|
|
|
9 |
|
Other |
|
|
296 |
|
|
|
428 |
|
Total current assets |
|
|
5,140 |
|
|
|
5,430 |
|
Investments |
|
|
|
|
|
|
|
|
Nuclear decommissioning trust funds |
|
|
3,330 |
|
|
|
2,999 |
|
Investment in equity method affiliates |
|
|
558 |
|
|
|
553 |
|
Restricted cash equivalents |
|
|
33 |
|
|
|
141 |
|
Other |
|
|
270 |
|
|
|
292 |
|
Total investments |
|
|
4,191 |
|
|
|
3,985 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
43,364 |
|
|
|
42,033 |
|
Property, plant and equipment, VIE |
|
|
957 |
|
|
|
957 |
|
Accumulated depreciation, depletion and amortization |
|
|
(13,548 |
) |
|
|
(13,320 |
) |
Total property, plant and equipment, net |
|
|
30,773 |
|
|
|
29,670 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Goodwill |
|
|
3,130 |
|
|
|
3,141 |
|
Pension and other postretirement benefit assets |
|
|
702 |
|
|
|
681 |
|
Intangible assets |
|
|
536 |
|
|
|
637 |
|
Regulatory assets |
|
|
1,717 |
|
|
|
1,382 |
|
Other |
|
|
649 |
|
|
|
688 |
|
Total deferred charges and other assets |
|
|
6,734 |
|
|
|
6,529 |
|
Total assets |
|
$ |
46,838 |
|
|
$ |
45,614 |
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
2012 |
|
|
2011 |
|
(millions) |
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Securities due within one year |
|
$ |
1,363 |
|
|
$ |
1,479 |
|
Securities due within one year, VIE |
|
|
860 |
|
|
|
|
|
Short-term debt |
|
|
2,412 |
|
|
|
1,814 |
|
Accounts payable |
|
|
1,137 |
|
|
|
1,250 |
|
Accrued interest, payroll and taxes |
|
|
636 |
|
|
|
648 |
|
Derivative liabilities |
|
|
510 |
|
|
|
951 |
|
Regulatory liabilities |
|
|
136 |
|
|
|
243 |
|
Other |
|
|
709 |
|
|
|
577 |
|
Total current liabilities |
|
|
7,763 |
|
|
|
6,962 |
|
Long-Term Debt |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
15,478 |
|
|
|
14,785 |
|
Long-term debt, VIE |
|
|
|
|
|
|
890 |
|
Junior subordinated notes |
|
|
1,373 |
|
|
|
1,719 |
|
Total long-term debt |
|
|
16,851 |
|
|
|
17,394 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes and investment tax credits |
|
|
5,800 |
|
|
|
5,216 |
|
Asset retirement obligations |
|
|
1,641 |
|
|
|
1,383 |
|
Pension and other postretirement benefit liabilities |
|
|
1,831 |
|
|
|
962 |
|
Regulatory liabilities |
|
|
1,514 |
|
|
|
1,324 |
|
Other |
|
|
556 |
|
|
|
613 |
|
Total deferred credits and other liabilities |
|
|
11,342 |
|
|
|
9,498 |
|
Total liabilities |
|
|
35,956 |
|
|
|
33,854 |
|
Commitments and Contingencies (see Note 22) |
|
|
|
|
|
|
|
|
Subsidiary Preferred Stock Not Subject To Mandatory Redemption |
|
|
257 |
|
|
|
257 |
|
Equity |
|
|
|
|
|
|
|
|
Common stock-no
par(1) |
|
|
5,493 |
|
|
|
5,180 |
|
Other paid-in capital |
|
|
162 |
|
|
|
179 |
|
Retained earnings |
|
|
5,790 |
|
|
|
6,697 |
|
Accumulated other comprehensive loss |
|
|
(877 |
) |
|
|
(610 |
) |
Total common shareholders equity |
|
|
10,568 |
|
|
|
11,446 |
|
Noncontrolling interest |
|
|
57 |
|
|
|
57 |
|
Total equity |
|
|
10,625 |
|
|
|
11,503 |
|
Total liabilities and equity |
|
$ |
46,838 |
|
|
$ |
45,614 |
|
(1) |
1 billion shares authorized; 576 million shares and 570 million shares outstanding at December 31, 2012 and 2011, respectively.
|
The accompanying notes are an integral part of Dominions Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Statements of Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
Dominion Shareholders |
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
Amount |
|
|
Other Paid-In Capital |
|
|
Retained Earnings |
|
|
Accumulated Other Comprehensive Income (Loss) |
|
|
Total Common Shareholders Equity |
|
|
Noncontrolling Interests |
|
|
Total Equity |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
599 |
|
|
$ |
6,525 |
|
|
$ |
185 |
|
|
$ |
4,686 |
|
|
$ |
(211 |
) |
|
$ |
11,185 |
|
|
$ |
|
|
|
$ |
11,185 |
|
Net income including noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,825 |
|
|
|
|
|
|
|
2,825 |
|
|
|
|
|
|
|
2,825 |
|
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 |
|
|
|
|
|
|
|
80 |
|
Stock repurchases |
|
|
(21 |
) |
|
|
(900 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(900 |
) |
|
|
|
|
|
|
(900 |
) |
Tax benefit from stock awards and stock options exercised |
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
9 |
|
Dividends(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,093 |
) |
|
|
|
|
|
|
(1,093 |
) |
|
|
|
|
|
|
(1,093 |
) |
Other comprehensive loss, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(119 |
) |
|
|
(119 |
) |
|
|
|
|
|
|
(119 |
) |
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 $16 million in 2012 and $17 million in 2011 and 2010. |
(2) |
See Note 15 for consolidation of a VIE in October 2011. |
(3) |
Contains shares issued in excess of principal amounts related to converted securities. See Note 17 for further information on convertible securities.
|
The accompanying notes are an integral part of Dominions Consolidated Financial Statements
Dominion Resources, Inc.
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
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 VIEassets at fair value |
|
|
|
|
|
|
957 |
|
|
|
|
|
Consolidation of VIEdebt |
|
|
|
|
|
|
896 |
|
|
|
|
|
The accompanying notes are an integral part of Dominions Consolidated Financial Statements.
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Virginia Electric and Power Company
Richmond, Virginia
We have audited the
accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (Virginia Power) as of December 31, 2012 and 2011, and the related consolidated
statements of income, comprehensive income, common shareholders equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of Virginia Powers
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 Powers 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, 2012
and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Richmond,
Virginia
February 27, 2013
Virginia Electric and Power Company
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue |
|
$ |
7,226 |
|
|
$ |
7,246 |
|
|
$ |
7,219 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
2,368 |
|
|
|
2,506 |
|
|
|
2,495 |
|
Purchased electric capacity |
|
|
386 |
|
|
|
452 |
|
|
|
449 |
|
Other operations and maintenance: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliated suppliers |
|
|
305 |
|
|
|
306 |
|
|
|
384 |
|
Other |
|
|
1,161 |
|
|
|
1,437 |
|
|
|
1,361 |
|
Depreciation and amortization |
|
|
782 |
|
|
|
718 |
|
|
|
671 |
|
Other taxes |
|
|
232 |
|
|
|
222 |
|
|
|
218 |
|
Total operating expenses |
|
|
5,234 |
|
|
|
5,641 |
|
|
|
5,578 |
|
Income from operations |
|
|
1,992 |
|
|
|
1,605 |
|
|
|
1,641 |
|
Other income |
|
|
96 |
|
|
|
88 |
|
|
|
100 |
|
Interest and related charges |
|
|
385 |
|
|
|
331 |
|
|
|
347 |
|
Income from operations before income tax expense |
|
|
1,703 |
|
|
|
1,362 |
|
|
|
1,394 |
|
Income tax expense |
|
|
653 |
|
|
|
540 |
|
|
|
542 |
|
Net Income |
|
|
1,050 |
|
|
|
822 |
|
|
|
852 |
|
Preferred dividends |
|
|
16 |
|
|
|
17 |
|
|
|
17 |
|
Balance available for common stock |
|
$ |
1,034 |
|
|
$ |
805 |
|
|
$ |
835 |
|
The accompanying notes are an integral part of Virginia Powers 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 Powers Consolidated Financial Statements.
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, |
|
2012 |
|
|
2011 |
|
(millions) |
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS 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 Shareholders 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 shareholders equity |
|
|
9,233 |
|
|
|
8,750 |
|
Total liabilities and shareholders 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 Powers Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Common Shareholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
Other Paid-In Capital |
|
|
Retained Earnings |
|
|
Accumulated Other Comprehensive Income
(Loss) |
|
|
Total |
|
|
|
Shares |
|
|
Amount |
|
|
|
|
|
(millions, except for shares) |
|
(thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 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 Powers Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Powers Consolidated Financial Statements.
Combined Notes to Consolidated Financial Statements
NOTE 1. NATURE OF OPERATIONS
Dominion, headquartered in Richmond, Virginia, is one of the nations largest producers and transporters of energy.
Dominions 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 Powers common stock is owned by Dominion. Dominions 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.
Dominions 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 operations that are expected to be and are currently discontinued, which is discussed in Note 3. In addition, Corporate and Other includes specific
items attributable to Dominions 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 25 for further discussion of Dominions and Virginia Powers 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 cash flows for the periods presented. Actual results may differ from those estimates.
Dominions and Virginia Powers Consolidated Financial Statements include, after eliminating intercompany transactions and
balances, the accounts of their respective majority-owned 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 6 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 21 for further information on these plans.
Certain amounts in the 2011 and
2010 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2012 presentation for comparative purposes. The reclassifications did not affect the Companies net income, total assets, liabilities, equity or cash
flows.
Amounts disclosed for Dominion are inclusive of Virginia Power, 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.
Dominions customer receivables at December 31, 2012 and 2011 included $411 million and $423 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet
billed to its utility customers. Virginia Powers customer receivables at December 31, 2012 and 2011 included $348 million and $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:
|
|
Regulated electric sales consist
primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; |
|
|
Nonregulated electric sales consist
primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity; |
|
|
Regulated gas sales consist primarily
of state-regulated retail natural gas sales and related distribution services; |
|
|
Nonregulated gas sales consist
primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity. Revenue from sales of gas production is
recognized based on actual volumes of gas sold to purchasers and is reported net of royalties; |
|
|
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 |
|
|
Other revenue consists primarily of
sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes miscellaneous service revenue from electric and gas distribution operations, and gas processing and handling revenue.
|
The primary types of sales and service activities reported as operating revenue for Virginia Power are as
follows:
|
|
Regulated electric sales consist
primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and |
|
|
Other revenue consists primarily of
miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.
|
Combined Notes to Consolidated Financial Statements, Continued
Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs
Where permitted by regulatory authorities, the differences between Virginia Powers actual electric fuel and purchased energy expenses and
Dominions 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 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. 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 of income taxes in interest expense. 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
2012, Dominion recognized interest income of $8 million and 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. Dominion had accrued interest receivable of $5 million, interest
payable of $10 million and penalties payable of less than $1 million at December 31, 2012 and interest receivable of $48 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2011.
Virginia Powers interest and penalties were immaterial in 2012 and 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, 2012, Virginia Powers Consolidated Balance Sheet included $10 million of federal income taxes payable and $36 million of noncurrent federal and state income taxes payable.
At December 31, 2011, Virginia Powers Consolidated Balance Sheet included $18 million of current federal
income taxes receivable, $34 million of current state income taxes payable and $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, 2012 and 2011, Dominions accounts payable included $53 million and $75 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 2012 and 2011, Virginia Powers
accounts payable included $30 million and $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.
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
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 $212 million and $319 million associated
with cash collateral at December 31, 2012 and 2011, respectively. Dominion had margin liabilities of $4 million and $66 million associated with cash collateral at December 31, 2012 and 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 Powers margin liabilities associated with cash collateral were not material at December 31, 2012 and 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 Dominions 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:
|
|
Derivatives Held for Trading Purposes:
All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis. |
|
|
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 Powers generation operations, changes in the fair value of derivative instruments
result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact
earnings.
DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING
INSTRUMENTS
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 relationship between the hedging instrument and the hedged item, as well as the risk management objective and the
strategy for using the hedging instrument. The Companies assess whether the
hedg-
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
HedgesA majority of Dominions and Virginia Powers 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 HedgesDominion also uses fair value hedges to mitigate the fixed
price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, Dominion and Virginia Power have designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate
exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged items fair value. Derivative gains and losses from the hedged item
are reclassified to earnings when the hedged item is included in earnings, or earlier, if the hedged item no longer qualifies for hedge accounting. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting.
See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7
for further information on derivatives.
Property, Plant and Equipment
Property, plant and equipment, 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 2012, 2011 and 2010, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $91 million, $85
million and $102 million, respectively. In 2012, 2011 and
Combined Notes to Consolidated Financial Statements, Continued
2010, Virginia Power capitalized AFUDC to property, plant and equipment of $31 million, $31 million and $61 million, respectively. Under Virginia law, certain Virginia jurisdictional projects
qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2012, 2011 and 2010, Virginia Power recorded
$37 million, $20 million and $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. 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 propertys 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. Dominions
and Virginia Powers depreciation rates on utility property, plant and equipment are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(percent) |
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
Generation |
|
|
2.62 |
|
|
|
2.68 |
|
|
|
2.59 |
|
Transmission |
|
|
2.17 |
|
|
|
2.26 |
|
|
|
2.24 |
|
Distribution |
|
|
3.17 |
|
|
|
3.19 |
|
|
|
3.20 |
|
Storage |
|
|
2.59 |
|
|
|
2.64 |
|
|
|
2.75 |
|
Gas gathering and processing |
|
|
2.49 |
|
|
|
2.52 |
|
|
|
2.39 |
|
General and other |
|
|
4.55 |
|
|
|
4.66 |
|
|
|
4.60 |
|
|
|
|
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
Generation |
|
|
2.62 |
|
|
|
2.68 |
|
|
|
2.59 |
|
Transmission |
|
|
1.98 |
|
|
|
2.03 |
|
|
|
1.94 |
|
Distribution |
|
|
3.32 |
|
|
|
3.33 |
|
|
|
3.33 |
|
General and other |
|
|
4.32 |
|
|
|
4.38 |
|
|
|
4.28 |
|
Dominions nonutility property, plant and equipment is depreciated using the straight-line method
over the following estimated useful lives:
|
|
|
|
|
Asset |
|
Estimated Useful Lives |
|
Merchant generationnuclear |
|
|
34 44 years |
|
Merchant generationother |
|
|
27 40 years |
|
General and other |
|
|
5 59 years |
|
Nuclear fuel used in electric generation is amortized over its estimated service life on a
units-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their
Consolidated Statements of Cash Flows.
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, Dominion no longer has any significant gas and oil properties subject to
the ceiling test calculation.
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 and recognized a gain
from the sale of substantially all of its Appalachian E&P operations, as discussed in Note 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. Compliance with the RGGI requirements only applies to certain of Dominions 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 Dominions and Virginia Powers 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 depreciation, 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.
Regulatory Assets and Liabilities
The accounting for Dominions regulated gas and Virginia Powers 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. Dominion reports accretion of AROs associated with its natural gas pipeline and storage well assets as an
adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Virginia Power reports accretion of AROs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability
for certain jurisdictions. 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 are deferred and amortized over the lives of the new issuances.
Investments
MARKETABLE
EQUITY AND DEBT SECURITIES
Dominion accounts for and classifies investments in
marketable equity and debt securities as trading or available-for-sale securities.
Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities.
|
|
Trading securities include marketable equity and debt securities held by Dominion in rabbi trusts associated with certain deferred compensation
plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.
|
|
|
Available-for-sale securities include all other marketable equity and debt securities, primarily comprised of securities held in the nuclear
decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on
investments held in Virginia Powers 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
Dominions merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI,
after-tax. |
In determining realized gains and losses for marketable equity and debt securities, the cost
basis of the security is based on the specific identification method.
NON-MARKETABLE
INVESTMENTS
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:
|
|
Equity method investments when Dominion and Virginia Power have the ability to exercise significant influence, but not control, over the
investee. Dominions investments are included in investments in equity method affiliates and Virginia Powers 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. |
|
|
Cost method investments when Dominion and Virginia Power do not have the ability to exercise significant influence over the investee.
Dominions and Virginia Powers investments are included in other investments and nuclear decommissioning trust funds.
|
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. If a decline in fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period.
Decommissioning Trust InvestmentsSpecial Considerations
|
|
The recognition provisions of the FASBs 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. |
|
|
Debt SecuritiesUsing information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion and Virginia
Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost
basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, 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. |
|
|
Equity securities and other investmentsDominions and Virginia Powers 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 East Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at $24 million and $48 million at December 31, 2012
and December 31, 2011, respectively. Based on the average price of gas purchased during 2012 and 2011, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $69 million and
$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. DISPOSITIONS
Sale of Salem Harbor and State Line
In August 2012, Dominion completed the sale of Salem Harbor. In the second quarter of 2012, the assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair
value less cost to sell. During the second quarter of 2012, Dominion completed the sale of State Line, which ceased operations in March 2012. See Note 6 for impairments related to these power stations.
The following table presents selected information regarding the results of operations of Salem Harbor and State Line, which are classified
in discontinued operations in Dominions Consolidated Statements of Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
57 |
|
|
$ |
233 |
|
|
$ |
269 |
|
Loss before income
taxes(1) |
|
|
(49 |
) |
|
|
(34 |
) |
|
|
(158 |
) |
(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 subsidiary of CONSOL for approximately $3.5 billion. The transaction included 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, recorded in the second quarter of 2010.
The results of
operations for Dominions 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.
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.
The following table presents selected information regarding the results
of operations of Peoples, which are reported as discontinued operations in Dominions Consolidated Statements of Income:
|
|
|
|
|
Year Ended December 31, |
|
2010 |
|
(millions) |
|
|
|
Operating revenue |
|
$ |
67 |
|
Loss before income taxes |
|
|
(134 |
)(1) |
(1) |
Includes a loss and other charges related to the sale of Peoples. |
NOTE 4. OPERATING REVENUE
Dominions and Virginia Powers operating revenue consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
Electric sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
|
$ |
7,102 |
|
|
$ |
7,114 |
|
|
$ |
7,123 |
|
Nonregulated |
|
|
2,742 |
|
|
|
3,100 |
|
|
|
3,559 |
|
Gas sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
|
|
250 |
|
|
|
287 |
|
|
|
308 |
|
Nonregulated |
|
|
1,071 |
|
|
|
1,635 |
|
|
|
2,010 |
|
Gas transportation and storage |
|
|
1,401 |
|
|
|
1,506 |
|
|
|
1,493 |
|
Other |
|
|
527 |
|
|
|
503 |
|
|
|
434 |
|
Total operating revenue |
|
$ |
13,093 |
|
|
$ |
14,145 |
|
|
$ |
14,927 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated electric sales |
|
$ |
7,102 |
|
|
$ |
7,114 |
|
|
$ |
7,123 |
|
Other |
|
|
124 |
|
|
|
132 |
|
|
|
96 |
|
Total operating revenue |
|
$ |
7,226 |
|
|
$ |
7,246 |
|
|
$ |
7,219 |
|
NOTE 5. INCOME TAXES
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and
liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. 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.
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.
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, in December 2012, in response to public comments received, the IRS amended the temporary regulations to postpone the effective date
until January 1, 2014.
Changes in tax treatment elected by Dominion or required by the regulations will impact income
taxes payable, cash flows from operations and deferred taxes. Except to the extent the implementation impacts deferred taxes and, therefore, the rate base used to establish customer rates for regulated utilities, results of 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(1)
|
|
|
Virginia
Power(2) |
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
(117 |
) |
|
$ |
3 |
|
|
$ |
894 |
|
|
$ |
70 |
|
|
$ |
(35 |
) |
|
$ |
(78 |
) |
State |
|
|
80 |
|
|
|
9 |
|
|
|
309 |
|
|
|
81 |
|
|
|
79 |
|
|
|
10 |
|
Total current expense (benefit) |
|
|
(37 |
) |
|
|
12 |
|
|
|
1,203 |
|
|
|
151 |
|
|
|
44 |
|
|
|
(68 |
) |
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
214 |
|
|
|
694 |
|
|
|
818 |
|
|
|
482 |
|
|
|
484 |
|
|
|
537 |
|
State |
|
|
(30 |
) |
|
|
50 |
|
|
|
93 |
|
|
|
21 |
|
|
|
13 |
|
|
|
74 |
|
Total deferred expense |
|
|
184 |
|
|
|
744 |
|
|
|
911 |
|
|
|
503 |
|
|
|
497 |
|
|
|
611 |
|
Amortization of deferred investment tax credits |
|
|
(1 |
) |
|
|
(2 |
) |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
Total income tax expense |
|
$ |
146 |
|
|
$ |
754 |
|
|
$ |
2,112 |
|
|
$ |
653 |
|
|
$ |
540 |
|
|
$ |
542 |
|
(1) |
In 2012, Dominions 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, Dominions 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 Powers 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 Powers 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.
|
Combined Notes to Consolidated Financial Statements, Continued
For continuing operations including noncontrolling interests, the statutory U.S. federal
income tax rate reconciles to Dominions and Virginia Powers effective income tax rate as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
Virginia Power |
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
U.S. statutory rate |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
Increases (reductions) resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State taxes, net of federal benefit |
|
|
8.1 |
|
|
|
1.8 |
|
|
|
5.1 |
|
|
|
3.9 |
|
|
|
4.4 |
|
|
|
3.8 |
|
Valuation allowances |
|
|
(1.5 |
) |
|
|
|
|
|
|
(0.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Production tax credits |
|
|
(2.4 |
) |
|
|
(0.6 |
) |
|
|
(0.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of investment tax credits |
|
|
(0.3 |
) |
|
|
(0.1 |
) |
|
|
|
|
|
|
(0.1 |
) |
|
|
(0.1 |
) |
|
|
(0.1 |
) |
AFUDCequity |
|
|
(4.1 |
) |
|
|
(0.6 |
) |
|
|
(0.4 |
) |
|
|
(0.9 |
) |
|
|
(0.8 |
) |
|
|
(1.1 |
) |
Employee stock ownership plan deduction |
|
|
(3.1 |
) |
|
|
(0.7 |
) |
|
|
(0.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill |
|
|
0.4 |
|
|
|
|
|
|
|
0.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Legislative change |
|
|
|
|
|
|
|
|
|
|
1.1 |
|
|
|
|
|
|
|
|
|
|
|
1.1 |
|
Other, net |
|
|
(2.8 |
) |
|
|
(0.6 |
) |
|
|
(0.2 |
) |
|
|
0.4 |
|
|
|
1.2 |
|
|
|
0.2 |
|
Effective tax rate |
|
|
29.3 |
% |
|
|
34.2 |
% |
|
|
40.7 |
% |
|
|
38.3 |
% |
|
|
39.7 |
% |
|
|
38.9 |
% |
Dominions 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
Dominions 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.
Dominions and Virginia Powers 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 employers 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, Dominions 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.
