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, 2014
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 |
001-08489 |
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DOMINION RESOURCES, INC. |
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54-1229715 |
000-55337 |
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VIRGINIA ELECTRIC AND POWER COMPANY |
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54-0418825 |
000-55338 |
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DOMINION GAS HOLDINGS, LLC |
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46-3639580 |
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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 |
2013 Series A 6.125% Corporate Units |
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New York Stock Exchange |
2013 Series B 6% Corporate Units |
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New York Stock Exchange |
2014 Series A 6.375% Corporate Units |
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
VIRGINIA ELECTRIC AND POWER COMPANY
Common Stock, no par value