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 |
|
At December 31, |
|
2012 |
|
|
2011 |
|
|
2012 |
|
|
2011 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets |
|
$ |
2,505 |
|
|
$ |
2,229 |
|
|
$ |
466 |
|
|
$ |
503 |
|
Total deferred income tax liabilities |
|
|
7,716 |
|
|
|
7,424 |
|
|
|
4,238 |
|
|
|
3,759 |
|
Total net deferred income tax liabilities |
|
$ |
5,211 |
|
|
$ |
5,195 |
|
|
$ |
3,772 |
|
|
$ |
3,256 |
|
Total deferred income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant and equipment, primarily depreciation method and basis differences |
|
$ |
4,601 |
|
|
$ |
4,008 |
|
|
$ |
3,394 |
|
|
$ |
2,758 |
|
Nuclear decommissioning |
|
|
994 |
|
|
|
913 |
|
|
|
407 |
|
|
|
374 |
|
Deferred state income taxes |
|
|
474 |
|
|
|
493 |
|
|
|
265 |
|
|
|
243 |
|
Federal benefit of deferred state income taxes |
|
|
(166 |
) |
|
|
(173 |
) |
|
|
(93 |
) |
|
|
(85 |
) |
Deferred fuel, purchased energy and gas costs |
|
|
3 |
|
|
|
161 |
|
|
|
(16 |
) |
|
|
144 |
|
Pension benefits |
|
|
231 |
|
|
|
396 |
|
|
|
(17 |
) |
|
|
8 |
|
Other postretirement benefits |
|
|
(171 |
) |
|
|
(167 |
) |
|
|
(7 |
) |
|
|
(13 |
) |
Loss and credit carryforwards |
|
|
(656 |
) |
|
|
(577 |
) |
|
|
(77 |
) |
|
|
(55 |
) |
Reserve for rate proceedings |
|
|
|
|
|
|
(54 |
) |
|
|
|
|
|
|
(54 |
) |
Partnership basis differences |
|
|
174 |
|
|
|
274 |
|
|
|
|
|
|
|
|
|
Valuation allowances |
|
|
93 |
|
|
|
96 |
|
|
|
|
|
|
|
|
|
Other |
|
|
(366 |
) |
|
|
(175 |
) |
|
|
(84 |
) |
|
|
(64 |
) |
Total net deferred income tax liabilities |
|
$ |
5,211 |
|
|
$ |
5,195 |
|
|
$ |
3,772 |
|
|
$ |
3,256 |
|
At December 31, 2012, Dominion had the following deductible loss and credit carryforwards:
|
|
Federal loss carryforwards of $1.1 billion that expire if unutilized during the period 2021 through 2031; |
|
|
Federal production tax credits of $26 million that expire if unutilized through 2032; |
|
|
State loss carryforwards of $1.4 billion that expire if unutilized during the period 2014 through 2032. A valuation allowance on $857 million of these
carryforwards has been established; |
|
|
State minimum tax credits of $96 million that do not expire; and |
|
|
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. |
At December 31, 2012, Virginia Power
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
tax refunds receivable or changing deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, an 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 |
|
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
$ |
347 |
|
|
$ |
307 |
|
|
$ |
291 |
|
|
$ |
114 |
|
|
$ |
117 |
|
|
$ |
121 |
|
Increasesprior period positions |
|
|
28 |
|
|
|
127 |
|
|
|
34 |
|
|
|
4 |
|
|
|
22 |
|
|
|
4 |
|
Decreasesprior period positions |
|
|
(106 |
) |
|
|
(119 |
) |
|
|
(75 |
) |
|
|
(80 |
) |
|
|
(51 |
) |
|
|
(33 |
) |
Increasescurrent period positions |
|
|
43 |
|
|
|
64 |
|
|
|
61 |
|
|
|
24 |
|
|
|
47 |
|
|
|
25 |
|
Decreasescurrent period positions |
|
|
|
|
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
|
(21 |
) |
|
|
|
|
Settlements with tax authorities |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
Expiration of statutes of limitation |
|
|
(15 |
) |
|
|
(11 |
) |
|
|
(4 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
Balance at December 31 |
|
$ |
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 $167 million, $184 million and $133 million at December 31, 2012, 2011 and 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, respectively. For Virginia Power, these unrecognized tax benefits were $13 million, $20 million and $14 million at December 31, 2012, 2011 and 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, respectively.
For Dominion and its subsidiaries, the U.S. federal statute of limitations has expired for years prior to 2008. For prior years, Dominion
had reserved the right to pursue refunds related to the calculation of interest to be capitalized in connection with improvements to in-service plant and equipment for the years 1995 through 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 January 2012, the Appellate Division of the IRS informed Dominion that the Joint Committee had completed its review of the settlement
of tax years 2004 and 2005 for Dominion and its
consolidated subsidiaries. Since the measurement of unrecognized tax benefits in 2011 considered the results of completed settlement negotiations, Dominions results of operations in 2012
were not affected.
In April 2012, the IRS issued its Revenue Agent Report for Dominions consolidated tax returns for tax
years 2006 and 2007, reflecting the resolution of all issues, except the capitalized interest on idle property issue that was in 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 include examination of
the 2011 tax year. The audit is expected to be concluded in late 2013.
It is reasonably possible that settlements with and
payments to tax authorities in 2013 and the expiration of statutes of limitations could reduce unrecognized tax benefits for Dominion and Virginia Power by up to $65 million and $35 million, respectively. If such changes were to occur, other than
revisions of the accrual for interest on tax underpayments and overpayments, Dominions earnings could increase by up to $10 million, and Virginia Powers earnings would not be affected.
Otherwise, with regard to 2012 and prior years, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to
unrecognized tax benefits that may occur in 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 |
|
|
2009 |
|
Connecticut |
|
|
2009 |
|
Massachusetts |
|
|
2008 |
|
Virginia(1) |
|
|
2009 |
|
West Virginia |
|
|
2009 |
|
(1) |
Virginia is the only state considered major for Virginia Powers operations. |
Dominion and Virginia Power are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition,
if Dominion utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are subject to examination.
Discontinued Operations
Dominions effective tax rate for 2012 reflects the dispositions of
State Line and Salem Harbor.
Dominions effective tax rate for 2011 reflects an expectation that State Lines
deferred tax assets, including 2011 operating losses, will not be realized in State Lines separately filed state tax returns.
Dominions effective tax rate for 2010 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.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 6. FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly
transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use
when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit
enhancements but also the impact of Dominions and Virginia Powers 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 Dominions 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, 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.
Dominions and Virginia Powers 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 contracts estimated fair value.
The inputs and assumptions used in measuring fair value include the following:
For commodity and foreign currency derivative contracts:
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Forward commodity prices |
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|
Forward foreign currency prices |
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Credit quality of counterparties and Dominion and Virginia Power |
For interest rate derivative contracts:
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Credit quality of counterparties and Dominion and Virginia Power |
For investments:
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Quoted securities prices and indices |
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Securities trading information including volume and restrictions |
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|
NAV (only for alternative investments)
|
Dominion and Virginia Power regularly evaluate and validate the inputs used to estimate
fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various
commodities and investments in which the Companies transact.
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:
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|
Level 1Quoted 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. |
|
|
Level 2Inputs 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. |
|
|
Level 3Unobservable 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
applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.
For derivative contracts, 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 are generally not considered to be liquid markets. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets. Alternative investments
are categorized as Level 3 due to the absence of quoted market prices, illiquidity and the long-term nature of these assets. These investments are generally valued using NAV based on the proportionate share of the fair value as determined by
reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment managers and the Companies measurement
date.
Dominion and Virginia Power enter 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 forward 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 Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, price correlations, the original
sales prices, and volumes. For Level 3 fair value measurements, the 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.
Combined Notes to Consolidated Financial Statements, Continued
The following table presents Dominions 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.
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|
Fair Value (millions) |
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|
Valuation Techniques |
|
Unobservable Input |
|
|
|
|
|
Range |
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|
Weighted Average(1)
|
|
At December 31, 2012 |
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Assets: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical and Financial Forwards and Futures: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. |
(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. |
(9) |
The range in market prices is the result of large variability in hourly power prices during peak and off-peak hours. |
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
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|
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|
|
|
|
|
|
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
MERCHANT POWER STATIONS
In the third quarter of 2012, Dominion decided to pursue the sale of Brayton Point and Kincaid, as well as its 50% interest in Elwood, which is an equity method investment. Since Dominion 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 of September 30, 2012.
At December 31, 2012, Dominion updated its recoverability analysis for
Brayton Point and Kincaid to reflect bids received and an updated probability weighting. As a result of this updated evaluation, Dominion recorded an impairment charge of approximately $1.6 billion ($1.0 billion after-tax), which is included in
other operations and maintenance expense in its Consolidated Statement of Income, to write down Brayton Points and Kincaids long-lived assets to their estimated fair value of approximately $216 million. Dominion used a market approach to
estimate the fair value of Brayton Points and Kincaids long-lived assets. This was considered a Level 2 fair value measurement given it was based on bids received.
Any sale of Brayton Point, Kincaid, or Dominions 50% interest in Elwood would be subject to the approval of Dominions Board
of Directors, as well 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
contract to buy Kewaunees generation will expire in December 2013 at a time of projected low wholesale electricity prices in the region. At September 30, 2012, Dominion expected that it would permanently cease generation operations at
Kewaunee in 2013 and commence decommissioning of the facility. As a result, Dominion evaluated Kewaunee for impairment since it was more likely than not that Kewaunee would be retired before the end of its previously estimated useful life. As
management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of
Kewaunees 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 Kewaunees 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 Dominions 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
Kewaunees 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 stations relatively low level of profitability combined with the EPAs 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 Lines 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 Lines 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 Lines 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 loss from discontinued operations 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 used the income approach (discounted cash flows) to estimate the fair value of State Lines and Salem Harbors long-lived assets in these impairment tests. These were
considered Level 3 fair value measurements 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 Dominions 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 EPAs 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 EPAs 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
CSAPRs 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
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 CSAPRs 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 Dominions pension and other
postretirement benefit plans are presented in Note 21.
DOMINION
The following table presents Dominions assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
12 |
|
|
$ |
639 |
|
|
$ |
84 |
|
|
$ |
735 |
|
Interest rate |
|
|
|
|
|
|
93 |
|
|
|
|
|
|
|
93 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
1,973 |
|
|
|
|
|
|
|
|
|
|
|
1,973 |
|
Other |
|
|
59 |
|
|
|
|
|
|
|
|
|
|
|
59 |
|
Non-U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
12 |
|
Fixed Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
|
|
|
|
325 |
|
|
|
|
|
|
|
325 |
|
U.S. Treasury securities and agency debentures |
|
|
391 |
|
|
|
152 |
|
|
|
|
|
|
|
543 |
|
State and municipal |
|
|
|
|
|
|
315 |
|
|
|
|
|
|
|
315 |
|
Other |
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
7 |
|
Cash equivalents and other |
|
|
13 |
|
|
|
67 |
|
|
|
|
|
|
|
80 |
|
Restricted cash equivalents |
|
|
|
|
|
|
33 |
|
|
|
|
|
|
|
33 |
|
Total assets |
|
$ |
2,460 |
|
|
$ |
1,631 |
|
|
$ |
84 |
|
|
$ |
4,175 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
8 |
|
|
$ |
528 |
|
|
$ |
59 |
|
|
$ |
595 |
|
Interest rate |
|
|
|
|
|
|
66 |
|
|
|
|
|
|
|
66 |
|
Total liabilities |
|
$ |
8 |
|
|
$ |
594 |
|
|
$ |
59 |
|
|
$ |
661 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Dominions assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Balance at January 1, |
|
$ |
(71 |
) |
|
$ |
(50 |
) |
|
$ |
(66 |
) |
Total realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
(15 |
) |
|
|
(77 |
) |
|
|
43 |
|
Included in other comprehensive income (loss) |
|
|
101 |
|
|
|
14 |
|
|
|
(49 |
) |
Included in regulatory assets/liabilities |
|
|
30 |
|
|
|
(42 |
) |
|
|
24 |
|
Settlements |
|
|
47 |
|
|
|
88 |
|
|
|
(38 |
) |
Transfers out of Level 3 |
|
|
(67 |
) |
|
|
(4 |
) |
|
|
36 |
|
Balance at December 31, |
|
$ |
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 |
|
$ |
42 |
|
|
$ |
22 |
|
|
$ |
(4 |
) |
The following table presents Dominions 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, 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 Powers assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
1 |
|
|
$ |
5 |
|
|
$ |
6 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
779 |
|
|
|
|
|
|
|
|
|
|
|
779 |
|
Other |
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
27 |
|
Fixed Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
|
|
|
|
196 |
|
|
|
|
|
|
|
196 |
|
U.S. Treasury securities and agency debentures |
|
|
168 |
|
|
|
66 |
|
|
|
|
|
|
|
234 |
|
State and municipal |
|
|
|
|
|
|
118 |
|
|
|
|
|
|
|
118 |
|
Other |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Cash equivalents and other |
|
|
7 |
|
|
|
31 |
|
|
|
|
|
|
|
38 |
|
Restricted cash equivalents |
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
10 |
|
Total assets |
|
$ |
981 |
|
|
$ |
423 |
|
|
$ |
5 |
|
|
$ |
1,409 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
6 |
|
|
$ |
3 |
|
|
$ |
9 |
|
Interest rate |
|
|
|
|
|
|
25 |
|
|
|
|
|
|
|
25 |
|
Total Liabilities |
|
$ |
|
|
|
$ |
31 |
|
|
$ |
3 |
|
|
$ |
34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Powers assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Powers Consolidated Statements of Income for the years
ended December 31, 2012, 2011 and 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 Dominions and Virginia Powers 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 Dominions and
Vir-
Combined Notes to Consolidated Financial Statements, Continued
ginia Powers financial instruments that are not recorded at fair value, the carrying amounts and fair values are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
2012 |
|
|
2011 |
|
|
|
Carrying Amount |
|
|
Estimated Fair
Value(1) |
|
|
Carrying Amount |
|
|
Estimated Fair
Value(1) |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, including securities due within one
year(2) |
|
$ |
16,841 |
|
|
$ |
19,898 |
|
|
$ |
16,264 |
|
|
$ |
18,936 |
|
Long-term debt, including securities due within one
yearVIE(3) |
|
|
860 |
|
|
|
864 |
|
|
|
890 |
|
|
|
892 |
|
Junior subordinated notes |
|
|
1,373 |
|
|
|
1,430 |
|
|
|
1,719 |
|
|
|
1,786 |
|
Subsidiary preferred
stock(4) |
|
|
257 |
|
|
|
255 |
|
|
|
257 |
|
|
|
256 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, including securities due within one
year(2) |
|
$ |
6,669 |
|
|
$ |
8,270 |
|
|
$ |
6,862 |
|
|
$ |
8,281 |
|
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 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, 2012, and 2011, includes the valuation of certain fair value hedges
associated with Dominions fixed rate debt, of approximately $93 million and $105 million, respectively. |
(3) |
Includes amounts which represent the unamortized premium. |
(4) |
Includes deferred issuance expenses of $2 million at December 31, 2012 and 2011. |
NOTE 7. DERIVATIVES AND 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 6 for further information about fair value measurements and associated valuation methods for derivatives.
DOMINION
The following table presents the volume of Dominions derivative activity as of December 31, 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 transactions, for which they represent the absolute value of the net volume of their long and short positions.
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
Noncurrent |
|
Natural Gas (bcf): |
|
|
|
|
|
|
|
|
Fixed price(1) |
|
|
249 |
|
|
|
68 |
|
Basis(1) |
|
|
786 |
|
|
|
534 |
|
Electricity (MWh): |
|
|
|
|
|
|
|
|
Fixed price(1) |
|
|
20,100,938 |
|
|
|
12,582,674 |
|
FTRs |
|
|
46,851,683 |
|
|
|
|
|
Capacity (MW) |
|
|
151,025 |
|
|
|
148,461 |
|
Liquids (gallons)(2) |
|
|
164,682,000 |
|
|
|
145,698,000 |
|
Interest rate |
|
$ |
1,500,000,000 |
|
|
$ |
2,250,000,000 |
|
(2) |
Includes NGLs and oil. |
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.
The following table presents selected information related to gains (losses) on cash flow hedges included
in AOCI in Dominions Consolidated Balance Sheet at December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AOCI After-Tax |
|
|
Amounts Expected to be Reclassified to Earnings during the next
12 Months After-Tax |
|
|
Maximum Term |
|
(millions) |
|
|
|
|
|
|
|
|
|
Commodities: |
|
|
|
|
|
|
|
|
|
|
|
|
Gas |
|
$ |
(28 |
) |
|
$ |
(24 |
) |
|
|
27 months |
|
Electricity |
|
|
68 |
|
|
|
17 |
|
|
|
36 months |
|
Other |
|
|
3 |
|
|
|
2 |
|
|
|
41 months |
|
Interest rate |
|
|
(165 |
) |
|
|
(21 |
) |
|
|
361 months |
|
Total |
|
$ |
(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 Dominions remaining E&P operations resulted in the
discontinuance of hedge accounting for certain cash flow hedges in 2010, as discussed in Note 3.
In addition, changes to
Dominions 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
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 Dominions derivatives and where they are presented in its Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
$ |
103 |
|
|
$ |
379 |
|
|
$ |
482 |
|
Interest rate |
|
|
36 |
|
|
|
|
|
|
|
36 |
|
Total current derivative assets |
|
|
139 |
|
|
|
379 |
|
|
|
518 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
130 |
|
|
|
123 |
|
|
|
253 |
|
Interest rate |
|
|
57 |
|
|
|
|
|
|
|
57 |
|
Total noncurrent derivative assets(1) |
|
|
187 |
|
|
|
123 |
|
|
|
310 |
|
Total derivative assets |
|
$ |
326 |
|
|
$ |
502 |
|
|
$ |
828 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
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 |
|
|
384 |
|
|
|
567 |
|
|
|
951 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
118 |
|
|
|
78 |
|
|
|
196 |
|
Interest rate |
|
|
|
|
|
|
10 |
|
|
|
10 |
|
Total noncurrent derivative liabilities(2) |
|
|
118 |
|
|
|
88 |
|
|
|
206 |
|
Total derivative liabilities |
|
$ |
502 |
|
|
$ |
655 |
|
|
$ |
1,157 |
|
(1) |
Noncurrent derivative assets are presented in other deferred charges and other assets in Dominions Consolidated Balance Sheets. |
(2) |
Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominions Consolidated Balance Sheets.
|
The following tables present the gains and losses on Dominions 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, 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 |
|
|
|
|
|
$ |
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 |
) |
(1) |
Amounts deferred into AOCI have no associated effect in Dominions 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 Dominions Consolidated Statements of Income. |
(3) |
Amounts recorded in Dominions Consolidated Statements of Income are classified in interest and related charges. |
(4) |
Amounts recorded in Dominions Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.
|
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
Dominions Consolidated Statements of Income. |
(2) |
Amounts recorded in Dominions Consolidated Statements of Income are classified in interest and related charges. |
VIRGINIA POWER
The
following table presents the volume of Virginia Powers derivative activity at December 31, 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 transactions, for which they represent the absolute value of the net volume of their long and short positions.
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
Noncurrent |
|
Natural Gas (bcf): |
|
|
|
|
|
|
|
|
Fixed price |
|
|
16 |
|
|
|
|
|
Basis |
|
|
8 |
|
|
|
|
|
Electricity (MWh): |
|
|
|
|
|
|
|
|
Fixed price |
|
|
709,600 |
|
|
|
|
|
FTRs |
|
|
43,570,739 |
|
|
|
|
|
Capacity (MW) |
|
|
107,000 |
|
|
|
93,800 |
|
Interest rate |
|
$ |
500,000,000 |
|
|
$ |
250,000,000 |
|
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 the time value of options and changes in the
differences between spot prices and forward prices.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Virginia Powers derivatives and where they are presented in its Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
$ |
1 |
|
|
$ |
5 |
|
|
$ |
6 |
|
Total current derivative
assets(1) |
|
|
1 |
|
|
|
5 |
|
|
|
6 |
|
Total derivative assets |
|
$ |
1 |
|
|
$ |
5 |
|
|
$ |
6 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
5 |
|
|
$ |
3 |
|
|
$ |
8 |
|
Interest rate |
|
|
25 |
|
|
|
|
|
|
|
25 |
|
Total current derivative liabilities |
|
|
30 |
|
|
|
3 |
|
|
|
33 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Total noncurrent derivative liabilities(2) |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Total derivative liabilities |
|
$ |
31 |
|
|
$ |
3 |
|
|
$ |
34 |
|
At December 31, 2011 |
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
2 |
|
|
$ |
2 |
|
Total current derivative
assets(1) |
|
|
|
|
|
|
2 |
|
|
|
2 |
|
Total derivative assets |
|
$ |
|
|
|
$ |
2 |
|
|
$ |
2 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
14 |
|
|
$ |
31 |
|
|
$ |
45 |
|
Interest rate |
|
|
53 |
|
|
|
37 |
|
|
|
90 |
|
Total current derivative liabilities |
|
|
67 |
|
|
|
68 |
|
|
|
135 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Interest rate |
|
|
|
|
|
|
10 |
|
|
|
10 |
|
Total noncurrent derivative liabilities(2) |
|
|
2 |
|
|
|
10 |
|
|
|
12 |
|
Total derivative liabilities |
|
$ |
69 |
|
|
$ |
78 |
|
|
$ |
147 |
|
(1) |
Current derivative assets are presented in other current assets in Virginia Powers Consolidated Balance Sheets. |
(2) |
Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Powers Consolidated Balance Sheets.
|
The following tables present the gains and losses on Virginia Powers 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, 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: |
|
|
|
|
|
|
|
|
|
|
|
|
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 |
) |
|
|
|
|
Purchased electric capacity |
|
|
|
|
|
|
4 |
|
|
|
|
|
Total commodity |
|
$ |
(1 |
) |
|
$ |
3 |
|
|
$ |
(17 |
) |
Interest rate(3) |
|
|
(1 |
) |
|
|
9 |
|
|
|
(27 |
) |
Foreign
currency(4) |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
Total |
|
$ |
(2 |
) |
|
$ |
12 |
|
|
$ |
(46 |
) |
(1) |
Amounts deferred into AOCI have no associated effect in Virginia Powers 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 Powers Consolidated Statements of Income. |
(3) |
Amounts recorded in Virginia Powers Consolidated Statements of Income are classified in interest and related charges. |
(4) |
Amounts recorded in Virginia Powers 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, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity(2) |
|
$ |
(50 |
) |
|
$ |
(45 |
) |
|
$ |
51 |
|
Interest
rate(3) |
|
|
|
|
|
|
(5 |
) |
|
|
(3 |
) |
Total |
|
$ |
(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 Powers Consolidated Statements of Income. |
(2) |
Amounts recorded in Virginia Powers Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.
|
(3) |
Amounts recorded in Virginia Powers Consolidated Statements of Income are classified in interest and related charges.
|
NOTE 8. EARNINGS PER SHARE
The following table presents the calculation of Dominions basic and diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
Combined Notes to Consolidated Financial Statements, Continued
There were no potentially dilutive securities excluded from the calculation of diluted
EPS for the years ended December 31, 2012, 2011 and 2010.
NOTE 9. INVESTMENTS
DOMINION
Equity and
Debt Securities
RABBI TRUST SECURITIES
Marketable equity and debt securities and cash equivalents held in Dominions rabbi trusts and classified as trading totaled $95 million and $90
million at December 31, 2012 and 2011, respectively. Cost-method investments held in Dominions rabbi trusts totaled $14 million and $17 million at December 31, 2012 and 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. Dominions decommissioning trust funds are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortized Cost |
|
|
Total Unrealized Gains(1) |
|
|
Total Unrealized Losses(1) |
|
|
Fair Value |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
$ |
1,210 |
|
|
$ |
732 |
|
|
$ |
|
|
|
$ |
1,942 |
|
Other |
|
|
40 |
|
|
|
13 |
|
|
|
|
|
|
|
53 |
|
Marketable debt securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
295 |
|
|
|
30 |
|
|
|
|
|
|
|
325 |
|
U.S. Treasury securities and agency debentures |
|
|
523 |
|
|
|
19 |
|
|
|
(2 |
) |
|
|
540 |
|
State and municipal |
|
|
248 |
|
|
|
26 |
|
|
|
|
|
|
|
274 |
|
Other |
|
|
6 |
|
|
|
1 |
|
|
|
|
|
|
|
7 |
|
Cost method investments |
|
|
117 |
|
|
|
|
|
|
|
|
|
|
|
117 |
|
Cash equivalents and
other(2) |
|
|
72 |
|
|
|
|
|
|
|
|
|
|
|
72 |
|
Total |
|
$ |
2,511 |
|
|
$ |
821 |
|
|
$ |
(2 |
)(3) |
|
$ |
3,330 |
|
2011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
$ |
1,152 |
|
|
$ |
537 |
|
|
$ |
|
|
|
$ |
1,689 |
|
Other |
|
|
36 |
|
|
|
10 |
|
|
|
|
|
|
|
46 |
|
Marketable debt securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
314 |
|
|
|
19 |
|
|
|
(1 |
) |
|
|
332 |
|
U.S. Treasury securities and agency debentures |
|
|
437 |
|
|
|
20 |
|
|
|
(1 |
) |
|
|
456 |
|
State and municipal |
|
|
264 |
|
|
|
24 |
|
|
|
|
|
|
|
288 |
|
Other |
|
|
23 |
|
|
|
1 |
|
|
|
|
|
|
|
24 |
|
Cost method investments |
|
|
118 |
|
|
|
|
|
|
|
|
|
|
|
118 |
|
Cash equivalents and
other(2) |
|
|
46 |
|
|
|
|
|
|
|
|
|
|
|
46 |
|
Total |
|
$ |
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 $6 million and $11 million at December 31, 2012 and 2011, respectively. |
(3) |
The fair value of securities in an unrealized loss position was $195 million and $164 million at December 31, 2012 and 2011, respectively.
|
The fair value of Dominions marketable debt securities held in nuclear
decommissioning trust funds at December 31, 2012 by contractual maturity is as follows:
|
|
|
|
|
|
|
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 Dominions marketable equity and
debt securities held in nuclear decommissioning trust funds:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Proceeds from sales |
|
$ |
1,356 |
|
|
$ |
1,757 |
|
|
$ |
1,814 |
(1) |
Realized gains(2) |
|
|
98 |
|
|
|
79 |
|
|
|
111 |
|
Realized
losses(2) |
|
|
33 |
|
|
|
92 |
|
|
|
63 |
|
(1) |
Does not include $1 billion of proceeds reflected in Dominions Consolidated Statement of Cash Flows from the sale of temporary investments
|
|
consisting of time deposits and Treasury Bills, purchased following the sale of substantially all of Dominions Appalachian E&P operations. |
(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, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Total other-than-temporary impairment losses(1) |
|
$ |
26 |
|
|
$ |
75 |
|
|
$ |
59 |
|
Losses recorded to decommissioning trust regulatory liability |
|
|
(10 |
) |
|
|
(24 |
) |
|
|
(21 |
) |
Losses recognized in other comprehensive income (before taxes) |
|
|
(2 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
Net impairment losses recognized in earnings |
|
$ |
14 |
|
|
$ |
48 |
|
|
$ |
35 |
|
(1) |
Amounts include other-than-temporary impairment losses for debt securities of $4 million, $6 million and $10 million at December 31, 2012, 2011 and 2010,
respectively. |
Equity Method Investments
Investments that Dominion accounts for under the equity method of accounting are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company |
|
Ownership% |
|
|
Investment
Balance |
|
|
Description |
As of December 31, |
|
|
|
|
2012 |
|
|
2011 |
|
|
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
Fowler I Holdings LLC |
|
|
50 |
% |
|
$ |
158 |
|
|
$ |
166 |
|
|
Wind-powered merchant generation facility |
NedPower Mount Storm LLC |
|
|
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 |
% |
|
|
102 |
|
|
|
104 |
|
|
Gas transmission system |
Blue Racer Midstream LLC |
|
|
50 |
% |
|
|
39 |
|
|
|
|
|
|
Midstream gas and related services |
Other(1) |
|
|
various |
|
|
|
5 |
|
|
|
29 |
|
|
|
Total |
|
|
|
|
|
$ |
558 |
|
|
$ |
553 |
|
|
|
(1) |
Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018. |
Dominions equity earnings on these investments totaled $25 million, $35 million and $42 million in 2012, 2011 and 2010,
respectively. Dominion received distributions from these investments of $58 million, $55 million and $60 million in 2012, 2011, and 2010, respectively. As of December 31, 2012 and 2011, the carrying amount of Dominions investments
exceeded Dominions share of underlying equity in net assets by approximately $30 million and $32 million, respectively. The differences relate to Dominions 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 Dominions partners for these projects. The differences are generally being amortized over the useful lives of the underlying
assets.
BLUE RACER
In December 2012, Dominion formed a joint venture with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. 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 cash 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 Dominions Consolidated Statement of Income. The joint venture will leverage Dominions 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 DTI pipeline connecting East Ohios 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 Powers decommissioning trust funds are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
Combined Notes to Consolidated Financial Statements, Continued
(2) |
Includes pending sales of securities of $6 million and pending purchases of securities of $13 million at December 31, 2012 and 2011, respectively.
|
(3) |
The fair value of securities in an unrealized loss position was $104 million and $99 million at December 31, 2012 and 2011, respectively.
|
The fair value of Virginia Powers debt securities at December 31, 2012, by contractual maturity
is as follows:
|
|
|
|
|
|
|
Amount |
|
(millions) |
|
|
|
Due in one year or less |
|
$ |
18 |
|
Due after one year through five years |
|
|
156 |
|
Due after five years through ten years |
|
|
217 |
|
Due after ten years |
|
|
157 |
|
Total |
|
$ |
548 |
|
Presented below is selected information regarding Virginia Powers marketable equity and debt
securities.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Proceeds from sales |
|
$ |
626 |
|
|
$ |
1,030 |
|
|
$ |
1,192 |
|
Realized gains(1) |
|
|
42 |
|
|
|
34 |
|
|
|
52 |
|
Realized
losses(1) |
|
|
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, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Total other-than-temporary impairment losses(1) |
|
$ |
11 |
|
|
$ |
29 |
|
|
$ |
25 |
|
Losses recorded to decommissioning trust regulatory liability |
|
|
(10 |
) |
|
|
(24 |
) |
|
|
(21 |
) |
Losses recorded in other comprehensive income (before taxes) |
|
|
|
|
|
|
(1 |
) |
|
|
(1 |
) |
Net impairment losses recognized in earnings |
|
$ |
1 |
|
|
$ |
4 |
|
|
$ |
3 |
|
(1) |
Amounts include other-than-temporary impairment losses for debt securities of $2 million, $4 million and $6 million at December 31, 2012, 2011 and 2010,
respectively. |
OTHER 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
qual-
ifying construction projects. At December 31, 2012 and 2011, Dominion had $37 million and $147 million, respectively, and Virginia Power had $10 million and $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 10. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment and their respective balances for the Companies are as follows:
|
|
|
|
|
|
|
|
|
At December 31, |
|
2012 |
|
|
2011 |
|
(millions) |
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
Utility: |
|
|
|
|
|
|
|
|
Generation |
|
$ |
13,707 |
|
|
$ |
11,793 |
|
Transmission |
|
|
7,799 |
|
|
|
6,604 |
|
Distribution |
|
|
11,071 |
|
|
|
10,401 |
|
Storage |
|
|
2,137 |
|
|
|
2,060 |
|
Nuclear fuel |
|
|
1,277 |
|
|
|
1,193 |
|
Gas gathering and processing |
|
|
803 |
|
|
|
727 |
|
General and other |
|
|
803 |
|
|
|
778 |
|
Other-including plant under construction |
|
|
2,232 |
|
|
|
3,597 |
|
Total utility |
|
|
39,829 |
|
|
|
37,153 |
|
Nonutility: |
|
|
|
|
|
|
|
|
Merchant generationnuclear |
|
|
1,163 |
|
|
|
1,108 |
|
Merchant generationother(1) |
|
|
1,289 |
|
|
|
2,780 |
|
Nuclear fuel |
|
|
775 |
|
|
|
847 |
|
Other-including plant under construction |
|
|
1,265 |
|
|
|
1,102 |
|
Total nonutility |
|
|
4,492 |
|
|
|
5,837 |
|
Total property, plant and equipment |
|
$ |
44,321 |
|
|
$ |
42,990 |
|
|
|
|
Virginia Power |
|
|
|
|
|
|
|
|
Utility: |
|
|
|
|
|
|
|
|
Generation |
|
$ |
13,707 |
|
|
$ |
11,793 |
|
Transmission |
|
|
4,261 |
|
|
|
3,823 |
|
Distribution |
|
|
8,701 |
|
|
|
8,231 |
|
Nuclear fuel |
|
|
1,277 |
|
|
|
1,193 |
|
General and other |
|
|
659 |
|
|
|
631 |
|
Other-including plant under construction |
|
|
2,017 |
|
|
|
2,946 |
|
Total utility |
|
|
30,622 |
|
|
|
28,617 |
|
Nonutility-other |
|
|
9 |
|
|
|
9 |
|
Total property, plant and equipment |
|
$ |
30,631 |
|
|
$ |
28,626 |
|
(1) |
Amount includes $957 million due to consolidation of a VIE.
|
Jointly-Owned Power Stations
Dominions and Virginia Powers proportionate share of jointly-owned power stations at December 31, 2012 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bath County Pumped Storage Station(1) |
|
|
North Anna Units 1 and 2(1) |
|
|
Clover Power Station(1)
|
|
|
Millstone Unit
3(2) |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
Ownership interest |
|
|
60 |
% |
|
|
88.4 |
% |
|
|
50 |
% |
|
|
93.5 |
% |
Plant in service |
|
$ |
1,024 |
|
|
$ |
2,392 |
|
|
$ |
568 |
|
|
$ |
993 |
|
Accumulated depreciation |
|
|
(521 |
) |
|
|
(1,072 |
) |
|
|
(192 |
) |
|
|
(236 |
) |
Nuclear fuel |
|
|
|
|
|
|
502 |
|
|
|
|
|
|
|
456 |
|
Accumulated amortization of nuclear fuel |
|
|
|
|
|
|
(390 |
) |
|
|
|
|
|
|
(272 |
) |
Plant under construction |
|
|
27 |
|
|
|
77 |
|
|
|
6 |
|
|
|
36 |
|
(1) |
Units jointly owned by Virginia Power. |
(2) |
Unit jointly owned by Dominion. |
The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest.
Dominion and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes,
etc.) in the Consolidated Statements of Income.
NOTE 11. GOODWILL AND INTANGIBLE ASSETS
Goodwill
The changes in
Dominions carrying amount and segment allocation of goodwill are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
Dominions and Virginia Powers other intangible assets are subject to amortization over their estimated useful lives. Dominions amortization expense for intangible assets was $82 million,
$78 million and $107 million for 2012, 2011 and 2010, respectively. In 2012, Dominion acquired $102 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 19 years.
Amortization expense for Virginia Powers 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, |
|
2012 |
|
|
2011 |
|
|
|
Gross Carrying Amount |
|
|
Accumulated Amortization |
|
|
Gross Carrying Amount |
|
|
Accumulated Amortization |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Software, licenses and other |
|
$ |
859 |
|
|
$ |
327 |
|
|
$ |
888 |
|
|
$ |
278 |
|
Emissions allowances |
|
|
5 |
|
|
|
1 |
|
|
|
80 |
|
|
|
53 |
|
Total |
|
$ |
864 |
|
|
$ |
328 |
|
|
$ |
968 |
|
|
$ |
331 |
|
|
|
|
|
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Software, licenses and other |
|
$ |
303 |
|
|
$ |
122 |
|
|
$ |
285 |
|
|
$ |
102 |
|
Total |
|
$ |
303 |
|
|
$ |
122 |
|
|
$ |
285 |
|
|
$ |
102 |
|
Annual amortization expense for these intangible assets is estimated to be as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 |
|
|
2014 |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
$ |
65 |
|
|
$ |
56 |
|
|
$ |
43 |
|
|
$ |
37 |
|
|
$ |
25 |
|
|
|
|
|
|
|
Virginia Power |
|
$ |
20 |
|
|
$ |
18 |
|
|
$ |
12 |
|
|
$ |
8 |
|
|
$ |
5 |
|
Combined Notes to Consolidated Financial Statements, Continued
NOTE 12. REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities include the following:
|
|
|
|
|
|
|
|
|
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) |
Reflects unrecovered gas costs at Dominions regulated gas operations, which are recovered through quarterly or annual filings with the applicable regulatory
authority. |
(2) |
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 Powers 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 Dominions rate-regulated subsidiaries. |
(8) |
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. |
(9) |
Primarily reflects costs recognized in excess of amounts included in regulated rates charged by Dominions regulated gas operations before rates were updated to
reflect a change in accounting method for other postretirement benefit costs. |
(10) |
Under PIPP, eligible customers can receive energy assistance based on their ability to pay. The difference between the customers 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 Biennial Review Order. See Note 13 for more information. |
(12) |
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 Powers utility nuclear generation stations, in excess of the related ARO. |
At December 31, 2012, approximately $319 million of Dominions and $240 million of Virginia Powers regulatory
assets represented past expenditures on which they do not currently earn a return. These expenditures are expected to be recovered within the next two years.
NOTE 13. REGULATORY MATTERS
Regulatory Matters Involving Potential Loss Contingencies
As a result of issues generated in the ordinary course of business, 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-
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 Dominions or Virginia Powers financial position, liquidity or results of operations. The following is a discussion of Dominions and
Virginia Powers material pending and recent regulatory matters.
FERCElectric
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 Dominions merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominions 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 Powers service territory. Any
such sales would be voluntary.
Rates
In April 2008, FERC granted an application for Virginia Powers 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 Powers 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 Powers 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 Powers 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 FERCs 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 FERCs 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
The enactment of the Regulation Act in 2007 significantly
changed electric service regulation in Virginia by instituting a modified cost-of-service rate model. With respect to most classes of customers, the Regulation Act ended Virginias planned transition to retail competition for its electric
supply service.
Combined Notes to Consolidated Financial Statements, Continued
The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for
new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It 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. See Future Issues and Other Matters in Item 7. MD&A for a discussion of
this legislation.
If the Virginia Commissions future rate decisions, including actions relating to Virginia Powers
rate adjustment clause filings, differ materially from Virginia Powers 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 Powers 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 Powers base rates are not subject to change based on the 2011 biennial review. In November 2011, the Virginia Commission issued 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 connection with the 2009-2010 biennial review. Instead, in March 2012, the Virginia Commission 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 September 2012, the Virginia Commission issued an Order for Notice and Hearing in the separate rulemaking proceeding to develop
specific performance standards based on nationally recognized standards for the Virginia Commissions 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, allowed for further comments by November 2012 on the proposed rules and regulations as modified, and held a public hearing in November 2012. In 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 Powers 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 Powers 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 Powers 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 Powers previously-approved 11.9% base ROE authorized in the Virginia
Settlement Approval Order would be used to measure base rate earnings for the period January 1, 2011 through November 30, 2011. In March 2012, the Virginia Commission issued an order denying Virginia Powers petition seeking rehearing
or reconsideration. Contrary to Virginia Powers position, 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 the March 2012 Order. In May 2012, the Supreme Court of Virginia granted review of Virginia Powers appeals from the Biennial Review Order and the March 2012 Order denying Virginia Powers 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 Powers petition
seeking rehearing or reconsideration.
ROE Applicable to Riders C1, C2, R, and S
Effective December 1, 2011, the ROE applicable to Riders C1 and C2 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. Based on the 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
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 Commissions 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 Powers 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 Powers 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 Powers base rates and are to be considered as part of its future biennial reviews. The Virginia Commission rejected Virginia Powers 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.
Earnings Test Adjustments
The Virginia Commission ruled on numerous contested proposals to adjust Virginia Powers earnings for the 2009 and 2010 combined test
periods. Among other adjustments, the Virginia Commission approved Virginia Powers 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 Powers 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 Powers 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
Powers 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 Commissions 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 Commissions 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
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 Powers 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 Powers 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 Powers base rates. Virginia Powers 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 Powers
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 Staffs 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 Powers 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
Powers 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 Dominions
renewable generation by more than 150 MW and are expected to be completed by the end of 2013.
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 apply 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 Powers 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, and not through a rate adjustment clause. This case is pending.
Solar Distributed Generation Demonstration Program
In October 2011, Virginia Power filed with the Virginia Commission an application to conduct a solar distributed generation demonstration
program, consisting of up to a combined 30 MW of Company-owned solar distributed generation facilities to be located at selected commercial, industrial and community locations throughout its Virginia service territory. Virginia Power proposed to
construct and operate the Company-owned facilities in two phases, with Phase I (up to 10 MW) from the date of approval through the end of 2013 and Phase II (up to 20 MW)
from the beginning of 2014 to the end of 2015. 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 indicated that it may seek a rate adjustment clause at a future time for Phase II costs.
In November 2012, the Virginia Commission approved the voluntary solar distributed generation demonstration program for Company-owned solar distributed generation facilities subject to a total cost cap of
$80 million (including capital, financing, and operation and maintenance costs) which can be increased subject to future application based upon program experience, results, and data.
In May 2012, Virginia Power filed with the Virginia Commission a petition to implement a special tariff for a combined 3 MW of
customer-owned solar distributed generation facilities. Under the proposed tariff, Rate Schedule SP, Virginia Power would purchase 100% of the energy output from these facilities, including all environmental attributes and associated renewable
energy credits, at a fixed price of $0.15 per kWh for five years. As proposed, the costs of the purchases under Rate Schedule SP would not be recovered from all customers. Following comments, the Virginia Commission issued 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 Powers application to rebuild its portion of 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 Powers portion of the rebuild project is expected to be completed by June 2015.
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. The Hayes-to-Yorktown line was placed in service in December 2012.
In July 2010, the Virginia
Commission authorized Virginia Power to construct the Radnor Heights Project. The Virginia Commission stated that these lines and substation must be constructed and in service by June 30, 2012, and that Virginia Power could apply to extend
this date for good cause shown. In October 2012, the Virginia Commission issued an order extending this construction and the in-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
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 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.
In 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 Commissions consideration an approximately 37 mile alternate route for the 500 kV line from Virginia Powers 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 must 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 ODECs interest in the project, thereby terminating ODECs involvement in the development of a potential third unit at North Anna. In January 2013, the NRC approved the transfer of ODECs 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, BREDLs 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 NRCs 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 courts 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 NRCs August 2012 decision is not expected to affect the schedule for
issuance of the 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 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 Powers fuel case for its North
Carolina service territory. The settlement agreement provided for a $36 million increase in Virginia Powers fuel revenues for one year, effective January 1, 2012, including approximately $13 million in under recovery of fuel expenses for
the previous fuel period.
In March 2012, Virginia Power filed an application with the North Carolina Commission to increase
base non-fuel revenues by approximately $64 million, with January 1, 2013 as the proposed effective date for the permanent rate revision.
In August 2012, Virginia Power filed its annual fuel expense recovery application and testimony with the North Carolina Commission requesting a total annual fuel revenue decrease of approximately $27
million from the fuel and fuel-related costs currently in effect. Virginia Powers filing also sought to implement a temporary voluntary rider, Rider A1, effective
November 1, 2012 to December 31, 2012, to reduce projected over-collection of fuel expense in the second half of 2012.
In August 2012 and October 2012, Virginia Power filed supplemental testimony in the base rate proceeding which had the cumulative effect
of updating Virginia Powers requested overall base non-fuel revenue increase to $53 million. In September 2012, the North Carolina Commission staff filed testimony recommending a non-fuel revenue increase of $24 million. In October 2012, the
North Carolina Commission issued a public notice stating that Virginia Power would begin billing under its proposed rates beginning November 1, 2012 on an interim basis, subject to refund with interest.
In December 2012, the North Carolina Commission approved a $36 million increase in Virginia Powers annual non-fuel base revenues
based on an authorized ROE of 10.2%, and a $14 million decrease in annual base fuel revenues for a combined total base revenue increase of $22 million. These rate changes became effective on January 1, 2013 and 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 Powers annual non-base fuel
Experience Modification Factor revenues. The rate decrease is the result of the Commissions 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 Powers 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 Regulation
PIR
Program
In March 2011, East Ohio filed a request with the Ohio Commission to accelerate the PIR program by nearly doubling its PIR
spending to more than $200 million annually. East Ohio identified 1,450 miles of pipeline that need to be replaced, in addition to the pipeline originally identified in the PIR project scope. 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 the stipulation by East Ohio, the Staff of
the Ohio Commission and other interested parties in East Ohios 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 over a five-year period commencing upon the approval of the Ohio Commission.
In February 2012, East Ohio submitted an application with the Ohio Commission to adjust the cost recovery charge for costs associated with PIR investments for the six months ended December 31, 2011.
The filing was made in accordance with changes to the PIR program approved by the Ohio Commission in August 2011 and effects a transition from a fiscal year ending June 30 to a calendar year for annual filings thereafter. The
appli-
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 $47 million. A stipulation was submitted by East Ohio, the Staff of the Ohio Commission and 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 notice 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 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
customers 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. The PIPP Plus program sets the customers monthly payments at 6% of household income
and provides for forgiveness credits to the customers balance when required payments are received in full by the due date. Such credits may result in the elimination of the customers arrearage balance over 24 months.
In July 2012, the Ohio Commission approved East Ohios 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 Program. The UEX Rider is adjusted annually to achieve dollar-for-dollar recovery of East Ohios
actual write-offs of uncollectable amounts.
In July 2012, the Ohio Commission approved East Ohios 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 from ratepayers in the 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
Combined Notes to Consolidated Financial Statements, Continued
2011 and December 2012 for assets placed in service but not yet reflected in rates. The Ohio Commission approved East Ohios application in December 2012.
In December 2012, East Ohio filed an application requesting authority to implement a capital expenditure program for 2013 capital
expenditures totaling $93 million, subject to the provisions approved for the initial application. This case is pending.
Federal Regulation
FERCGas
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 Dominions 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 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 approving the stipulation and agreement, including the settlement rates that are effective April 1, 2012. The settlement was considered final in August 2012. Pursuant to the terms of the settlement, future operational purchases
of LNG are not expected to affect Cove Points net results of operations. Cove Point and settling customers will be subject to a rate moratorium through December 31, 2016. Cove Point is required to file its next rate case in 2016 with
rates to be effective January 1, 2017.
NOTE 14. ASSET RETIREMENT OBLIGATIONS
AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of
Dominions and Virginia Powers long-lived assets. Dominions and Virginia Powers AROs are primarily associated with the decommissioning of their nuclear generation facilities. In addition, Dominions 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 Dominions LNG
facility, Dominions 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 Powers 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 any of these assets. As a result, a settlement date is not determinable for these
assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies
continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 2011 and 2012 were as follows:
|
|
|
|
|
|
|
Amount |
|
(millions) |
|
|
|
Dominion |
|
|
|
|
AROs at December 31, 2010(1) |
|
$ |
1,591 |
|
Obligations incurred during the period |
|
|
16 |
|
Obligations settled during the period |
|
|
(16 |
) |
Revisions in estimated cash flows(2) |
|
|
(277 |
) |
Accretion |
|
|
84 |
|
AROs at December 31,
2011(1) |
|
$ |
1,398 |
|
Obligations incurred during the period |
|
|
24 |
|
Obligations settled during the period |
|
|
(13 |
) |
Revisions in estimated cash flows(3) |
|
|
242 |
|
Accretion |
|
|
77 |
|
Other |
|
|
(23 |
) |
AROs at December 31,
2012(1) |
|
$ |
1,705 |
|
Virginia Power |
|
|
|
|
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) |
|
|
(90 |
) |
Accretion |
|
|
36 |
|
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 |
|
|
34 |
|
Other |
|
|
(12 |
) |
AROs at December 31, 2012 |
|
$ |
705 |
|
(1) |
Includes $14 million, $15 million and $64 million reported in other current liabilities at December 31, 2010, 2011, and 2012, respectively.
|
(2) |
Primarily reflects the effect of lower anticipated costs due to the expected future recovery from the DOE of certain spent fuel storage costs.
|
(3) |
Primarily reflects the accelerated timing of the decommissioning of Kewaunee to begin in 2013. |
(4) |
Includes $3 million and $1 million reported in other current liabilities at December 31, 2010 and 2011, respectively. |
(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, 2012 and 2011, the aggregate fair value of Dominions trusts, consisting primarily of equity and debt securities, totaled $3.3 billion and $3.0 billion, respectively. At December 31, 2012 and 2011, the aggregate
fair value of Virginia Powers trusts, consisting primarily of debt and equity securities, totaled $1.5 billion and $1.4 billion, respectively.
NOTE 15. VARIABLE INTEREST ENTITIES
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant
variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entitys 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 870 MW. These contracts contain certain variable
pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs.
However, the information they provided, as well as Virginia Powers 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 Powers 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 Powers 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 $1.1 billion as of December 31, 2012. Virginia Power paid $214 million, $211 million, and $213 million for electric capacity and $83 million, $125 million, and $164 million for electric energy to
these entities for the years ended December 31, 2012, 2011 and 2010, respectively.
Virginia Power purchased shared
services from DRS, an affiliated VIE, of approximately $328 million, $389 million, and $465 million for the years ended December 31, 2012, 2011 and 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 Junipers 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 entitys 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 Junipers 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.
Accordingly, Dominion consolidated Juniper in October 2011 and recorded, at fair value, approximately $957 million of property, plant and equipment, $896 million of debt and $61 million of noncontrolling
interests. The debt is non-recourse to Dominion and is secured by Junipers assets. The annual lease payments made by Dominion to Juniper for Fairless are now eliminated in the Consolidated Statements of Income and are excluded from the lease
commitments table in Note 22.
Dominion has not provided any financial or other support to Juniper in the current period that
it was not previously contractually required to provide.
NOTE 16. SHORT-TERM DEBT AND 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, Dominions credit ratings and the credit quality of its counterparties.
Combined Notes to Consolidated Financial Statements, Continued
DOMINION
Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
Effective September 2012, the maturity date was extended from September 2016 to September 2017. This credit facility can be used to support bank borrowings and the
issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit. |
(2) |
Effective September 2012, the maturity date for $400 million of the $500 million in committed capacity of this credit facility was extended from September 2016 to
September 2017. The remaining $100 million continues to have a maturity date of September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. |
(3) |
The weighted-average interest rates of the outstanding commercial paper supported by Dominions credit facilities were 0.49% and 0.47% at December 31, 2012
and 2011, respectively. |
VIRGINIA POWER
Virginia Powers short-term financing is supported by two 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 Powers 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, |
|
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) |
Effective September 2012, the maturity date was extended from September 2016 to September 2017. This credit facility can be used to support bank borrowings and the
issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Powers current sub-limit under this credit facility can be increased or decreased multiple times per
year. |
(2) |
Effective September 2012, the maturity date for $400 million of the $500 million in committed capacity of this credit facility was extended from September 2016 to
September 2017. The remaining $100 million continues to have a maturity date of September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Powers current sub-limit
under this credit facility can be increased or decreased multiple times per year. |
(3) |
The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.47% and 0.46% at December 31, 2012 and 2011,
respectively. |
In addition to the credit facility commitments mentioned above, Virginia Power also has a $120
million credit facility. Effective September 2012, the maturity date was extended from September 2016 to September 2017. This facility supports certain tax-exempt financings of Virginia Power.
NOTE 17. LONG-TERM DEBT
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
2012 Weighted- average Coupon(1) |
|
|
2012 |
|
|
2011 |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
Virginia Electric and Power Company: |
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
1.14 |
% |
|
|
454 |
|
|
|
454 |
|
1.5% to 6.5%, due 2017 to 2040 |
|
|
3.65 |
% |
|
|
508 |
|
|
|
533 |
|
Virginia Electric and Power Company total principal |
|
|
|
|
|
$ |
6,676 |
|
|
$ |
6,866 |
|
Securities due within one year |
|
|
4.88 |
% |
|
|
(418 |
) |
|
|
(616 |
) |
Unamortized discount and premium, net |
|
|
|
|
|
|
(7 |
) |
|
|
(4 |
) |
Virginia Electric and Power Company total long-term debt |
|
|
|
|
|
$ |
6,251 |
|
|
$ |
6,246 |
|
Dominion Resources, Inc.: |
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
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 |
|
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) |
|
|
|
|
|
|
6,676 |
|
|
|
6,866 |
|
Dominion Resources, Inc. total principal |
|
|
|
|
|
$ |
18,988 |
|
|
$ |
18,745 |
|
Fair value hedge valuation(10) |
|
|
|
|
|
|
93 |
|
|
|
105 |
|
Securities due within one year(11) |
|
|
4.53 |
% |
|
|
(2,223 |
) |
|
|
(1,479 |
) |
Unamortized discount and premium, net |
|
|
|
|
|
|
(7 |
) |
|
|
23 |
|
Dominion Resources, Inc. total long-term debt |
|
|
|
|
|
$ |
16,851 |
|
|
$ |
17,394 |
|
(1) |
Represents weighted-average coupon rates for debt outstanding as of December 31, 2012. |
(2) |
These financings relate to certain pollution control equipment at Virginia Powers generating facilities. Certain variable rate tax-exempt financings are
supported by a $120 million credit facility that terminates in September 2017. |
(3) |
At the option of holders, $510 million of Dominions 5.25% senior notes due 2033 and $600 million of Dominions 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. |
(4) |
Convertible into a combination of cash and shares of Dominions 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, 2013 or 2018, these securities are subject to
redemption at 100% of the principal amount plus accrued interest. These senior notes have been callable by Dominion since December 15, 2011. |
(5) |
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. |
(7) |
Juniper notes issued in 2004 and consolidated in October 2011 due to Dominion becoming the primary beneficiary of this VIE. This amount excludes $18 million and $48
million of unamortized premium in 2012 and 2011, respectively. The debt is non-recourse to Dominion and is secured by Junipers assets. |
(8) |
Represents debt associated with Kincaid. The debt is non-recourse to Dominion and is secured by the facilitys assets ($552 million at
December 31, 2012) and revenue. Dominion announced in the third quarter of 2012 that it was pursuing the sale of Kincaid. Dominion anticipates redeeming the notes as a condition to a sale of Kincaid. |
(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 Dominions fixed rate debt. |
(11) |
Includes $23 million of net unamortized premium and fair value hedge valuation in 2012 and $4 million of net unamortized discount in 2011.
|
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, 2012, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 |
|
|
2014 |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
Thereafter |
|
|
Total |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Virginia Power |
|
$ |
418 |
|
|
$ |
17 |
|
|
$ |
211 |
|
|
$ |
476 |
|
|
$ |
679 |
|
|
$ |
4,875 |
|
|
$ |
6,676 |
|
Weighted-average Coupon |
|
|
4.88 |
% |
|
|
7.73 |
% |
|
|
5.39 |
% |
|
|
5.27 |
% |
|
|
5.44 |
% |
|
|
5.26 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Secured Senior Notes |
|
$ |
852 |
|
|
$ |
15 |
|
|
$ |
18 |
|
|
$ |
20 |
|
|
$ |
22 |
|
|
$ |
60 |
|
|
$ |
987 |
|
Unsecured Senior Notes |
|
|
1,090 |
|
|
|
1,065 |
|
|
|
960 |
|
|
|
1,351 |
|
|
|
1,303 |
|
|
|
9,278 |
|
|
|
15,047 |
|
Tax-Exempt Financings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
75 |
|
|
|
1,227 |
|
|
|
1,321 |
|
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts |
|
|
258 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
268 |
|
Enhanced Junior Subordinated Notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,365 |
|
|
|
1,365 |
|
Total |
|
$ |
2,200 |
|
|
$ |
1,080 |
|
|
$ |
978 |
|
|
$ |
1,390 |
|
|
$ |
1,400 |
|
|
$ |
11,940 |
|
|
$ |
18,988 |
|
Weighted-average Coupon |
|
|
4.53 |
% |
|
|
3.99 |
% |
|
|
4.50 |
% |
|
|
4.27 |
% |
|
|
4.60 |
% |
|
|
5.54 |
% |
|
|
|
|
Dominions and Virginia Powers short-term credit facilities and long-term debt agreements
contain customary covenants and default provisions. As of December 31, 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, 2012, Dominion had $82 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominions 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, 2012, the conversion rate had been adjusted to 29.3863
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, Dominions 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 Dominions diluted EPS when the conversion price is lower than the average market
price of Dominions 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 Dominions common stock under any of the following circumstances:
(1) |
The closing price of Dominions 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 Moodys is below Baa3 and by Standard & Poors is below BBB- or the ratings are discontinued for
any reason. |
The senior notes were eligible for conversion during 2012 since the closing price of
Dominions common stock was equal to 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days of each quarter. During 2012, approximately $61 million of the contingent convertible senior
notes were converted by holders. As of December 31, 2012, the closing price of Dominions common stock was equal to $40.84 per share or higher for at least 20 out of the last 30 consecutive trading days; therefore, the senior notes are
eligible for conversion during the first quarter of 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 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 established several subsidiary capital trusts, each as a finance subsidiary of Dominion, which holds 100% of the voting
interests. The trusts sold capital securities representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trusts. In exchange for the funds realized from the sale of the capital securities and common securities
that represent the remaining 3% beneficial ownership interest in the assets held by the capital trusts, Dominion issued various junior subordinated notes. The junior subordinated notes constitute 100% of each capital trusts assets. Each trust
must redeem its capital securities when their respective junior subordinated notes are repaid at maturity or if redeemed prior to maturity.
In 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 December 1, 2027. At December 31, 2012, the debentures were included in securities
due within one year in the Consolidated Balance Sheets. In January 2013, Dominion redeemed the securities at a price of $1,019.58 per capital security plus accrued and unpaid distributions.
The following table provides summary information about the capital securities and junior subordinated notes outstanding as of
December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date Established |
|
Capital Trusts |
|
Units |
|
|
Rate |
|
|
Capital Securities Amount |
|
|
Common Securities Amount |
|
|
|
|
|
(thousands) |
|
|
|
|
|
(millions) |
|
December 1997 |
|
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 |
|
Junior subordinated notes/debentures held as assets by each capital trust were as follows:
(1) |
$258 millionDominion Resources, Inc. 7.83% Debentures due 12/1/2027. |
(2) |
$10 millionDominion Resources, Inc. 8.4% Debentures due 1/15/2031. |
Interest charges related to Dominions junior subordinated notes payable to affiliated trusts were $21 million for the years ended December 31, 2012, 2011 and 2010.
Distribution payments on the capital securities are considered to be fully and unconditionally guaranteed by Dominion. Each guarantee
agreement only provides for the guarantee of distribution payments on the relevant capital securities to the extent that the trust has funds legally and immediately available to make distributions. The trusts ability to pay amounts when they
are due on the capital 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, 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. Beginning September 30, 2011, the September 2006 hybrids 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 underwriters option to purchase additional
notes to cover over-allotments) of 8.375% June 2009 hybrids. The June 2009 hybrids are listed on the NYSE under the symbol DRU.
Dominion may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on
the hybrids are deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period,
Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.
Dominion executed RCCs in connection with its issuance of 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 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, 2012 or 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, 2012 and 2011. Upon involuntary liquidation,
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 Powers 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, 2012:
|
|
|
|
|
|
|
|
|
Dividend |
|
Issued and Outstanding Shares |
|
|
Entitled Per Share Upon Liquidation |
|
|
|
(thousands) |
|
|
|
|
$5.00 |
|
|
107 |
|
|
$ |
112.50 |
|
4.04 |
|
|
13 |
|
|
|
102.27 |
|
4.20 |
|
|
15 |
|
|
|
102.50 |
|
4.12 |
|
|
32 |
|
|
|
103.73 |
|
4.80 |
|
|
73 |
|
|
|
101.00 |
|
7.05 |
|
|
500 |
|
|
|
100.36 |
(1) |
6.98 |
|
|
600 |
|
|
|
100.35 |
(2) |
Flex Money Market Preferred 12/02, Series A |
|
|
1,250 |
|
|
|
100.00 |
(3) |
Total |
|
|
2,590 |
|
|
|
|
|
(1) |
Through 7/31/2013; $100.00 commencing 8/1/2013. |
(2) |
Through 8/31/2013; $100.00 commencing 9/1/2013. |
(3) |
Dividend rate was 6.25% until 3/20/2011. Effective 3/20/11 the rate reset to 6.12% until 3/20/2014 after which the rate will be determined according to periodic
auctions for periods established by Virginia Power at the time of the auction process. |
NOTE 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 Dominions 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 2012, Dominion issued approximately 6.4 million shares of common stock through various programs. Dominion
received cash proceeds of $265 million from the issuance of 5.3 million of such shares through Dominion Direct, employee savings plans, and the exercise of employee stock options.
In January 2012, Dominion filed 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 issue common 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, for
the purpose of retiring short-term demand note borrowings from Dominion.
Shares Reserved for Issuance
At December 31, 2012, Dominion had approximately 48 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
During 2011, Dominion repurchased approximately 13 million shares of common stock for approximately $601 million on the open market, 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, |
|
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, 2012, approximately 32 million shares were available for future grants under these plans.
Dominion
measures and recognizes compensation expense relating to share-based payment transactions over the vesting
period based on the fair value of the equity or liability instruments issued. Dominions results for the years ended December 31, 2012, 2011 and 2010 include $25 million, $39 million,
and $40 million, respectively, of compensation costs and $8 million, $13 million, and $15 million, respectively of income tax benefits related to Dominions stock-based compensation arrangements. Stock-based compensation cost is reported in
other operations and maintenance expense in Dominions Consolidated Statements of Income. Excess tax benefits are classified as a financing cash flow. During the years ended December 31, 2012, 2011 and 2010, Dominion realized $10 million,
$2 million, and $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, 2012, 2011 and 2010. No options were granted under any plan
in 2012, 2011 or 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
Weighted - average Exercise Price |
|
|
Weighted - average Remaining Contractual Life |
|
|
Aggregated Intrinsic Value(1) |
|
|
|
(thousands) |
|
|
|
|
|
(years) |
|
|
(millions) |
|
Outstanding and exercisable at December 31, 2009 |
|
|
3,822 |
|
|
$ |
31.25 |
|
|
|
|
|
|
|
29 |
|
Exercised |
|
|
(1,983 |
) |
|
$ |
30.81 |
|
|
|
|
|
|
$ |
22 |
|
Forfeited/expired |
|
|
(29 |
) |
|
$ |
29.84 |
|
|
|
|
|
|
|
|
|
Outstanding and exercisable at December 31, 2010 |
|
|
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 Dominions stock. |
Dominion issues new shares to satisfy stock option exercises. Dominion received cash proceeds from the exercise of stock options of
approximately $19 million, $38 million, and $63 million in the years ended December 31, 2012, 2011 and 2010, respectively.
RESTRICTED STOCK
Restricted stock grants are made to officers under Dominions LTIP and may also be granted to certain key contributors from time to time. The fair
value of Dominions restricted stock awards is equal to the market price of Dominions 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, 2012, 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
Weighted - average Grant Date Fair Value |
|
|
|
(thousands) |
|
|
|
|
Nonvested at December 31, 2009 |
|
|
1,484 |
|
|
$ |
39.88 |
|
Granted |
|
|
463 |
|
|
|
38.80 |
|
Vested |
|
|
(618 |
) |
|
|
43.54 |
|
Cancelled and forfeited |
|
|
(39 |
) |
|
|
36.92 |
|
Converted from goal-based stock to restricted stock |
|
|
186 |
|
|
|
40.84 |
|
Nonvested at December 31, 2010 |
|
|
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, 2012, unrecognized compensation cost related to nonvested restricted stock
awards totaled $23 million and is expected to be recognized over a weighted-average period of 2.1 years. The fair value of restricted stock awards that vested was $30 million, $28 million, and $26 million in 2012, 2011 and 2010, respectively.
Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion stock and the
applicable federal, state and local tax withholding rates.
GOAL-BASED STOCK
Goal-based stock awards are granted under Dominions LTIP to officers who have not achieved a certain targeted level of share ownership, in lieu of
cash-based performance grants. Goal-based stock awards may also be made to certain key non-officer employees from time to time. Current outstanding goal-based shares include awards granted to officers in February 2011 and February 2012.
The issuance of awards is based on the achievement of two performance metrics during a two-year period, including TSR relative to that of
a peer group of 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 Dominions stock on the date of grant. Goal-based stock
awards granted to key non-officer employees convert to restricted stock at the end
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 2009 grants ended on December 31, 2010, the
CGN Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 132 thousand shares of the outstanding goal-based stock awards granted in April 2009 were converted to
168 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2012. For awards to officers, 20 thousand shares of the outstanding goal-based stock awards were converted to 25 thousand
non-restricted shares and issued to the officers.
After the performance period for the April 2010 grants ended on
December 31, 2011, the CGN Committee determined the actual performance against metrics established for those awards. For awards to officers, 9 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, 2012, 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
Targeted Number of Shares |
|
|
Weighted
- average Grant Date Fair Value |
|
|
|
(thousands) |
|
|
|
|
Nonvested at December 31, 2009 |
|
|
323 |
|
|
$ |
36.12 |
|
Granted |
|
|
9 |
|
|
|
37.46 |
|
Vested |
|
|
(16 |
) |
|
|
39.31 |
|
Cancelled and forfeited |
|
|
(8 |
) |
|
|
30.99 |
|
Converted from goal-based stock to restricted stock |
|
|
(147 |
) |
|
|
40.84 |
|
Nonvested at December 31, 2010 |
|
|
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, 2012, the targeted number of shares expected to be issued under the February 2011 and
February 2012 awards was approximately 4 thousand. In January 2013, the CGN Committee determined the actual performance against metrics established for the February 2011 awards with a performance period that ended December 31, 2012. Based on
that determination, the total number of shares to be issued under the February 2011 goal-based stock awards was approximately 2 thousand.
As of December 31, 2012, unrecognized compensation cost related to nonvested goal-based stock awards was not material.
CASH-BASED PERFORMANCE GRANTS
Cash-based performance grants are made to Dominions officers under Dominions 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 2009 was $11 million, but the actual payout of the award in February 2011 determined by the CGN Committee was $14 million ($11 million of which was paid in December
2010), based on the level of performance metrics achieved.
In February 2010, a cash-based performance grant was made to
officers. A portion of the grant, representing $14 million was paid in December 2011, 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, 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 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, 2012, the Virginia Commission had not restricted the payment of dividends by Virginia Power.
Certain agreements associated with Dominions and Virginia Powers credit facilities contain restrictions on the ratio of debt
to total capitalization. These limitations did not restrict Dominions or Virginia Powers ability to pay dividends or receive dividends from their subsidiaries at December 31, 2012.
See Note 17 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest
payments on junior subordinated notes.
NOTE 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
employees compensation. Dominions funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension program also provides benefits to
certain retired executives under a company-sponsored nonqualified employee benefit plan. The nonqualified plan is funded through contributions to a grantor trust. Dominion also provides retiree healthcare and life insurance benefits with annual
employee premiums based on several factors such as age, retirement date and years of service.
Pension 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.
Dominions
pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Aggregate actual returns for Dominions pension and other postretirement plan assets were $743 million in 2012 and $273 million in
2011, versus expected returns of $509 million and $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.
In January 2011, Dominion amended its retiree healthcare and life benefits to change 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. Dominion received a
federal subsidy of $5 million for each of 2012 and 2011. In December 2011, Dominion elected to change its method of receiving the subsidy under Medicare Part D for retiree prescription drug coverage
from the Retiree Drug Subsidy to the EGWP. This change 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 Part D subsidies, in the form of reduced costs rather than a
direct reimbursement.
Funded Status
The following table summarizes the changes in Dominions 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 |
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2012 |
|
|
2011 |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
|
$ |
4,981 |
|
|
$ |
4,490 |
|
|
$ |
1,493 |
|
|
$ |
1,707 |
|
Service cost |
|
|
116 |
|
|
|
108 |
|
|
|
44 |
|
|
|
48 |
|
Interest cost |
|
|
268 |
|
|
|
258 |
|
|
|
79 |
|
|
|
94 |
|
Benefits paid |
|
|
(208 |
) |
|
|
(215 |
) |
|
|
(88 |
) |
|
|
(83 |
) |
Actuarial (gains) losses during the year |
|
|
967 |
|
|
|
340 |
|
|
|
191 |
|
|
|
(210 |
) |
Plan amendments |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
(70 |
) |
Settlements and curtailments |
|
|
|
|
|
|
|
|
|
|
(6 |
) |
|
|
(1 |
) |
Medicare Part D reimbursement |
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
5 |
|
Early Retirement Reimbursement Program |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
Benefit obligation at end of year |
|
$ |
6,125 |
|
|
$ |
4,981 |
|
|
$ |
1,719 |
|
|
$ |
1,493 |
|
Changes in fair value of plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
$ |
5,145 |
|
|
$ |
5,106 |
|
|
$ |
1,042 |
|
|
$ |
1,031 |
|
Actual return on plan assets |
|
|
611 |
|
|
|
247 |
|
|
|
132 |
|
|
|
26 |
|
Employer contributions |
|
|
5 |
|
|
|
7 |
|
|
|
16 |
|
|
|
19 |
|
Benefits paid |
|
|
(208 |
) |
|
|
(215 |
) |
|
|
(34 |
) |
|
|
(34 |
) |
Fair value of plan assets at end of year |
|
$ |
5,553 |
|
|
$ |
5,145 |
|
|
$ |
1,156 |
|
|
$ |
1,042 |
|
Funded status at end of year |
|
$ |
(572 |
) |
|
$ |
164 |
|
|
$ |
(563 |
) |
|
$ |
(451 |
) |
Amounts recognized in the Consolidated Balance Sheets at December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent pension and other postretirement benefit assets |
|
|
701 |
|
|
|
677 |
|
|
|
1 |
|
|
|
4 |
|
Other current liabilities |
|
|
(2 |
) |
|
|
(3 |
) |
|
|
(4 |
) |
|
|
(3 |
) |
Noncurrent pension and other postretirement benefit liabilities |
|
|
(1,271 |
) |
|
|
(510 |
) |
|
|
(560 |
) |
|
|
(452 |
) |
Net amount recognized |
|
$ |
(572 |
) |
|
$ |
164 |
|
|
$ |
(563 |
) |
|
$ |
(451 |
) |
Significant assumptions used to determine benefit obligations as of December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
4.4 |
% |
|
|
5.5 |
% |
|
|
4.4 |
% |
|
|
5.5 |
% |
Weighted average rate of increase for compensation |
|
|
4.21 |
% |
|
|
4.21 |
% |
|
|
4.22 |
% |
|
|
4.22 |
% |
Combined Notes to Consolidated Financial Statements, Continued
The ABO for all of Dominions defined benefit pension plans was $5.5 billion and $4.5
billion at December 31, 2012 and 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 2012, Dominion made no contributions to its qualified defined benefit pension plans and no contributions are currently expected in 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 Dominions subsidiaries fund other postretirement benefit costs through VEBAs. Dominions remaining subsidiaries do not prefund other
postretirement benefit costs but instead pay claims as presented. Dominion expects to contribute approximately $14 million to the Dominion VEBAs in 2013.
Dominion does not expect any pension or other postretirement plan assets to be returned to the Company during 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, |
|
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, |
|
2012(1)
|
|
|
2011 |
|
(millions) |
|
|
|
|
|
|
|
Accumulated benefit obligation |
|
$ |
4,850 |
|
|
|
|
$ |
95 |
|
Fair value of plan assets |
|
|
4,189 |
|
|
|
|
(1) |
The increase from 2011 is primarily due to a decrease in the discount rate.
|
The following benefit payments, which reflect expected future service, as appropriate, are
expected to be paid:
|
|
|
|
|
|
|
|
|
|
|
Estimated Future Benefit Payments |
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
(millions) |
|
|
|
|
|
|
2013 |
|
$ |
231 |
|
|
$ |
89 |
|
2014 |
|
|
245 |
|
|
|
93 |
|
2015 |
|
|
255 |
|
|
|
96 |
|
2016 |
|
|
300 |
|
|
|
100 |
|
2017 |
|
|
334 |
|
|
|
103 |
|
2018-2022 |
|
|
1,749 |
|
|
|
555 |
|
Plan Assets
Dominions 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 Dominions 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 Dominions assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans actual
asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and
other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.
For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.
The fair values of Dominions 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 Dominions 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 |
|
Combined Notes to Consolidated Financial Statements, Continued
The following table presents the changes in Dominions pension and 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) |
|
|
|
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 cost and amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
116 |
|
|
$ |
108 |
|
|
$ |
102 |
|
|
$ |
44 |
|
|
$ |
48 |
|
|
$ |
56 |
|
Interest cost |
|
|
268 |
|
|
|
258 |
|
|
|
266 |
|
|
|
79 |
|
|
|
94 |
|
|
|
101 |
|
Expected return on plan assets |
|
|
(430 |
) |
|
|
(440 |
) |
|
|
(410 |
) |
|
|
(79 |
) |
|
|
(79 |
) |
|
|
(69 |
) |
Amortization of prior service (credit) cost |
|
|
3 |
|
|
|
3 |
|
|
|
3 |
|
|
|
(13 |
) |
|
|
(13 |
) |
|
|
(7 |
) |
Amortization of net actuarial loss |
|
|
132 |
|
|
|
96 |
|
|
|
59 |
|
|
|
6 |
|
|
|
12 |
|
|
|
12 |
|
Settlements and curtailments(1) |
|
|
|
|
|
|
|
|
|
|
136 |
|
|
|
(4 |
) |
|
|
1 |
|
|
|
37 |
|
Special termination
benefits(2) |
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
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 |
|
$ |
786 |
|
|
$ |
534 |
|
|
$ |
95 |
|
|
$ |
139 |
|
|
$ |
(157 |
) |
|
$ |
13 |
|
Prior service (credit) cost |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
(70 |
) |
|
|
|
|
Settlements and curtailments(1) |
|
|
|
|
|
|
|
|
|
|
(50 |
) |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
Less amounts included in net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial loss |
|
|
(132 |
) |
|
|
(96 |
) |
|
|
(59 |
) |
|
|
(6 |
) |
|
|
(12 |
) |
|
|
(12 |
) |
Amortization of prior service credit (cost) |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
13 |
|
|
|
13 |
|
|
|
7 |
|
Total recognized in other comprehensive income and regulatory assets and
liabilities |
|
$ |
651 |
|
|
$ |
435 |
|
|
$ |
(16 |
) |
|
$ |
145 |
|
|
$ |
(227 |
) |
|
$ |
7 |
|
Significant assumptions used to determine periodic cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.5 |
% |
|
|
5.9 |
% |
|
|
6.6 |
% |
|
|
5.5 |
% |
|
|
5.9 |
% |
|
|
6.6 |
% |
Expected long-term rate of return on plan assets |
|
|
8.5 |
% |
|
|
8.5 |
% |
|
|
8.5 |
% |
|
|
7.75 |
% |
|
|
7.75 |
% |
|
|
7.75 |
% |
Weighted average rate of increase for compensation |
|
|
4.21 |
% |
|
|
4.61 |
% |
|
|
4.76 |
% |
|
|
4.22 |
% |
|
|
4.62 |
% |
|
|
4.79 |
% |
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) |
2012 amounts relate to the sale of Salem Harbor. 2010 amounts relate to the sales of Peoples and Dominions Appalachian E&P operations and a workforce
reduction program. |
(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. |
The components of AOCI and regulatory assets and liabilities that have not been recognized
as components of periodic benefit cost are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2012, of the $2.9 billion and $158 million related to pension benefits and other postretirement benefits, $1.8 billion and $69 million,
respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2011, of the $2.2 billion related to pension benefits, $1.4 billion is included in AOCI, with the remainder included in
regulatory assets and liabilities; the $14 million related to other postretirement benefits consists of $16 million included in regulatory assets and liabilities and $(2) million included in AOCI. |
The following table provides the components of AOCI and regulatory assets and liabilities as of December 31, 2012 that are expected
to be amortized as components of periodic benefit cost in 2013:
|
|
|
|
|
|
|
|
|
|
|
Pension
Benefits |
|
|
Other
Postretirement Benefits |
|
(millions) |
|
|
|
|
|
|
Net actuarial loss |
|
$ |
185 |
|
|
$ |
9 |
|
Prior service (credit) cost |
|
|
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 long term historic returns as well as historic risk premiums for various asset classes;
|
|
|
|
Expected future risk premiums, asset volatilities and correlations; |
|
|
|
Forecasts of an independent investment advisor; |
|
|
|
Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; and
|
|
|
|
Investment allocation of plan assets. |
Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans.
Assumed healthcare cost trend rates have a significant effect on the amounts reported for
Dominions 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 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 Dominions 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 2012, 2011 and 2010, Dominion recognized $40
million, $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 that provides benefits to
multiple Dominion subsidiaries. Retirement benefits payable under this plan are based primarily on years of service, age and the employees compensation. As a participating employer, Virginia Power is subject to Dominions funding policy,
which is to contribute annually an amount that is in accordance with the provisions of ERISA. During 2012, Virginia Power made no contributions to the plan and no contributions are currently expected in 2013. Virginia Powers net periodic
pension cost related to this pension plan was $72 million, $50 million and $84 million in 2012, 2011 and 2010, respectively. Employee compensation is the basis for determining Virginia Powers 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 Powers net periodic benefit cost related to
this plan was $13 million, $23 million and $59 million in 2012, 2011 and 2010, respectively. Employee headcount is the basis for determining Virginia Powers 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 made no contributions to the VEBA in
2012 and does not expect to contribute to the VEBA in 2013.
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 Powers 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 $15 million were incurred in
2012 and $14 million in each of 2011 and 2010.
NOTE 22. COMMITMENTS AND CONTINGENCIES
As a result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in legal proceedings
before various courts and are periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of
damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of
possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the
Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in
excess of the accrued liability (if any) for such matters. 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 below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material
effect on Dominions or Virginia Powers 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 nations 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 Dominions and Virginia Powers facilities are subject to the CAAs 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 NOx emissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a
ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions
that cross state lines. CSAPR established new SO2 and
NOx emissions cap and trade programs that were completely
independent of the current ARP. Specifically, CSAPR required reductions in SO2 and NOx
emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NOx emissions caps, NOx emissions caps during the ozone season (May 1 through September 30) and annual SO2 emission caps with differing requirements for two groups of affected states.
Following numerous petitions by industry participants for review and 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 courts 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 Dominions
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.
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 EPAs 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 EPAs 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, Millstones 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.
SOLID AND HAZARDOUS WASTE
The
CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which
hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present
owners and operators of contaminated sites, can be jointly, severally, and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup,
voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.
From time to time, Dominion 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
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 partys 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 LEGISLATION AND 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 Dominions 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 Dominions 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 RGGIs 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 Dominions 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 Dominions 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 staffs 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
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 NRCs 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, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 |
|
|
2014 |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
Thereafter |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased electric
capacity(1) |
|
$ |
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, 2012, the present value of Virginia Powers
total commitment for capacity payments is $1.4 billion. Capacity payments totaled $337 million, $338 million, and $344 million, and energy payments totaled $214 million, $275 million, and $303 million for 2012, 2011 and 2010, respectively.
|
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, 2012 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 |
|
|
2014 |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
Thereafter |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
$ |
79 |
|
|
$ |
72 |
|
|
$ |
64 |
|
|
$ |
55 |
|
|
$ |
63 |
|
|
$ |
161 |
|
|
$ |
494 |
|
Virginia Power |
|
$ |
26 |
|
|
$ |
24 |
|
|
$ |
19 |
|
|
$ |
15 |
|
|
$ |
11 |
|
|
$ |
26 |
|
|
$ |
121 |
|
Rental expense for Dominion totaled $112 million, $155 million, and $171 million for 2012, 2011 and 2010,
respectively. Rental expense for Virginia Power totaled $48 million, $50 million, and $50 million for 2012, 2011, and 2010, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated
Statements of Income.
Nuclear Operations
NUCLEAR DECOMMISSIONINGMINIMUM 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 2012 calculation for the NRC minimum financial assurance amount, aggregated for
Dominions and Virginia Powers nuclear units, excluding joint owners assurance amounts, was $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 2012 NRC minimum financial assurance amounts shown were calculated using preliminary December 31, 2012 U.S. Bureau of Labor Statistics
indices. Dominion believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also
believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover 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 complete 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, 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 Dominions and Virginia Powers nuclear units is as follows:
|
|
|
|
|
|
|
Coverage |
|
(billions) |
|
|
|
Dominion |
|
|
|
|
Millstone |
|
$ |
2.75 |
|
Kewaunee |
|
|
1.80 |
|
Virginia Power(1) |
|
|
|
|
Surry |
|
$ |
2.55 |
|
North Anna |
|
|
2.55 |
|
(1) |
Surry and North Anna share a blanket property limit of $1 billion.
|
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. Dominions and Virginia Powers maximum retrospective premium assessment for the current policy period is $89 million and $48 million, respectively.
Based on the severity of the incident, the Board of Directors of NEIL 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. Dominions and
Virginia Powers maximum retrospective premium assessment for the current policy period is $33 million and $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, Kewaunees accidental outage policy for replacement power costs has been cancelled, and Kewaunees property coverage of $1.8 billion did not change. The cancellation of
Kewaunees accidental outage policy for replacement power costs lowered Dominions retrospective premium assessment from $33 million to $30 million.
ODEC, a part owner of North Anna, and Massachusetts Municipal Wholesale Electric Company and Green Mountain Power Corporation, part owners of Millstones Unit 3, are responsible to Dominion and
Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.
SPENT NUCLEAR FUEL
Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent
fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by 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 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 for 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 recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery
from the DOE. Dominions receivables for spent nuclear fuel-related costs totaled $36 million and $102 million at December 31, 2012 and 2011, respectively. Virginia Powers receivables for spent nuclear fuel-related costs totaled $26
million and $76 million at December 31, 2012 and 2011, respectively. The Companies will continue to manage their spent fuel until it is accepted by the DOE.
Guarantees, Surety Bonds and Letters of Credit
DOMINION
At December 31, 2012, Dominion had issued $92 million of guarantees, primarily to support equity method investees. No significant amounts
related to these guarantees have been recorded. As of December 31, 2012, Dominions exposure under these guarantees was $62 million, primarily related to certain reserve requirements associated with non-recourse financing.
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, 2012, Dominions maximum remaining cumulative exposure under these
equity funding agreements is $107 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million.
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 Dominions consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of
its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion currently believes it is
unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries obligations.
At December 31, 2012, Dominion had issued the following subsidiary guarantees:
|
|
|
|
|
|
|
|
|
|
|
Stated Limit |
|
|
Value(1)
|
|
(millions) |
|
|
|
|
|
|
Subsidiary debt(2) |
|
$ |
363 |
|
|
$ |
363 |
|
Commodity transactions(3) |
|
|
2,939 |
|
|
|
377 |
|
Nuclear obligations(4) |
|
|
231 |
|
|
|
77 |
|
Other(5) |
|
|
673 |
|
|
|
98 |
|
Total |
|
$ |
4,206 |
|
|
$ |
915 |
|
(1) |
Represents the estimated portion of the guarantees stated limit that is utilized as of December 31, 2012 based upon prevailing economic conditions
and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominions subsidiaries, the value includes the recorded amount. |
(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 Dominions
nuclear insurance programs and guarantees for a DEI subsidiarys and Virginia Powers commitment to buy nuclear fuel. Excludes Dominions 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, 2012 Dominion had purchased $163 million of surety bonds and authorized the issuance of letters of credit by financial institutions of $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, 2012, Virginia Power had
issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. Virginia Power had also purchased $67 million of surety bonds for various purposes, including providing workers compensation coverage, and
authorized the issuance of letters of credit by financial institutions of $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, 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 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, 2012 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
commer-
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. Dominion does not believe that this geographic
concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion is not exposed to a significant concentration of credit risk for receivables arising from
electric and gas utility operations.
Dominions 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, 2012, Dominions credit exposure totaled $512 million. Of this amount, investment grade counterparties, including those internally rated, represented 77%. One counterparty exposure represents 11% of Dominions 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 Powers 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 Powers exposure to potential concentrations of credit risk results primarily from sales to wholesale customers.
Virginia Powers 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, 2012, Virginia Powers exposure to potential concentrations of credit risk was not considered material.
CREDIT-RELATED CONTINGENT PROVISIONS
The majority of Dominions 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, 2012 and 2011, Dominion would
have been required to post an additional $110 million and $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 $4 million in collateral at December 31, 2012 and $110 million in collateral, including $4 million of letters of credit at December 31, 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, 2012 and 2011 was $163 million and $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 7 for further information about derivative instruments.
NOTE 24. RELATED-PARTY TRANSACTIONS
Virginia Power engages in related-party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Powers
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 Dominions consolidated federal income tax
return and participates in certain Dominion benefit plans. A discussion of significant related-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, to manage commodity price risks associated with purchases of
natural gas.
As of December 31, 2012 and 2011, Virginia Powers derivative liabilities with affiliates were not
material.
DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to
Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage. Presented below are significant transactions with DRS and other affiliates:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Commodity purchases from affiliates |
|
$ |
368 |
|
|
$ |
376 |
|
|
$ |
373 |
|
Services provided by affiliates |
|
|
399 |
|
|
|
393 |
|
|
|
469 |
|
Services provided to affiliates |
|
|
19 |
|
|
|
21 |
|
|
|
19 |
|
In the fourth quarter of 2011, a subsidiary of Virginia Power purchased nuclear fuel-related inventory from an affiliate
for $39 million for 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
Powers outstanding borrowings, net of repayments, under the Dominion 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 Powers borrowings from Dominion were immaterial for the years ended December 31, 2012, 2011 and 2010.
In 2010 Virginia Power issued 33,013 shares of its common stock to Dominion for approximately $1 billion, for the purpose of retiring short-term demand note borrowings from Dominion. There were no such
issuances of common stock in 2011 and 2012.
NOTE 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 the operations that are expected to be or
are currently discontinued, which are discussed in Note 3. In addition, Corporate and Other includes specific items attributable to Dominions 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 2012, Dominion reported after-tax net expense of $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:
|
|
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;
|
|
|
A $467 million ($303 million after-tax) net loss, including impairment charges, primarily resulting from managements decision to cease operations
and begin decommissioning Kewaunee in 2013, attributable to Dominion Generation; |
|
|
An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP; and
|
|
|
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 $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:
|
|
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; |
|
|
A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to
DVP; |
|
|
A $66 million ($39 million after-tax) loss from the operations of Kewaunee, attributable to Dominion Generation; |
|
|
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
|
|
|
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:
|
|
A $2.5 billion ($1.4 billion after-tax) benefit resulting from the gain on the sale of substantially all of Dominions Appalachian E&P
operations net of charges related to the divestiture, attributable to Dominion Energy; partially offset by |
|
|
A $331 million ($202 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program,
attributable to: |
|
|
|
DVP ($67 million after-tax); |
|
|
|
Dominion Energy ($24 million after-tax); and |
|
|
|
Dominion Generation ($111 million after-tax); |
|
|
A $158 million ($103 million after-tax) loss from the discontinued operations of State Line and Salem Harbor; and |
|
|
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 segment. |
Combined Notes to Consolidated Financial Statements, Continued
The following table presents segment information pertaining to Dominions
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
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 |
|
|
$ |
7,735 |
|
|
$ |
2,335 |
|
|
$ |
19 |
|
|
$ |
1,225 |
|
|
$ |
14,927 |
|
Intersegment revenue |
|
|
207 |
|
|
|
413 |
|
|
|
1,166 |
|
|
|
750 |
|
|
|
(2,536 |
) |
|
|
|
|
Total operating revenue |
|
|
3,820 |
|
|
|
8,148 |
|
|
|
3,501 |
|
|
|
769 |
|
|
|
(1,311 |
) |
|
|
14,927 |
|
Depreciation, depletion and amortization |
|
|
353 |
|
|
|
443 |
|
|
|
210 |
|
|
|
29 |
|
|
|
|
|
|
|
1,035 |
|
Equity in earnings of equity method investees |
|
|
|
|
|
|
11 |
|
|
|
21 |
|
|
|
10 |
|
|
|
|
|
|
|
42 |
|
Interest income |
|
|
12 |
|
|
|
45 |
|
|
|
12 |
|
|
|
92 |
|
|
|
(90 |
) |
|
|
71 |
|
Interest and related charges |
|
|
158 |
|
|
|
179 |
|
|
|
85 |
|
|
|
494 |
|
|
|
(90 |
) |
|
|
826 |
|
Income taxes |
|
|
277 |
|
|
|
756 |
|
|
|
302 |
|
|
|
777 |
|
|
|
|
|
|
|
2,112 |
|
Loss from discontinued operations, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(258 |
) |
|
|
|
|
|
|
(258 |
) |
Net income attributable to Dominion |
|
|
448 |
|
|
|
1,263 |
|
|
|
475 |
|
|
|
622 |
|
|
|
|
|
|
|
2,808 |
|
Capital expenditures |
|
|
1,038 |
|
|
|
1,742 |
|
|
|
613 |
|
|
|
29 |
|
|
|
|
|
|
|
3,422 |
|
(1) |
Segment information has been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3. |
At December 31, 2012, 2011, and 2010, none of Dominions long-lived assets and no significant percentage of its operating
revenues were associated with international operations.
VIRGINIA POWER
The majority of Virginia Powers revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia
Powers 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:
|
|
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:
|
|
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; |
|
|
A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to
DVP; and |
|
|
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:
|
|
A $202 million ($123 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program,
attributable to: |
|
|
|
DVP ($63 million after-tax); and |
|
|
|
Dominion Generation ($60 million after-tax).
|
The following table
presents segment information pertaining to Virginia Powers operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
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 |
|
Depreciation and amortization |
|
|
344 |
|
|
|
327 |
|
|
|
|
|
|
|
|
|
|
|
671 |
|
Interest income |
|
|
11 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
15 |
|
Interest and related charges |
|
|
158 |
|
|
|
189 |
|
|
|
|
|
|
|
|
|
|
|
347 |
|
Income taxes |
|
|
228 |
|
|
|
385 |
|
|
|
(71 |
) |
|
|
|
|
|
|
542 |
|
Net income (loss) |
|
|
377 |
|
|
|
630 |
|
|
|
(155 |
) |
|
|
|
|
|
|
852 |
|
Capital expenditures |
|
|
1,035 |
|
|
|
1,199 |
|
|
|
|
|
|
|
|
|
|
|
2,234 |
|
Combined Notes to Consolidated Financial Statements, Continued
NOTE 26. QUARTERLY FINANCIAL AND COMMON STOCK
DATA (UNAUDITED)
A summary of Dominions and Virginia Powers quarterly results of operations for the years ended December 31, 2012
and 2011 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(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 |
|
(millions, except per share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
3,983 |
|
|
$ |
3,288 |
|
|
$ |
3,745 |
|
|
$ |
3,129 |
|
|
$ |
14,145 |
|
Income from operations |
|
|
993 |
|
|
|
733 |
|
|
|
828 |
|
|
|
340 |
|
|
|
2,894 |
|
Net income including noncontrolling interests |
|
|
483 |
|
|
|
340 |
|
|
|
396 |
|
|
|
207 |
|
|
|
1,426 |
|
Income from continuing operations(1) |
|
|
504 |
|
|
|
341 |
|
|
|
388 |
|
|
|
200 |
|
|
|
1,433 |
|
Income (loss) from discontinued operations(1) |
|
|
(25 |
) |
|
|
(5 |
) |
|
|
4 |
|
|
|
1 |
|
|
|
(25 |
) |
Net income attributable to Dominion |
|
|
479 |
|
|
|
336 |
|
|
|
392 |
|
|
|
201 |
|
|
|
1,408 |
|
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) |
|
$ |
46.56 - 42.06 |
|
|
$ |
48.55 - 43.27 |
|
|
$ |
51.44 - 44.50 |
|
|
$ |
53.59 - 48.21 |
|
|
$ |
53.59 - 42.06 |
|
(1) |
Amounts attributable to Dominions 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. |
Dominions 2012 results include the impact of the following significant items:
|
|
Fourth quarter results include a $1.0 billion after-tax impairment charge to write down Brayton Points and Kincaids long-lived assets to
their estimated fair value. |
|
|
Third quarter results include a $281 million after-tax net loss, including impairment charges, primarily resulting from managements decision to
cease operations and begin decommissioning Kewaunee in 2013. |
Dominions 2011 results include the impact
of the following significant item:
|
|
Fourth quarter results include a $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. |
VIRGINIA POWER
Virginia Powers quarterly results of operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
Second Quarter |
|
|
Third Quarter |
|
|
Fourth Quarter |
|
|
Year |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
1,754 |
|
|
$ |
1,756 |
|
|
$ |
2,086 |
|
|
$ |
1,630 |
|
|
$ |
7,226 |
|
Income from operations |
|
|
468 |
|
|
|
361 |
|
|
|
746 |
|
|
|
417 |
|
|
|
1,992 |
|
Net income |
|
|
243 |
|
|
|
172 |
|
|
|
415 |
|
|
|
220 |
|
|
|
1,050 |
|
Balance available for common stock |
|
|
239 |
|
|
|
168 |
|
|
|
411 |
|
|
|
216 |
|
|
|
1,034 |
|
2011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
1,757 |
|
|
$ |
1,757 |
|
|
$ |
2,177 |
|
|
$ |
1,555 |
|
|
$ |
7,246 |
|
Income from operations |
|
|
511 |
|
|
|
471 |
|
|
|
568 |
|
|
|
55 |
|
|
|
1,605 |
|
Net income |
|
|
278 |
|
|
|
241 |
|
|
|
297 |
|
|
|
6 |
|
|
|
822 |
|
Balance available for common stock |
|
|
274 |
|
|
|
237 |
|
|
|
293 |
|
|
|
1 |
|
|
|
805 |
|
Virginia Powers 2012 results include the impact of the following significant item:
|
|
Second quarter results include a $42 million after-tax charge reflecting restoration costs associated with damage caused by late June summer storms.
|
Virginia Powers 2011 results include the impact of the following significant item:
|
|
Fourth quarter results include a $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 power stations. |
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None.
Item 9A. Controls
and Procedures
DOMINION
Senior management, including Dominions CEO and CFO, evaluated the effectiveness of Dominions disclosure controls and procedures as of the end
of the period covered by this report. Based on this evaluation process, Dominions CEO and CFO have concluded that Dominions disclosure controls and procedures are effective. There were no changes in Dominions internal control over
financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominions internal control over financial reporting.
MANAGEMENTS ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL
REPORTING
Management of Dominion Resources, Inc. (Dominion) understands and accepts responsibility for Dominions
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 Dominions 2012 Annual Report to contain a
managements 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, 2012, Dominion makes the following assertions:
Management is
responsible for establishing and maintaining effective internal control over financial reporting of Dominion.
There are
inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with
respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Dominions internal control over financial reporting as of December 31, 2012. This assessment was based on criteria for effective internal control over financial
reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion maintained effective internal control
over financial reporting as of December 31, 2012.
Dominions independent registered public accounting firm is
engaged to express an opinion on Dominions internal control over financial reporting, as stated in their report which is included herein.
February 27, 2013
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the internal control over financial reporting of Dominion Resources, Inc. and subsidiaries (Dominion) as of
December 31, 2012, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Dominions 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 Managements Annual Report on Internal Control over Financial Reporting.
Our responsibility is to express an opinion on Dominions 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 companys
internal control over financial reporting is a process designed by, or under the supervision of, the companys principal executive and principal financial officers, or persons performing similar functions, and effected by the companys
Board of Directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes
in accordance with generally accepted accounting principles. A companys 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 companys 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,
2012, based on the criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended
December 31, 2012 of Dominion and our report dated February 27, 2013, expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 2013
VIRGINIA POWER
Senior management, including Virginia Powers CEO and CFO, evaluated the effectiveness of Virginia Powers disclosure controls and procedures as of the end of the period covered by this report.
Based on this evaluation process, Virginia Powers CEO and CFO have concluded that Virginia Powers disclosure controls and procedures are effective. There were no changes in Virginia Powers internal control over financial reporting
that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Powers internal control over financial reporting.
MANAGEMENTS ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL
REPORTING
Management of Virginia Electric and Power Company (Virginia Power) understands and accepts responsibility for
Virginia Powers 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 Powers Audit Committee and meets periodically with the independent registered public
accounting firm, the internal auditors and management to discuss Virginia Powers 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
Powers 2012 Annual Report to contain a managements 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, 2012, Virginia Power makes the following assertions:
Management is responsible
for establishing and maintaining effective internal control over financial reporting of Virginia Power.
There are inherent
limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to
financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.
Management evaluated Virginia Powers internal control over financial reporting as of December 31, 2012. This assessment was based on criteria for effective internal control over financial
reporting described in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal
control over financial reporting as of December 31, 2012.
This annual report does not include an attestation report
of Virginia Powers registered public accounting firm regarding internal control over financial reporting. Managements report is not subject to attestation by Virginia Powers independent registered public accounting firm pursuant to
a permanent exemption under the Dodd-Frank Act.
February 27, 2013
Item 9B. Other Information
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 was
February 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 Dominions 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.
Part III
Item 10. Directors, Executive Officers and Corporate Governance
DOMINION
The following information for Dominion is incorporated by reference from the
Dominion 2013 Proxy Statement, which will be filed on or around March 19, 2013:
|
|
Information regarding the directors required by this item is found under the heading Election of Directors. |
|
|
Information regarding compliance with Section 16 of the Securities Exchange Act of 1934, as amended, required by this item is found under the
heading Section 16(a) Beneficial Ownership Reporting Compliance. |
|
|
Information regarding the Dominion Audit Committee Financial expert(s) required by this item is found under the headings Director Independence
and Committees and Meeting Attendance. |
|
|
Information regarding the Dominion Audit Committee required by this item is found under the headings The Audit Committee Report and
Committees and Meeting Attendance. |
|
|
Information regarding Dominions Code of Ethics required by this item is found under the heading Corporate Governance and Board Matters.
|
The information concerning the executive officers of Dominion required by this item is included in Part I of
this Form 10-K under the caption Executive Officers of Dominion. Each executive officer of Dominion is elected annually.
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 (58) |
|
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 date. Mr. Farrell has served as a director of Altria Group, Inc. since 2008. Mr. Farrells qualifications to serve as a director include his 17 years of industry experience as well as his legal expertise, having served as General Counsel for Dominion and Virginia Power and as a
practicing attorney with a private firm. He is chairman of the Institute of Nuclear Power Operations and a member of the Board of Directors of the Edison Electric Institute through which he actively represents the interests of Dominion, Virginia
Power and the energy sector. Mr. Farrell also has extensive community and public interest involvement and serves or has served on many non-profit and university foundations. |
|
|
1999 |
|
Mark F. McGettrick (55) |
|
Executive Vice President and CFO of Virginia Power and Dominion from June 2009 to date; President and COO-Generation of Virginia Power from
February 2006 to May 2009; Executive Vice President of Dominion from April 2006 to May 2009. Mr. McGettricks 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 Board of Directors of the Dominion
Foundation. Mr. McGettrick also has community and public interest involvement and serves or has served on many non-profit foundations and boards. |
|
|
2009 |
|
Steven A. Rogers (51) |
|
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 December 2012. Mr. Rogers qualifications to serve as a director include his 17 years of industry experience, prior work with Deloitte & Touche LLP and his former membership in the FASBs Financial Accounting
Standards Advisory Committee. Mr. Rogers also has community and public interest involvement and serves or has served on many non-profit foundations and boards. |
|
|
2007 |
|
(1) |
Any service listed for Dominion and DRS reflects service at a parent, subsidiary or affiliate. Virginia Power is a wholly-owned subsidiary of Dominion. DRS is an
affiliate of Virginia Power and is also a subsidiary of Dominion. |
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 (58) |
|
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 date. |
Mark F. McGettrick (55) |
|
Executive Vice President and CFO of Virginia Power and Dominion from June 2009 to date; President and COO-Generation of Virginia Power from February 2006 to May 2009; Executive Vice
President of Dominion from April 2006 to May 2009. |
Paul D. Koonce (53) |
|
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 February 2013. |
David A. Christian (58) |
|
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 2009. |
David A. Heacock (55) |
|
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
President-DVP of Virginia Power from October 2007 to May 2008. |
Robert M. Blue (45) |
|
Senior Vice President-Law, Public Policy and Environment of Virginia Power and Dominion from January 2011 to date; Senior Vice President-Public Policy and Environment of Dominion from
February 2010 to December 2010; Senior Vice President-Public Policy and Corporate Communications of Dominion from May 2008 to January 2010; Vice President-State and Federal Affairs of DRS from September 2006 to May 2008. |
Ashwini Sawhney (63) |
|
Vice President-Accounting of Virginia Power from April 2006 to date; Vice President-Accounting and Controller (CAO) of Dominion from May 2010 to
date; Vice President and Controller (CAO) of Dominion from July 2009 to May 2010; Vice President and Controller of Dominion from April 2007 to June 2009. |
(1) |
Any service listed for Dominion and DRS reflects services at a parent, subsidiary or affiliate. |
Section 16(a) Beneficial Ownership Reporting Compliance
To Virginia Powers knowledge, for the fiscal year ended December 31, 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 Powers Audit Committee
and is comprised entirely of executive officers of Virginia Power or Dominion. Virginia Powers 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 were 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 Dominions 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 Powers Code of Ethics will be posted on the
Dominion website.
Item 11. Executive Compensation
DOMINION
The following information
about Dominion is contained in the 2013 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the headings Compensation Discussion and Analysis and Executive Compensation;
the information regarding Compensation Committee interlocks contained under the heading Compensation Committee Interlocks and Insider Participation; the Compensation, Governance and Nominating Committee Report; and the
information regarding director compensation contained under the heading Non-Employee Director Compensation.
VIRGINIA POWER
COMPENSATION COMMITTEE REPORT
In preparation
for the filing of Virginia Powers Annual Report on Form 10-K, Dominions CGN Committee reviewed and discussed the following CD&A with management and has recommended to the Board of Directors of Virginia Power that the CD&A be
included in Virginia Powers Annual Report on Form 10-K for the year ended December 31, 2012.
Robert S. Jepson, Jr., Chairman
William P. Barr
John W. Harris
Mark J. Kington
David A. Wollard
INTRODUCTION
Virginia Power is a wholly-owned subsidiary of Dominion. Virginia Powers 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 Powers Board is not independent, there is not a separate compensation committee at the Virginia Power level. Instead, Virginia Powers Board depends on the
advice and recommendations of Dominions CGN Committee which is comprised of independent directors. Virginia Powers Board approves all compensation paid to Virginia Powers executive officers based on Dominions CGN Committee
recommendations.
None of Virginia Powers directors receive any compensation for services they provide as 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 Dominions CGN Committee, Dominions Board of
Directors or Virginia Powers 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 Dominions overall compensation program.
COMPENSATION DISCUSSION AND ANALYSIS
This CD&A provides a detailed explanation of the objectives and principles that underlie Dominions executive compensation program, its elements and the way performance is measured, evaluated and
rewarded. It also describes Dominions compensation decision-making process. Dominions executive compensation program is designed to pay for performance and plays an important role in Dominions success by linking a significant
amount of compensation to the achievement of performance goals.
The program and processes generally apply to all of
Dominions officers, but this discussion and analysis focuses primarily on compensation for the NEOs of Virginia Power. During 2012, Virginia Powers NEOs were:
|
|
Thomas F. Farrell II, Chairman and CEO |
|
|
Mark F. McGettrick, Executive Vice President and CFO |
|
|
Paul D. Koonce, President and COODVP |
|
|
David A. Christian, President and COOGeneration |
|
|
David A. Heacock, President and CNO |
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 Powers NEOs, except for Mr. Heacock, are NEOs of Dominion. For the NEOs included in Dominions annual proxy statement, these aggregate amounts are reported in the
Summary Compensation Table and related executive compensation tables. For purposes of reporting each NEOs 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 NEOs
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 Dominions 2013 Proxy Statement. The CD&A below discusses the CGN Committees decisions with respect to each NEOs aggregate compensation for all services
performed for all of Dominion, not just the pro-rated portion attributable to the NEOs services for Virginia Power.
OBJECTIVES OF DOMINIONS EXECUTIVE COMPENSATION
PROGRAM AND THE COMPENSATION DECISION-MAKING PROCESS
Objectives
Dominions 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 Dominions compensation program are to:
|
|
Attract, develop and retain an experienced and highly qualified management team; |
|
|
Motivate and reward superior performance that supports Dominions business and strategic plans and contributes to the long-term success of the
company; |
|
|
Align the interests of management with those of Dominions shareholders and customers by placing a substantial portion of pay at risk through
performance goals that, if achieved, are expected to increase TSR and enhance customer service; |
|
|
Promote internal pay equity; and |
|
|
Reinforce Dominions four core values of safety, ethics, excellence and One DominionDominions term for teamwork.
|
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 Dominions actual performance to its short-term and long-term goals, strategies, and peer companies performance.
Dominions 2012 performance indicates that the design of Dominions compensation program is meeting these objectives. The NEOs
have service with Dominion ranging from 14 to 36 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 Dominions shareholder dollars. Dominion is performing well relative to 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 Committees decisions and policies and Dominions 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 Dominions
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 Dominions 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 NEOs 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 Dominions senior officers, reviews the share ownership guidelines and executive officer
compliance with the guidelines, and establishes compensation programs designed to achieve Dominions objectives.
THE
ROLE OF THE INDEPENDENT COMPENSATION CONSULTANT
The CGN Committee has retained an independent compensation consultant, PM&P, to advise the committee on executive and director compensation matters.
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 2012 executive compensation program:
|
|
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 proposals; and |
|
|
Generally reviewed and offered advice as requested by or on behalf of the CGN Committee regarding other aspects of the executive compensation program,
including best practices and other matters. |
PM&P received compensation from Dominion for consulting
services related only to executive and director compensation, except for $3,300 related to Dominions 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 Dominions 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&Ps work did not raise any conflict of interest.
MANAGEMENTS ROLE IN
DOMINIONS 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 recommendations 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 CGN Committee meeting.
As discussed previously, the CEO is responsible for reviewing senior officer succession plans with the CGN Committee 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
COMPENSATION PEER GROUP
The 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. (See 2012 Performance Grants for additional information.) In the fall of each year, the CGN Committee approves a Compensation Peer Group of companies. In selecting the 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 Dominions size in revenues, assets and market capitalization. Dominion also considers the geographic locations and the regulatory environment in which potential peer companies operate.
Dominions Compensation Peer Group is generally consistent from year to year, with merger and acquisition activity being the primary
reason for any changes. No changes were made to the peer group used for setting compensation for 2012. The members of Dominions Compensation Peer Group are as follows:
|
|
|
Ameren Corporation |
|
FirstEnergy Corp. |
American Electric Power Company, Inc.
CMS Energy Corporation DTE Energy Company Duke Energy Corporation |
|
NextEra Energy, Inc.
NiSource, Inc. PPL Corporation
Public Service Enterprise Group Inc. |
Entergy Corporation
Exelon Corporation |
|
The Southern Company Xcel Energy
Inc. |
The CGN Committee and management use data from the Compensation Peer Group prepared by
management to: (i) compare Dominions 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 benefits and 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 Dominions larger size
compared with the median of the Compensation Peer Group.
SURVEY DATA
Dominion did not benchmark or otherwise use broad-based market data as the basis for compensation decisions for the NEOs. Survey compensation data is used
only to provide a general understanding of compensation practices and trends. The CGN Committee takes into account individual and company specific factors, including internal pay equity, along with data from the Compensation Peer Group in
establishing compensation opportunities. The CGN Committee believes that this emphasis better reflects Dominions specific needs in its distinct competitive market and with respect to its size and complexity versus its peers.
COMPENSATION DESIGN AND RISK
Dominions management, including Dominions chief risk officer and other executives, annually reviews the overall structure of Dominions 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:
|
|
Analysis of how different elements of the compensation programs may increase or mitigate risk-taking; |
|
|
Analysis of performance metrics used for short-term and long-term incentive programs and the relation of such incentives to the objectives of Dominion;
|
|
|
Analysis of whether the performance measurement periods for short-term and long-term incentive compensation are appropriate; and
|
|
|
Analysis of the overall structure of compensation programs as related to business risks.
|
Among the factors considered in managements 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; Dominions 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 at Dominion.
Management reviewed and provided the results of this assessment to the CGN Committee. Based on this review, the CGN Committee believes that Dominions 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 Dominions risk management practices and overall strategies.
OTHER TOOLS
The CGN Committee uses a number of tools in its annual review of the compensation of Dominions 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 CEOs pay and that of the next highest-paid officer and Dominions NEOs as a group; and other information the CGN Committee may request in its discretion.
Managements internal compensation specialists provide the CGN Committee with detailed comparisons of the design and features of Dominions long-term incentive and other executive benefit programs with available information regarding
similar programs at the 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 Dominions peer companies and internally
among Dominions NEOs, and that an appropriate balance of at-risk, performance-based compensation is maintained to support the programs core objectives. No material adjustments were made to Dominions NEOs compensation as a
result of using these tools.
ELEMENTS OF DOMINIONS
COMPENSATION PROGRAM
The executive compensation program consists of four basic elements:
|
|
|
|
|
Pay Element |
|
Primary Objectives |
|
Key Features & Behavioral Focus |
Base Salary |
|
Provide competitive level of fixed cash
compensation for performing day-to-day responsibilities
Attract and retain talent |
|
Generally targeted at or slightly above
peer median, with individual and company-wide considerations
Rewards individual performance and level of experience |
Annual Incentive Plan |
|
Provide competitive level of at-risk
cash compensation for achievement of short-term financial and operational goals
Align short-term compensation with annual budget, earnings goals, business plans and core values |
|
Cash payments based on achievement of
annual financial and individual operating and stewardship goals
Rewards achievement of annual financial goals for Dominion as well as business unit and individual
goals selected to support longer-term strategies |
Long-Term Incentive Program |
|
Provide competitive level of at-risk
compensation for achievement of long-term performance goals
Create long-term shareholder value
Retain talent and support the succession planning process |
|
A combination of performance-based cash
and restricted stock awards 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 ROIC |
Employee and Executive Benefits |
|
Provide competitive retirement and
other benefit programs that attract and retain highly qualified individuals
Provide competitive terms to encourage officers to remain with Dominion during any potential change in control to ensure an orderly transition of management |
|
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
Encourages officers to remain with Dominion long-term and to act in the best interests of
shareholders, even during any potential change in control |
Factors in Setting Compensation
As part of the process of setting compensation targets, approving payouts and designing future programs, the CGN Committee evaluates Dominions 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 Dominions overall performance for the year, the CGN Committee takes into consideration several individual factors that are not
given any specific weighting in setting each element of compensation for each NEO, including:
|
|
An officers experience and job performance; |
|
|
The scope, complexity and significance of responsibility for a position, including any differences from peer company positions;
|
|
|
Internal pay equity considerations, such as the relative importance of a particular position or individual officer to Dominions strategy and
success, and comparability to other officer positions at Dominion; |
|
|
Retention and market competitive concerns; and |
|
|
The officers role in any succession plan for other key positions. |
The CGN Committee evaluates each NEOs base salary, total cash and total direct compensation opportunities against data from the
Compensation Peer Group to ensure the compensation levels are appropriately competitive, but does not target these compensation levels at a particular percentile or range of the peer group data. For Mr. Heacock, the same evaluation process is
performed using the Towers Watson Energy Services data instead of peer group data. See Exhibit 99.3 for a listing of the companies included in the survey. As part of this analysis, the CGN Committee also takes into account Dominions larger
size and complexity compared to the companies in the Compensation Peer Group.
In setting compensation for 2012, Dominion provided a modest increase in base salary for
all officers, including all NEOs, and made adjustments to performance-based compensation target levels for certain officers. Based on the review of data from the Compensation Peer Group, each NEOs job performance, recent promotions and
internal pay equity considerations such as scope and complexity of the position relative to other positions at Dominion, the CGN Committee determined it was appropriate to increase the target levels under the 2012 AIP for Mr. Christian as
described below in Annual Incentive Plan and the LTIP for Messrs. McGettrick, Christian and Koonce as described below in Long-Term Incentive 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. Farrells 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 encompassing the entirety of Dominion (as compared to the other NEOs who are responsible for
significant but distinct areas within Dominion) and his overall responsibility for corporate strategy. His compensation also reflects his role as the principal 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. Farrells 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
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 2012.
Allocation of Total
Direct Compensation in 2012
Consistent with Dominions 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 87% of
Mr. Farrells targeted 2012 total direct compensation is performance-based, tied to pre-approved performance metrics, including relative TSR and ROIC, or tied to the performance of Dominions stock. For the other NEOs,
performance-based and stock-based compensation ranges from 65% to 80% of targeted 2012 total direct compensation. This compares to an average of approximately 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 2012 for Mr. Farrell and the average of the other NEOs as a group and the allocation of such compensation among base salary, targeted 2012 AIP award and targeted 2012 long-term incentive compensation.
Base Salary
Base salary compensates officers, along with the rest of the workforce, for committing significant time to working on Dominions
behalf. Annual salary reviews achieve two primary purposes: (i) an annual adjustment, as appropriate, to keep salaries in line and competitive with the Compensation 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 officers at a level that best achieves Dominions
objectives and reflects the considerations discussed above. Dominion believes that an overall goal of targeting base salary at or slightly above the Compensation Peer Group median is a conservative but appropriate target for base pay. However, an
individuals compensation may be below or above Dominions target range based on a number of factors such as performance, tenure, and other factors explained above in Factors in Setting Compensation. In addition to being ranked
above or at the Compensation Peer Group median in 2012 in terms of revenues, assets and market capitalization, the scope of Dominions 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 Compensation Peer Group median. For 2012, the CGN
Committee approved a 7.5% base salary increase for Messrs. Farrell and Christian, a 3% base salary increase for Messrs. McGettrick and Koonce and a 4% base salary increase for Mr. Heacock. In determining the base salary increase for
Mr. Farrell, the CGN Committee considered Dominions strong performance in 2011 as well as Mr. Farrells individual performance, the complexity of Dominion and the energy industry itself and Mr. Farrells leadership in
the industry and other factors. For Mr. Christian, the CGN Committee took into consideration that Mr. Christians 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 Dominions three business units, relative to Dominions other business units and other factors. Effective January 1, 2013, the CGN Committee
increased Mr. Koonces 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 Dominions overall objective of rewarding strong performance. The AIP is a cash-based
program focused on short-term goal accomplishments and is designed to:
|
|
Tie interests of shareholders, customers and employees closely together; |
|
|
Focus the workforce on company, operating group, team and individual goals that ultimately influence operational and financial results;
|
|
|
Reward corporate and operating unit earnings performance; |
|
|
Reward safety and other operating and stewardship goal successes;
|
|
|
Emphasize teamwork by focusing on common goals; |
|
|
Appropriately balance risk and reward; and |
|
|
Provide a competitive total compensation opportunity. |
TARGET AWARDS
An NEOs compensation opportunity under
the AIP is based on a target award. Target awards are determined as a percentage of a participants base salary (for example, 85% of base salary). The target award is the amount of cash that will be paid if the plan is funded at the full
funding target set for the 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 prorated 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 Compensation Peer Group data to ensure the appropriate competitiveness of an NEOs total cash compensation opportunity. However, as discussed above, AIP target award levels were
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 2012. Annual incentive target award levels are also consistent with Dominions intent to have a
significant portion of NEO compensation at risk. For 2012, Mr. Christians AIP target award percentage was increased from 85% to 90% of base salary to reflect the continued transition of his compensation to a business unit CEO level. There
were no changes to the AIP targets as a percentage of salary for Messrs. Farrell, McGettrick, Koonce and Heacock for 2012.
|
|
|
|
|
|
|
|
|
Name |
|
2011 AIP Target Award* |
|
|
2012 AIP Target Award* |
|
Thomas F. Farrell II |
|
|
125% |
|
|
|
125% |
|
Mark F. McGettrick |
|
|
100% |
|
|
|
100% |
|
David A. Christian |
|
|
85% |
|
|
|
90% |
|
Paul D. Koonce |
|
|
90% |
|
|
|
90% |
|
David A. Heacock |
|
|
70% |
|
|
|
70% |
|
* As a % of base salary
FUNDING OF THE 2012 AIP
Funding of the 2012
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 Dominions 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 companys financial objectives and encourages behavior and
performance that will help achieve these objectives.
For the 2012 AIP, the CGN Committee established a full funding target at
100% for the NEOs at $3.05 operating earnings per share, inclusive of funding for all plan participants. The maximum funding target of 200% was set at $3.15 operating earnings per share, and no funding if operating earnings were less than $3.05 per
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 in How AIP Payouts Are 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.
Dominions consolidated operating earnings for the year ended December 31, 2012 were $1.75 billion or $3.05 per share, as
compared to its consolidated reported earnings in accordance with GAAP of $302 million or $0.53 per share, with enough earnings above $3.05 (before AIP funding) to support 60% funding for the 2012 AIP.*
*Reconciliation of 2012 Consolidated Operating Earnings to Reported Earnings. The following items, which are net of tax, are included in
Dominions 2012 reported earnings, but are excluded from consolidated operating earnings: $1.1 billion net loss, 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 planned shutdown of the Kewaunee nuclear merchant power station; $53 million of restoration costs associated with severe storms
affecting the Dominion Virginia Power and Dominion North Carolina Power service territories; $22 million net loss from discontinued operations of two merchant power stations (State Line and Salem Harbor) that were sold in 2012; and $5 million net
benefit related to other items.
HOW AIP PAYOUTS ARE DETERMINED
For Dominions NEOs, payout of funded AIP awards is 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 performance of that goal. Officer goals are weighted according to their responsibilities. The overall score cannot exceed
100%.
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 the core values of safety, ethics, excellence and teamwork, which in turn contribute to Dominions financial success.
The discretionary payout goals adopted by each NEO are described under 2012 AIP Payouts and the weightings applied to those goals
are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
Consolidated Financial Goal |
|
|
Business Unit Financial Goals |
|
|
Operating/ Stewardship Goals* |
|
Thomas F. Farrell II |
|
|
95% |
|
|
|
|
|
|
|
5% |
|
Mark F. McGettrick |
|
|
95% |
|
|
|
|
|
|
|
5% |
|
David A. Christian |
|
|
65% |
|
|
|
30% |
|
|
|
5% |
|
Paul D. Koonce |
|
|
65% |
|
|
|
30% |
|
|
|
5% |
|
David A. Heacock |
|
|
40% |
|
|
|
30% |
|
|
|
30% |
|
*5% goal weighting is for safety goal. Mr. Heacock had other non-safety operating and stewardship goals as described
below.
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 $3.05 per share, which was accomplished as described above. The 2012 business unit financial goals and accomplishment levels for Mr. Koonce (DVP), and Messrs. Christian and Heacock (Dominion Generation) were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business Unit |
|
Goal Threshold (Net Income) |
|
|
Goal 100% Payout (Net Income) |
|
|
Actual 2012 Net Income |
|
|
2012
Approved Accomplishment |
|
(Million/$) |
|
|
|
|
|
|
|
|
|
|
|
|
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 2012 AIP by NEOs are shown below and are reflected in the Non-Equity Incentive Plan Compensation
column of the Summary Compensation Table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
Base Salary |
|
|
|
|
Target Award* |
|
|
|
|
Funding% |
|
|
|
|
Total Payout Score % |
|
|
|
|
2012 AIP Payout |
|
Thomas F. Farrell II |
|
$ |
386,319 |
|
|
X |
|
|
125% |
|
|
X |
|
|
60% |
|
|
X |
|
|
99% |
|
|
= |
|
$ |
286,842 |
|
Mark F. McGettrick |
|
|
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 |
|
|
431,709 |
|
|
X |
|
|
90% |
|
|
X |
|
|
60% |
|
|
X |
|
|
100% |
|
|
= |
|
|
233,123 |
|
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 applicable portion related to their
service for Virginia Power in the year presented.
Messrs. Farrell and McGettricks 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 Heacocks payout scores were calculated as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
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|
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|
|
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% |
|
Long-Term Incentive Program
OVERVIEW
Dominions LTIP focuses on Dominions longer-term
strategic goals and retention of its executives. Since 2006, 50% of Dominions 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 Dominions stock price to further align the interests of officers with the interests of its shareholders and customers. For those officers who have
made substantial progress toward their share ownership guidelines, the 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 in Share
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 Dominions earnings for the prior year. Like the AIP target award levels discussed above, long-term incentive target award levels were established based on a number of factors,
including historical practice, individual and company performance, and internal pay equity considerations, and are compared against Compensation Peer Group data to ensure the appropriate competitiveness of an NEOs 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 Compensation Peer Group data, nor was market survey data a factor in setting long-term incentive target award
levels for 2012.
For 2012, the CGN Committee approved increases to the target long-term incentive awards for Messrs.
McGettrick, Christian and Koonce as discussed below. There was no change to the target long-term incentive award for Mr. Farrell or for Mr. Heacock.
MCGETTRICK. Among the factors
considered by the CGN Committee in determining the amount of Mr. McGettricks award were Mr. McGettricks continued superior performance as CFO and his broad-based experience. The CGN Committee determined it was appropriate to
approve a 6% increase in Mr. McGettricks target long-term incentive award, which resulted in a 5% increase in total direct compensation at target.
CHRISTIAN. For Mr. Christians
target long-term incentive award, the CGN Committee considered, among other factors, Mr. Christians 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 Dominions three
business units, relative to Dominions other business units in determining his target long-term incentive award, the continued transition of Mr. Christians 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. Christians 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. Koonces award were Mr. Koonces performance as CEO of the DVP business unit and his
experience and long tenure with Dominion. The CGN Committee determined it was appropriate to approve a 13% increase in Mr. Koonces target long-term incentive award, which resulted in a 9% increase in total direct compensation at target.
Information regarding the fair value of the 2012 restricted stock grants and target cash performance grants for the NEOs is
provided in the Grants of Plan-Based Awards table.
2012 RESTRICTED STOCK GRANTS
All officers received a restricted stock grant on February 1, 2012 based on a stated dollar value. The number of shares awarded was
determined by dividing the stated dollar value by the closing price of Dominions common stock on February 1, 2012. The grants have a three-year vesting term, with cliff vesting at the end of the restricted period on February 1, 2015.
Dividends are paid to officers during the restricted period. The grant date fair value and vesting terms of the 2012 restricted stock grant awards made to the NEOs are disclosed in the Grants of Plan-Based Awards table and related footnotes.
2012 PERFORMANCE GRANTS
In January 2012, the CGN Committee approved cash performance grants for the NEOs, effective February 1, 2012. The performance period commenced on January 1, 2012 and will end on
December 31, 2013. The 2012 grants are denominated as a target award, with potential payouts ranging from 0-200% of the target based on Dominions TSR relative to a 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 Dominions peer companies. The ROIC metric was selected to reward officers for the achievement of expected levels
of return on Dominions 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 2012 performance grants made to the NEOs are disclosed in the Grants of Plan-Based Awards table and related footnotes.
Performance Grant Peer Group
Since performance grants were first awarded in 2006, Dominions 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 Dominions 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 Dominions 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
Dominions 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 2011 PERFORMANCE
GRANTS
In February 2013, final payouts were made to officers who received 2011 performance grants, including the NEOs. The
2011 performance grants were based on two goals: TSR for the two-year period ended December 31, 2012 relative to Dominions 2011 Performance Peer Group (weighted 50%) and ROIC for the same two-year period (weighted 50%).
|
|
Relative TSR (50% weighting). TSR is the difference between the value of a share of common stock at the beginning and
|
|
|
end of the two-year performance period, plus dividends paid as if reinvested in stock. For this metric, Dominions TSR is compared to TSR levels of the companies in the 2011 Performance
Grant Peer Group for the same two-year period. The relative TSR targets and corresponding payout scores for the 2011 performance grant are as follows: |
|
|
|
Relative TSR Performance |
|
Percentage Payout of
TSR Percentage* |
1st Quartile 75% to 100% |
|
150% 200% |
2nd Quartile 50% to 74.9% |
|
100% 149.9% |
3rd Quartile 25% to 49.9% |
|
50% 99.9% |
4th Quartile
below 25% |
|
0% |
|
*TSR |
weighting is interpolated between the top and bottom of the percentages within a quartile. A minimum payment of 25% of the TSR percentage will be made if the TSR
performance is at least 10% on a compounded annual basis for the performance period, regardless of relative performance. |
Actual relative TSR performance for the 2011-2012 period was in the second quartile. Dominions 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.
|
|
ROIC (50% weighting). ROIC reflects Dominions total return divided by average invested capital for the performance period. The ROIC goal
at target is consistent with the strategic plan/annual business plan as approved by Dominions Board. For this purpose, total return is Dominions consolidated operating earnings plus its after-tax interest and related charges, plus
preferred dividends. Dominion designed its 2011 ROIC goals to provide 100% payout if it achieved an average ROIC of 7.60% over the two-year performance period. The ROIC performance targets and corresponding payout scores are as follows:
|
|
|
|
|
|
ROIC Performance |
|
Percentage Payout of ROIC Percentage* |
|
7.88% and above |
|
|
200% |
|
7.74% 7.87% |
|
|
150% 199.9% |
|
7.60% 7.73% |
|
|
100% 149.9% |
|
7.46% 7.59% |
|
|
50% 99.9% |
|
Below 7. 46% |
|
|
0% |
|
|
*ROIC |
percentage payout is interpolated between the top and bottom of the percentages for any range. |
Actual ROIC performance for the 2011-2012 period was 7.40% which produced a payout of 0%.
Based on the achievement of the performance criteria, the CGN Committee approved a 64.2% payout for the 2011 performance grants. The
following table summarizes the achievement of the 2011 performance criteria:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Measure |
|
Goal Weight% |
|
|
|
|
|
Goal Achievement% |
|
|
|
|
|
Payout% |
|
Relative TSR |
|
|
50% |
|
|
|
X |
|
|
|
128.5% |
|
|
|
= |
|
|
|
64.2% |
|
ROIC |
|
|
50% |
|
|
|
X |
|
|
|
0% |
|
|
|
= |
|
|
|
0% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined Overall Performance Score |
|
|
|
|
|
|
|
64.2% |
|
The resulting payout amounts for the NEOs for the 2011 performance grants are shown below
and are also reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
2011 Performance Grant Award |
|
|
|
|
|
Overall Performance Score |
|
|
|
|
|
Calculated Performance Grant Payout |
|
Thomas F. Farrell II |
|
$ |
1,027,600 |
|
|
|
X |
|
|
|
64.2% |
|
|
|
= |
|
|
$ |
659,719 |
|
Mark F. McGettrick |
|
|
458,300 |
|
|
|
X |
|
|
|
64.2% |
|
|
|
= |
|
|
|
294,229 |
|
David A. Christian |
|
|
303,525 |
|
|
|
X |
|
|
|
64.2% |
|
|
|
= |
|
|
|
194,863 |
|
Paul D. Koonce |
|
|
464,231 |
|
|
|
X |
|
|
|
64.2% |
|
|
|
= |
|
|
|
298,036 |
|
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 applicable portion related to their service for Virginia Power in the year presented.
Other Restricted
Stock Grants
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 2012, the CGN Committee approved restricted stock grants for Messrs.
McGettrick, Koonce and Christian of 21,949, 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 their service for Virginia Power in the
year presented), respectively, to secure their services for the next three years. In making the restricted 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 is subject to three-year cliff vesting with all shares vesting on December 20, 2015 (the Vesting Date). The 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 compose 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 (DPP)
and a defined contribution 401(k)
savings 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 retirement benefit under which Dominion contributes 2% of each participants 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 DPP is explained in the narrative following the Pension Benefits table. The change in DPP value for 2012 for the
NEOs is included in the Summary Compensation Table.
Officers whose matching contributions under the 401(k) Plan are
limited by the IRC 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 IRC limits for the NEOs are included in the All Other Compensation column of the Summary 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. Unlike the DPP and 401(k) Plan, these
plans are unfunded, unsecured obligations of Dominion. These plans keep Dominion competitive in attracting and retaining officers. Due to IRC limits on pension plan benefits and because a more substantial portion of total compensation for officers
is paid as incentive compensation than for other employees, the DPP 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 DPP due to the IRC 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 the Pension Benefits table and the terms of the plans are fully explained in the narrative following that table.
In individual situations and primarily for mid-career changes or retention purposes, the CGN Committee has granted certain officers
additional years of credited age and service for purposes of calculating benefits under the BRP. Age and service credits granted to the NEOs are described in Dominion Retirement Benefit Restoration Plan under Pension Benefits.
Additional age and service may also be earned under the terms of an officers Employee Continuity Agreement in the event of a change in control, as described in Change in Control under Potential Payments Upon Termination or Change
in Control. No additional years of age or service credit were granted to the NEOs during 2012.
OTHER BENEFIT PROGRAMS
Dominions 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 officers 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 the All Other Compensation column of the Summary 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:
|
|
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 Dominions retirement and other employee benefit programs. |
|
|
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. |
|
|
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 executives 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 Dominion to have better access to the executives for business purposes. During 2012, 97% of the use of Dominions aircraft
was for business purposes. Other than Mr. Farrell, none
|
|
|
of the NEOs or other executive officers used company aircraft for personal travel in 2012. |
Other than costs associated with comprehensive executive physical exams (which are exempt from taxation under the 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 at 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 companys 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 Dominion 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 in
Potential 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 nations 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 certain of its NEOs to provide certain benefit enhancements or other protections, as described in Dominion Retirement Benefit Restoration Plan, Dominion Executive
Supplemental Retirement Plan and Potential Payments Upon Termination or Change in Control. No new letter agreements were entered into in 2012.
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
Dominions shareholders by promoting a long-term focus through long-term share ownership. The guidelines ensure that management maintains a personal stake in the 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 PresidentDominion |
|
|
5 x salary/35,000 |
|
Senior Vice PresidentDominion & Subsidiaries/PresidentDominion Subsidiaries |
|
|
4 x salary/20,000 |
|
Vice PresidentDominion & Subsidiaries |
|
|
3 x salary/10,000 |
|
The levels of ownership reflect the increasing level of responsibility for that officers position.
Shares owned by an officer and his or her immediate family members as well as shares held under Dominion benefit plans contribute to the ownership targets. Restricted stock, goal-based stock and shares underlying stock options do not contribute to
the ownership 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.
Until an officer meets his or her ownership target, an officer must retain net shares from stock option
exercises and all after-tax shares from vesting restricted stock and goal-based stock awards. Dominion refers to shares held by an officer that are more than 15% above his or her ownership target as Qualifying Excess Shares. Officers may sell, gift
or transfer Qualifying Excess Shares at any time, subject to insider trading rules and other policy provisions as long as the sale, gift or transfer does not cause an executive to fall below his or 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. As of January 1, 2013, each NEO exceeded his share ownership target as shown below:
|
|
|
|
|
|
|
|
|
|
|
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
Dominions 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 Dominions 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 Dominions operations or the employees 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 company 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
IRC Section 162(m) generally disallows a deduction by publicly held corporations for compensation in excess of $1 million paid to the CEO and next three most highly compensated officers other than
the CFO. If certain requirements are met, performance-based compensation qualifies for an exemption from the IRC Section 162(m) deduction limit. Dominion intends to provide competitive executive compensation while maximizing Dominions tax
deduction. While the CGN Committee considers IRC 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. Dominions 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.
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 prorated compensation amounts attributable to each NEOs services performed for Virginia Power. The percentage of each NEOs overall Dominion services performed for Virginia Power
during 2012 was as follows: Mr. Farrell, 29%; Mr. McGettrick, 46%; Mr. Koonce, 83%; Mr. Christian, 54%; and Mr. 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 grant date fair value of the stock
awards for accounting purposes for the respective year. Stock awards are reported in the year in 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 Dominions 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 are not 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 Dominion, which include the tax-qualified DPP and the nonqualified plans described in the narrative following the
Pension Benefits table. 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
Dominions audited financial statements for the applicable fiscal year. Accrued 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 the years presented in the Summary Compensation Table. Please refer to the footnotes to the Pension Benefits table 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 NEOs 401(k) Plan account, and company matching contributions paid directly to the NEO that would be credited to the 401(k) Plan if IRC contribution limits did
not apply.
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.
SUMMARY COMPENSATION TABLE
The following table presents information concerning compensation paid or earned by the NEOs for the years ended December 31, 2012, 2011 and 2010, 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 |
|
Thomas F. Farrell II
Chairman and Chief Executive Officer |
|
|
2012 |
|
|
$ |
381,827 |
|
|
$ |
1,027,602 |
|
|
$ |
946,561 |
|
|
$ |
1,171,041 |
|
|
$ |
54,815 |
|
|
$ |
3,581,846 |
|
|
|
2011 |
|
|
|
393,084 |
|
|
|
1,127,702 |
|
|
|
2,351,094 |
|
|
|
584,944 |
|
|
|
51,827 |
|
|
|
4,508,651 |
|
|
|
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 |
|
|
2012 |
|
|
|
311,880 |
|
|
|
1,632,701 |
|
|
|
480,389 |
|
|
|
1,169,718 |
|
|
|
31,291 |
|
|
|
3,625,979 |
|
|
|
2011 |
|
|
|
320,948 |
|
|
|
485,013 |
|
|
|
1,008,431 |
|
|
|
802,520 |
|
|
|
33,962 |
|
|
|
2,650,874 |
|
|
|
2010 |
|
|
|
305,402 |
|
|
|
413,970 |
|
|
|
841,435 |
|
|
|
1,590,831 |
|
|
|
33,281 |
|
|
|
3,184,919 |
|
David A. Christian
President and COODominion 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 COODVP |
|
|
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 applicable portion related to their service for Virginia Power in the year presented.
(1) |
The NEOs received the following base salary increases effective
March 1, 2012: Messrs. Farrell and Christian: 7.5%; Mr. Heacock: 4%; and Messrs. McGettrick and Koonce: 3%. |
(2) |
The amounts in this column reflect the grant date fair value of stock
awards for the respective year grant in accordance with FASB guidance for share-based payments. Dominion did not grant any stock options in 2012. See also Note 19 to the Consolidated Financial Statements in the companies 2012 Annual Report on
Form 10-K for more information on the valuation of stock-based awards, the Grants of Plan-Based Awards table for stock awards granted in 2012, and the Outstanding Equity Awards at Fiscal Year-End table for a listing of all outstanding equity awards
as of December 31, 2012. |
(3) |
The 2012 amounts in this column include the payout under Dominions
2012 AIP and 2011 Performance Grant Awards. All of the NEOs received 60% funding of their 2012 AIP target awards. Messrs. Farrell and McGettrick received 99% payouts for accomplishment of their goals while Messrs. Christian and Heacock received 96%
and Mr. Koonce received 100%. The 2012 AIP payout amounts were as follows: Mr. Farrell: $286,842; Mr. McGettrick: $186,161; Mr. Christian: $169,863; Mr. Koonce: $233,123; and Mr. Heacock: $83,771. See CD&A for
additional information on the 2012 AIP and the Grants of Plan-Based Awards table for the range of each NEOs potential award under the 2012 AIP. The 2011 Performance Grant Award was issued on February 1, 2011 and the payout amount was
determined based on achievement of performance goals for the performance period ended December 31, 2012. Payouts can range from 0% to 200%. The actual payout was 64.2% of the target amount. The payout amounts were as follows: Mr. Farrell:
$659,719; Mr. McGettrick: $294,229; Mr. Christian: $194,863; Mr. Koonce: $298,036; and Mr. Heacock: $75,531. The 2011 amounts reflect both the 2011 AIP and the 2010 Performance Grant payouts, and the 2010 amounts reflect both the
2010 AIP and 2009 Performance Grant payouts. |
(4) |
All amounts in this column are for the aggregate change in the actuarial
present value of the NEOs accumulated benefit under the DPP and nonqualified executive retirement plans. There are no above-market earnings on nonqualified deferred compensation plans. These accruals are not directly in relation to final
payout potential, and can vary significantly year over year based on (i) promotions and corresponding changes in salary; (ii) other one-time adjustments to salary or incentive target for market or other reasons; (iii) actual age
versus predicted age at retirement; (iv) discount rate used to determine present value of benefit; and (v) other relevant factors. |
(5) |
All Other Compensation amounts for 2012 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
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 |
|
$ |
31,629 |
|
|
$ |
8,646 |
|
|
$ |
2,202 |
|
|
$ |
12,338 |
|
|
$ |
54,815 |
|
Mark F. McGettrick |
|
|
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 |
|
|
22,768 |
|
|
|
11,000 |
|
|
|
6,190 |
|
|
|
6,699 |
|
|
|
46,657 |
|
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 applicable 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. Farrells personal use of the aircraft during 2012 was $23,537. For personal flights, all direct operating
costs are included in calculating aggregate incremental cost. Direct operating costs include the following: fuel, airport fees, catering, ground transportation and crew expenses (any food, lodging and other costs). The fixed costs of owning the
aircraft and employing the crew are not taken into consideration, as more than 97% of the use of the corporate aircraft is for business purposes. The CGN Committee has directed Mr. Farrell to use corporate aircraft for all personal travel
whenever it is feasible to do so. |
(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 lost 401(k) Plan matching contribution due to IRS limits. |
GRANTS OF 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, 2012.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Fair Value of Stock
and Options Award(1)(4) |
|
|
|
|
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 applicable portion related to their service for Virginia Power in the year presented.
(1) |
On January 19, 2012, the CGN Committee approved the 2012 long-term
incentive compensation awards for Dominion officers, which consisted of a restricted stock grant and a cash performance grant. The 2012 restricted stock award was granted on February 1, 2012. Under the 2005 Incentive Compensation Plan, fair
market value is defined as the closing price of Dominion common stock on the date of grant or, if that day is not a trading day, on the most recent trading day immediately preceding the date of grant. The fair market value for the February 1,
2012 restricted stock grant was $50.42 per share, which was Dominions closing stock price on February 1, 2012. |
(2) |
Amounts represent the range of potential payouts under the 2012 AIP.
Actual amounts paid under the 2012 AIP are found in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. Under Dominions AIP, officers are eligible for an annual performance-based award. The CGN Committee
establishes target awards for each NEO based on his salary level and expressed as a percentage of the individual NEOs 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 2012 AIP, funding was based on the achievement of consolidated operating earnings goals with the maximum funding capped at 200%, as explained under the Annual Incentive Plan section of the CD&A.
|
(3) |
Amounts represent the range of potential payouts under the 2012
performance grant of the LTIP. Payouts can range from 0% to 200% of the target award. Awards will be paid by March 15, 2014 depending on the achievement of performance goals for the two-year period ending December 31, 2013. The amount
earned will depend on the level of achievement of two performance metrics: TSR50% and ROIC50%. TSR measures Dominions share performance for the two-year period ended December 31, 2013 relative to the TSR of the companies that
are listed as members of the Philadelphia Stock Exchange Utility Index as of the end of the performance period. ROIC goal achievement will be scored against 2012 and 2013 budget goals. |
|
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 officers 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 officers estate or financial planning. The payout amount will be the greater of the officers target award or an amount based
on the predicted performance used for compensation cost disclosure purposes in Dominions 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 officers target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominions financial statements.
|
(4) |
The 2012 restricted stock grant fully vests at the end of three years.
The restricted stock grant is forfeited in its entirety if an officer voluntarily terminates employment or is terminated with cause before the vesting date. The restricted stock grant provides for pro-rated vesting if an officer retires, dies,
becomes disabled, is terminated without cause, or if there is a change in control. In the case of retirement, pro-rated vesting will not occur if the CEO (or for the |
|
CEO, the CGN Committee) determines the officers retirement is detrimental to the company. In the event of a change in control, pro-rated vesting is provided as of the change in control
date, and full vesting if an officers employment is terminated, or constructively terminated by the successor entity following the change in control date but before the scheduled vesting date. Dividends on the restricted shares are paid during
the restricted period at the same rate declared by Dominion for all shareholders. |
(5) |
On December 17, 2012, the CGN Committee awarded shares of restricted
stock to Messrs. McGettrick, Christian and Koonce for retention purposes. Mr. McGettrick received 21,949 shares, Mr. Christian received 15,505 and Mr. Koonce received 23,715 shares (These NEOs perform services for more than one
subsidiary of Dominion. These share amounts reflect only the applicable portion related to their service for Virginia Power in the year presented). The grant date was December 20, 2012 and the shares will fully vest on December 20, 2015
(Vesting Date), provided they each remain employed until that date. The officer will forfeit the restricted stock grant if 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. The fair market value for these retention grants was $52.20 per share, which was Dominions closing stock
price on December 20, 2012. Dividends on the restricted shares are reinvested and the resulting shares will also maintain a restricted status throughout the term of the grant. To the extent the officer remains an employee of Dominion or a
Dominion Company, net shares of vested restricted stock under each agreement must be retained for two years following the Vesting Date unless the officer dies or becomes disabled. |
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
The following table summarizes equity awards made to NEOs that were outstanding as of December 31, 2012. There were no unexercised or
unexercisable option awards outstanding for any NEOs as of December 31, 2012.
|
|
|
|
|
|
|
|
|
|
|
Stock Awards |
|
Name |
|
Number of Shares or Units of Stock that Have Not Vested (#) |
|
|
Market Value of Shares or Units of Stock That Have Not Vested(1) ($) |
|
Thomas F. Farrell II |
|
|
27,431 |
(2) |
|
$ |
1,420,926 |
|
|
|
|
23,601 |
(3) |
|
|
1,222,532 |
|
|
|
|
20,380 |
(4) |
|
|
1,055,684 |
|
|
|
|
31,839 |
(5) |
|
|
1,649,260 |
|
Mark F. McGettrick |
|
|
11,011 |
(2) |
|
|
570,370 |
|
|
|
|
10,526 |
(3) |
|
|
545,247 |
|
|
|
|
9,657 |
(4) |
|
|
500,233 |
|
|
|
|
21,949 |
(6) |
|
|
1,136,958 |
|
David A. Christian |
|
|
6,122 |
(2) |
|
|
317,120 |
|
|
|
|
6,971 |
(3) |
|
|
361,098 |
|
|
|
|
7,090 |
(4) |
|
|
367,262 |
|
|
|
|
15,505 |
(6) |
|
|
803,159 |
|
Paul D. Koonce |
|
|
12,393 |
(2) |
|
|
641,957 |
|
|
|
|
10,662 |
(3) |
|
|
552,292 |
|
|
|
|
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. Amounts for the NEOs
listed in the table reflect only the applicable portion related to their service for Virginia Power in the year presented.
(1) |
The market value is based on closing stock price of $51.80 on
December 31, 2012. |
(2) |
Shares scheduled to vest on February 1, 2013.
|
(3) |
Shares scheduled to vest on February 1, 2014.
|
(4) |
Shares scheduled to vest on February 1, 2015.
|
(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) |
Shares scheduled to vest on December 20, 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.
|
OPTION EXERCISES AND STOCK VESTED
The following table provides information about the value realized by NEOs during the year ended December 31, 2012 on vested restricted stock awards.
There were no option exercises by NEOs in 2012.
|
|
|
|
|
|
|
|
|
|
|
Stock Awards |
|
Name |
|
Number of Shares Acquired on Vesting |
|
|
Value Realized on Vesting |
|
Thomas F. Farrell II |
|
|
25,037 |
|
|
$ |
1,262,366 |
|
Mark F. McGettrick |
|
|
9,770 |
|
|
|
492,603 |
|
David A. Christian |
|
|
4,985 |
|
|
|
251,344 |
|
Paul D. Koonce |
|
|
10,557 |
|
|
|
532,284 |
|
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 applicable portion related to their service for Virginia Power in 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, 2012, using the same interest rate and mortality assumptions used in determining the aggregate pension obligations disclosed in Dominions financial statements. The years of credited service
and the present value of accumulated benefits were determined by the plan actuaries, using the appropriate accrued service, pay and other assumptions similar to those used for accounting and disclosure purposes. Please refer to Actuarial
Assumptions Used to Calculate Pension Benefits for detailed information regarding these assumptions.
|
|
|
|
|
|
|
|
|
|
|
Name |
|
Plan Name |
|
Number of Years Credited Service(1) |
|
|
Present Value of Accumulated Benefit(2) |
|
Thomas F. Farrell II |
|
Dominion Pension Plan |
|
|
17.00 |
|
|
$ |
299,495 |
|
|
|
Benefit Restoration Plan |
|
|
28.00 |
|
|
|
3,079,682 |
|
|
|
Supplemental Retirement Plan |
|
|
28.00 |
|
|
|
4,027,674 |
|
Mark F. McGettrick |
|
Dominion Pension Plan |
|
|
28.50 |
|
|
|
659,443 |
|
|
|
Benefit Restoration Plan |
|
|
30.00 |
|
|
|
3,049,238 |
|
|
|
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 |
|
Dominion Pension Plan |
|
|
14.00 |
|
|
|
559,634 |
|
|
|
Benefit Restoration Plan |
|
|
14.00 |
|
|
|
753,813 |
|
|
|
Supplemental Retirement Plan |
|
|
14.00 |
|
|
|
3,295,194 |
|
David A. Heacock |
|
Dominion Pension Plan |
|
|
25.50 |
|
|
|
697,260 |
|
|
|
Benefit Restoration Plan |
|
|
25.50 |
|
|
|
487,554 |
|
|
|
Supplemental Retirement Plan |
|
|
25.50 |
|
|
|
663,178 |
|
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 applicable portion related to their service for Virginia Power in 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, 2012. Service for the BRP and the ESRP is the NEOs actual credited service as of December 31, 2012 plus any potential total credited service to the plan maximum,
including any extra years of credited service granted to Messrs. Farrell and McGettrick by the CGN Committee for the purpose of calculating benefits under these plans. Please refer to the narrative below and under Dominion Retirement Benefit
Restoration Plan, Dominion Executive Supplemental Retirement Plan and Potential Payments Upon Termination or Change In Control for information about the requirements for receiving extra years of credited service and the amount credited, if any, for
each NEO. |
(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 Heacock, and (ii) age 55 for Mr. McGettrick (when he would be treated as age 60
based on his five additional years of credited age). In addition, for purposes of calculating the BRP benefits for Messrs. Farrell and McGettrick, the amounts reflect additional credited years of service granted to them pursuant to their agreements
with the company (see Dominion Retirement Benefit Restoration Plan). If the amounts in this column did not include the additional years of credited service, the present value of the BRP benefit would be $1,440,225 lower for Mr. Farrell and
$1,451,322 lower for Mr. McGettrick. DPP and ESRP benefits amounts are not augmented by the additional service credit assumptions. |
Dominion Pension Plan
The DPP is a tax-qualified defined benefit pension plan. All of the NEOs participate in the DPP. The DPP 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 DPP 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 participants 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 credited service through December 31, 2000: |
2.03% times Final
Average Earnings times Credited
Service before 2001 |
|
|
Minus |
|
|
2.00% times
estimated Social Security benefit times Credited Service before 2001 |
|
For credited service on or after January 1, 2001: |
1.80% times Final
Average Earnings times Credited
Service after 2000 |
|
|
Minus |
|
|
1.50% times estimated Social Security benefit times Credited Service after 2000 |
Credited service is limited to a total of 30 years for all parts of the formula and credited service after
2000 is limited to 30 years minus credited 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 (3.18% in 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 IRC limits the amount of compensation that may be included in determining pension benefits under qualified
pension plans. For 2012, the compensation limit was $250,000. The IRC also limits the total annual benefit that may be provided to a participant under a qualified defined benefit plan. For 2012, this limitation was the lesser of (i) $200,000 or
(ii) the average of the participants 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 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 IRC 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 participants BRP benefit is calculated using the same formula (except that the IRC salary limit is not applied)
used to determine the participants 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 IRC Section 409A, the portion of a participants 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. Farrells 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 50, has
earned benefits calculated based on five additional years of age and 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, see Dominion Executive Supplemental Retirement Plan.
If a vested participant dies when he or she is retirement eligible (on or after age 55), the participants 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 participants spouse will receive a restoration benefit calculated in the same way as the 50% qualified
pre-retirement survivor annuity payable under the DPP 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 participants 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 participants lifetime. To accommodate the enactment of IRC Section 409A,
the portion of a participants 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 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. 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 attaining age 55, he will receive a pro-rated ESRP benefit. Based on the terms of their individual letter agreements, Messrs. Farrell, McGettrick and Koonce will receive an ESRP benefit
calculated as a lifetime benefit. Mr. McGettrick 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. 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 IRC and PBGC 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, 2012 benefit calculations shown in the Pension Benefits
table include a discount rate of 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 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 a point five years beyond the calculation date (this year,
to 2017) with 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 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 Dominions Administrative Benefits Committee and adjusted periodically. For year 2012, a 5.09% discount rate was used to determine the lump sum payout amounts.
The discount rate for each year will be based on a rolling average of the blended rate published by the PBGC in October of the previous five years.
NONQUALIFIED DEFERRED COMPENSATION
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
Aggregate Earnings in Last FY
(as of 12/31/2012)* |
|
|
Aggregate Withdrawals/
Distributions (as of 12/31/2012) |
|
|
Aggregate Balance at Last FYE
(as of 12/31/2012) |
|
Thomas F. Farrell II |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Mark F. McGettrick |
|
|
|
|
|
|
|
|
|
|
|
|
David A. Christian |
|
|
256 |
|
|
|
|
|
|
|
15,891 |
|
Paul D. Koonce |
|
|
22,404 |
|
|
|
|
|
|
|
1,146,855 |
|
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 applicable portion related to their service for Virginia Power in the year
presented.
At this time, Dominion does not offer any nonqualified elective deferred compensation plans to its officers or
other employees. The Nonqualified Deferred Compensation table reflects, in aggregate, the plan balances for two former plans offered to Dominion officers and other highly compensated employees: the Frozen Deferred Compensation Plan and 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 Dominions 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; 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 27 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 following funds had rates of returns for 2012 as follows: Dominion Resources Stock Fund, 1.66%; and Dominion Fixed Income
Fund, 3.31%.
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. Dominions 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:
|
|
Options expire on the last day of the 120th month after retirement or disability; |
|
|
Options expire on the last day of the 24th month after the participants death (while employed); |
|
|
Options expire on the last day of the 12th month after the participants severance; |
|
|
Options expire on the 90th day after termination with cause; and |
|
|
Options expire on the last day of the 120th month after severance following a change in control. |
The NEO participating in the Frozen DSOP held options on the publicly available mutual fund, Vanguard Short-Term Bond Index, which had a
rate of return for 2012 of 1.95%.
POTENTIAL PAYMENTS UPON TERMINATION
OR CHANGE IN 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 Dominion, that are in addition to termination benefits for other employees in the same situation.
Change in Control
As discussed in the Employee
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:
|
|
There must be a change in control; and |
|
|
The executive must either be terminated without cause, or terminate his or her employment with the surviving company after a constructive termination.
Constructive termination means the executives salary, incentive compensation or job responsibility is reduced after a change in control or the executives work location is relocated more than 50 miles without his or her consent.
|
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 Dominions or its successors Board within two years after the last of such transactions.
If an executives 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:
|
|
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).
|
|
|
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. |
|
|
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.
|
|
|
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. |
|
|
Retiree medical coverage will be determined under the relevant plan with additional age and service credited as provided under an officers letter
of agreement (if any) and including five additional years credited to age and five additional years credited to service. |
|
|
Outplacement services for one year (up to $25,000). |
|
|
If any payments are classified as excess parachute payments for purposes of IRC Section 280G and the 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 the Long-Term Incentive Program section of the CD&A and footnotes to the Grants of Plan-Based Awards table.
Other Post Employment Benefit for Mr. Farrell
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.
The following table provides the incremental payments that would be earned by each NEO
if his employment had been terminated, or constructively terminated, as of December 31, 2012. These benefits are in addition to retirement benefits that would be payable on any termination of employment. Please refer to the Pension
Benefits table for information related to the present value of accumulated retirement benefits payable to the NEOs.
Incremental Payments Upon
Termination or 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 |
|
Thomas F. Farrell II(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement |
|
|
$ |
|
|
$ |
2,485,126 |
|
|
$ |
491,461 |
|
|
$ |
386,319 |
|
|
|
$ |
|
|
$ |
|
|
$ |
|
|
|
$ |
|
|
$ |
3,362,906 |
|
Death / Disability |
|
|
|
|
|
|
3,144,840 |
|
|
|
491,461 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,636,301 |
|
Change in
Control(5) |
|
|
588,482 |
|
|
|
1,873,837 |
|
|
|
536,139 |
|
|
|
|
|
|
|
2,929,365 |
|
|
|
|
|
7,340 |
|
|
|
|
|
|
|
5,935,163 |
|
Mark F. McGettrick(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement |
|
|
|
|
|
|
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) |
|
|
375,375 |
|
|
|
1,197,516 |
|
|
|
186,514 |
|
|
|
|
|
|
|
2,004,106 |
|
|
|
|
|
13,490 |
|
|
|
1,329,761 |
|
|
|
5,106,762 |
|
Paul D. Koonce |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Termination Without Cause |
|
|
|
|
|
|
1,142,123 |
|
|
|
251,627 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,393,750 |
|
Voluntary Termination |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Termination With Cause |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Death / Disability |
|
|
|
|
|
|
1,176,238 |
|
|
|
251,627 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,427,865 |
|
Change in
Control(5) |
|
|
2,120,693 |
|
|
|
1,821,216 |
|
|
|
274,502 |
|
|
|
|
|
|
|
2,781,824 |
|
|
11,102 |
|
|
20,633 |
|
|
|
|
|
|
|
7,029,970 |
|
David A. Heacock(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement |
|
|
|
|
|
|
268,709 |
|
|
|
56,267 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
324,976 |
|
Change in
Control(5) |
|
|
756,132 |
|
|
|
138,584 |
|
|
|
61,383 |
|
|
|
|
|
|
|
1,119,029 |
|
|
75,093 |
|
|
11,765 |
|
|
|
783,353 |
|
|
|
2,945,339 |
|
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 applicable portion related to their service for Virginia Power in the year presented.
(1) |
Grants made in 2010, 2011 and 2012 under the LTIP vest prorated upon
termination without cause, death or disability. These grants vest prorated upon retirement provided the CEO of Dominion (or in the case of the CEO, the CGN Committee) determines the NEOs retirement is not detrimental to the company; amounts
shown assume this determination was made. However, the December 2010 restricted stock award issued to Mr. Farrell and the December 2012 restricted stock awards issued to Messrs. McGettrick, Christian and Koonce do not vest prorated if the
executive is terminated or leaves for any reason other than following change of control, death or disability. The amounts shown in the restricted stock column are based on the closing stock price of $51.80 on December 31, 2012.
|
(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 and
Christian are entitled to executive life insurance coverage and retiree medical benefit upon any termination since they are retirement eligible and have completed 10 years of service. Mr. Heacock is entitled to executive life insurance coverage
since he has reached the age of 55 and has 10 years of service. Mr. Koonce is eligible for executive life insurance upon a change in control. Mr. Heacock is eligible for retiree medical coverage upon a change in control. Mr. Koonce would not be
eligible for retiree medical coverage upon a change in control because with an additional 5 years of age credit he would not reach the required retiree medical age of 58. Retiree health benefits have been quantified using assumptions used for
financial accounting purposes. |
(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 Heacock) or termination without cause (Mr. Koonce). The restricted stock and performance grant amounts
represent the value of the awards upon a change in control that is above what would be received upon a retirement or termination. |
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
DOMINION
The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the headings Share Ownership-Director and Officer Share Ownership and
Significant Shareholders in the 2013 Proxy Statement is incorporated by reference.
The information regarding equity
securities of Dominion that are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation-Equity Compensation Plans in the 2013 Proxy Statement is incorporated by reference.
VIRGINIA POWER
The
table below sets forth as of February 15, 2013, the number of shares of Dominion common stock owned by directors and executive officers of Virginia Power named on the Summary Compensation 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) |
|
Thomas F. Farrell II |
|
|
624,714 |
|
|
|
335,782 |
|
|
|
960,496 |
|
Mark F. McGettrick |
|
|
175,794 |
|
|
|
113,510 |
|
|
|
289,304 |
|
Steven A. Rogers |
|
|
53,431 |
|
|
|
11,368 |
|
|
|
64,799 |
|
David A. Christian |
|
|
86,198 |
|
|
|
68,250 |
|
|
|
154,448 |
|
David A. Heacock |
|
|
28,315 |
|
|
|
16,240 |
|
|
|
44,555 |
|
Paul D. Koonce |
|
|
69,099 |
|
|
|
67,754 |
|
|
|
136,853 |
|
All directors and executive officers as a group (8 persons)(2) |
|
|
1,082,890 |
|
|
|
637,935 |
|
|
|
1,720,825 |
|
(1) |
Includes shares as to which voting and/or investment power is shared with or controlled by another person as follows: Mr. Farrell, 20,000
(shares held jointly); Mr. Rogers, 669 (shares held in joint tenancy); all directors and executive officers as a group, 36,138. |
(2) |
Neither any individual director or executive officer, nor all of the directors and executive officers as a group, own more than one percent of
Dominion common shares outstanding as of February 15, 2013. |
Item 13. Certain
Relationships and Related Transactions, and Director Independence
DOMINION
The information regarding related party transactions required by this item found under the heading Related Party Transactions, and information
regarding director independence found under the heading Director Independence, in the 2013 Proxy Statement is incorporated by reference.
VIRGINIA POWER
Related
Party Transactions
Virginia Powers Board of Directors has adopted the Related Party Guidelines also approved by Dominions
Board of
Direc-
tors. 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 Dominions 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.
Dominions 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 partys only relationship is as an employee, if the aggregate amount involved does not exceed the greater of $1 million or 2% of that companys gross revenues; and charitable contributions which are less
than the greater of $1 million or 2% of the charitys annual receipts. The full text of the guidelines can be found on Dominions 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. Management reviews the potential related party transactions and assesses whether any of the identified transactions constitute a related party transaction. Any identified related party transactions are then reported to
Dominions CGN Committee. Dominions CGN Committee reviews and considers relevant facts and circumstances and determines whether to ratify or approve the related party transactions identified. Dominions 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 Powers Code of Ethics.
Since January 1, 2012, there have been no related party transactions involving Virginia Power that were required either to be
approved under Virginia Powers policies or reported under the SEC related party transactions rules.
Director Independence
Under NYSE listing standards, Messrs. Farrell, McGettrick and Rogers are not independent as they were executive officers of Virginia Power or of its parent company, Dominion. All of Virginia Powers
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 preferred stock
listed on the NYSE, it is exempt under Section 303A of the NYSE 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 accountant fees and services contained under the heading Auditors-Fees and Pre-Approval Policy
in the 2013 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, 2012 and 2011.
|
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|
|
|
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|
|
|
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 Powers annual consolidated financial statements, the review of financial statements included in Virginia Powers 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.
Virginia Powers Board of Directors has adopted the Dominion Audit Committee pre-approval policy for its independent auditors
services and fees and has delegated the execution of this policy to the Dominion Audit Committee. In accordance with this delegation, each year the Dominion Audit Committee pre-approves a schedule that details the services to be provided for the
following year and an estimated charge for such services. At its December 2012 meeting, the Dominion Audit Committee approved Virginia Powers schedule of services and fees for 2013. In accordance with the pre-approval policy, any changes to
the pre-approved schedule may be pre-approved by the Dominion Audit Committee or a member of the Dominion Audit Committee.
Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) Certain documents are filed as part of this
Form 10-K and are incorporated by reference and found on the pages noted.
1. Financial Statements
See Index on page 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 note
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|
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 March 3, 2011 (Exhibit 3.1b, Form 10-Q filed April 29, 2011, File No.
1-2255). |
|
|
|
|
|
|
X |
|
|
|
|
|
3.2.a |
|
Dominion Resources, Inc. Amended and Restated Bylaws, effective December 13, 2011 (Exhibit 3.1, Form 8-K filed December 14, 2011, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
3.2.b |
|
Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255). |
|
|
|
|
|
|
X |
|
|
|
|
|
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); Ninety-Second Supplemental Indenture, dated as of July 1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255). |
|
|
X |
|
|
|
X |
|
|
|
|
|
4.3 |
|
Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank
(formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of 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 |
|
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X |
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|
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). |
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4.4 |
|
Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank
(formerly The Chase Manhattan Bank)) as supplemented by a 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). |
|
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X |
|
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|
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4.5 |
|
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). |
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X |
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4.6 |
|
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 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit
2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2, Form 8-A filed December 12, 1996, File No. 1-3196 and relating to the
6 5/8% Debentures Due December 1, 2008);
Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of
October 20, 1998 (Exhibit 2, Form 8-A filed October 22, 1998, File No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K
for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196, and relating to the
7 1/4% Notes Due October 1, 2004); Second
Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.4, Form 8-K filed July 3, 2007, File No. 1-8489). |
|
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X |
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|
4.7 |
|
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 |
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X |
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|
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|
|
|
|
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). |
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|
4.8 |
|
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 |
|
|
|
|
|
|
|
4.9 |
|
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 |
|
|
|
|
|
|
|
4.10 |
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
4.12 |
|
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 |
|
DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31,
2011 filed February 28, 2012, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.2 |
|
DRS Services Agreement, dated as of January 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (Exhibit 10.2, Form 10-K for the fiscal year
ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255). |
|
|
|
|
|
|
X |
|
|
|
|
|
10.3 |
|
Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No.
1-8489). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.4 |
|
$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. 1-8489
and File No. 1-2255), as amended October 1, 2011 (Exhibit 10.1, Form 8-K filed October 3, 2011, File No. 1-8489 and File No. 1-2255). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.5 |
|
$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. 1-8489 and File No.
1-2255), as amended October 1, 2011 (Exhibit 10.2, Form 8-K filed October 3, 2011, File No. 1-8489 and File No. 1-2255). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.6 |
|
Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State
of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003 filed May 9,
2003, File No. 1-8489 and File No. 1-2255). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.7* |
|
Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No.
1-8489). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.8* |
|
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 |
|
|
|
|
|
10.9* |
|
Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1,
Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.10* |
|
Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No.
1-8489). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.11* |
|
Dominion Resources, Inc. Executives Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No.
1-8489). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.12* |
|
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 |
|
|
|
|
|
10.14* |
|
Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed
March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.15* |
|
Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1,
2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.16* |
|
Dominion Resources, Inc. Directors Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended
September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.17* |
|
Dominion Resources, Inc. Non-Employee Directors Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for
the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No.
1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.18* |
|
Dominion Resources, Inc. 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 |
|
|
|
|
|
10.19* |
|
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011 (Exhibit 10.22, Form 10-K filed February 28, 2011,
File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.20* |
|
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 |
|
|
|
|
|
10.21* |
|
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 |
|
|
|
|
|
|
|
|
|
10.22* |
|
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 |
|
|
|
|
|
|
|
|
|
10.23* |
|
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 |
|
|
|
|
|
|
|
|
|
10.24* |
|
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 |
|
|
|
|
|
|
|
|
|
10.25* |
|
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 |
|
|
|
|
|
10.26* |
|
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 |
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
10.29* |
|
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 |
|
|
|
|
|
10.30* |
|
Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective December 20, 2011 (Exhibit 10.32, Form 10-K for the
fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.31* |
|
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 |
|
|
|
|
|
10.32* |
|
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 |
|
|
|
|
|
10.33* |
|
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 |
|
|
|
|
|
10.35* |
|
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 |
|
|
|
|
|
10.36* |
|
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 |
|
|
|
|
|
10.42* |
|
Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.43* |
|
Non-employee directors annual compensation for Dominion Resources, Inc. (filed herewith). |
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2012, filed on
February 28, 2013, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated
Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. |
|
|
X |
|
|
|
X |
|
* |
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 Virginia Electric and
Power Company specifically incorporates it by reference. |
Signatures
DOMINION
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
|
|
|
DOMINION RESOURCES, INC. |
|
|
By: |
|
/S/ THOMAS F. FARRELL
II |
|
|
(Thomas F. Farrell II, Chairman, President and Chief Executive Officer) |
Date: February 28, 2013
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, 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/ ROBERT H.
SPILMAN, JR. Robert H. Spilman,
Jr. |
|
Director |
|
|
/S/ MICHAEL E.
SZYMANCZYK Michael E. Szymanczyk |
|
Director |
|
|
/S/ DAVID A.
WOLLARD David A. Wollard |
|
Director |
|
|
/S/ MARK F.
MCGETTRICK Mark F.
McGettrick |
|
Executive Vice President and Chief Financial Officer |
|
|
/S/ ASHWINI
SAWHNEY Ashwini Sawhney |
|
Vice PresidentAccounting and Controller (Chief Accounting Officer) |
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, 2013
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, 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 President-Accounting (Chief Accounting Officer) |
|
|
/S/ STEVEN A.
ROGERS Steven A. Rogers |
|
Director |
Exhibit Index
|
|
|
|
|
|
|
|
|
|
|
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 March 3, 2011 (Exhibit 3.1b, Form 10-Q filed April 29, 2011, File No.
1-2255). |
|
|
|
|
|
|
X |
|
|
|
|
|
3.2.a |
|
Dominion Resources, Inc. Amended and Restated Bylaws, effective December 13, 2011 (Exhibit 3.1, Form 8-K filed December 14, 2011, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
3.2.b |
|
Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255). |
|
|
|
|
|
|
X |
|
|
|
|
|
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); Ninety-Second Supplemental Indenture, dated as of July 1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255). |
|
|
X |
|
|
|
X |
|
|
|
|
|
4.3 |
|
Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank
(formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of 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 |
|
|
|
|
|
4.4 |
|
Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank
(formerly The Chase Manhattan Bank)) as supplemented by a First Supplemental Indenture, dated December 1, 1997 |
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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). |
|
|
|
|
|
|
|
|
|
|
4.5 |
|
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 |
|
|
|
|
|
|
|
4.6 |
|
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 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit
2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2, Form 8-A filed December 12, 1996, File No. 1-3196 and relating to the
6 5/8% Debentures Due December 1, 2008);
Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of
October 20, 1998 (Exhibit 2, Form 8-A filed October 22, 1998, File No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K
for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196, and relating to the
7 1/4% Notes Due October 1, 2004); Second
Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.4, Form 8-K filed July 3, 2007, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
4.7 |
|
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 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 |
|
|
|
|
|
|
|
|
|
|
|
|
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). |
|
|
|
|
|
|
|
|
|
|
4.8 |
|
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 |
|
|
|
|
|
|
|
4.9 |
|
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 |
|
|
|
|
|
|
|
4.10 |
|
Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File
No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
4.11 |
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit
Number |
|
Description |
|
Dominion |
|
|
Virginia Power |
|
4.12 |
|
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 |
|
DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31,
2011 filed February 28, 2012, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.2 |
|
DRS Services Agreement, dated as of January 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (Exhibit 10.2, Form 10-K for the fiscal year
ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255). |
|
|
|
|
|
|
X |
|
|
|
|
|
10.3 |
|
Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No.
1-8489). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.4 |
|
$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. 1-8489
and File No. 1-2255), as amended October 1, 2011 (Exhibit 10.1, Form 8-K filed October 3, 2011, File No. 1-8489 and File No. 1-2255). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.5 |
|
$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. 1-8489 and File No.
1-2255), as amended October 1, 2011 (Exhibit 10.2, Form 8-K filed October 3, 2011, File No. 1-8489 and File No. 1-2255). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.6 |
|
Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State
of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003,
File No. 1-8489 and File No. 1-2255). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.7* |
|
Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File
No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.8* |
|
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 |
|
|
|
|
|
10.9* |
|
Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1,
Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.10* |
|
Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No.
1-8489). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.11* |
|
Dominion Resources, Inc. Executives Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No.
1-8489). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.12* |
|
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 |
|
|
|
|
|
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 |
|
|
X |
|
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
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). |
|
|
|
|
|
|
|
|
|
|
|
|
10.14* |
|
Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed
March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.15* |
|
Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1,
2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.16* |
|
Dominion Resources, Inc. Directors Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30,
2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.17* |
|
Dominion Resources, Inc. Non-Employee Directors Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for
the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No.
1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.18* |
|
Dominion Resources, Inc. 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 |
|
|
|
|
|
10.19* |
|
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011 (Exhibit 10.22, Form 10-K filed February 28, 2011,
File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.20* |
|
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 |
|
|
|
|
|
10.21* |
|
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 |
|
|
|
|
|
|
|
|
|
10.22* |
|
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 |
|
|
|
|
|
|
|
|
|
10.23* |
|
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 |
|
|
|
|
|
|
|
|
|
10.24* |
|
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 |
|
|
|
|
|
|
|
|
|
10.25* |
|
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 |
|
|
|
|
|
10.26* |
|
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 |
|
|
|
|
|
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 |
|
|
|
|
|
10.29* |
|
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 |
|
|
|
|
|
10.30* |
|
Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective December 20, 2011 (Exhibit 10.32, Form 10-K for the
fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255). |
|
|
X |
|
|
|
X |
|
|
|
|
|
10.31* |
|
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 |
|
|
|
|
|
10.32* |
|
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 |
|
|
|
|
|
10.33* |
|
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 |
|
|
|
|
|
10.35* |
|
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 |
|
|
|
|
|
10.36* |
|
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 |
|
|
|
|
|
10.42* |
|
Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith). |
|
|
X |
|
|
|
|
|
|
|
|
|
10.43* |
|
Non-employee directors annual compensation for Dominion Resources, Inc. (filed herewith). |
|
|
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 |
|
|
|
|
|
|
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|
|
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|
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, 2012, filed on
February 28, 2013, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated
Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. |
|
|
X |
|
|
|
X |
|
* |
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 Virginia Electric and
Power Company specifically incorporates it by reference. |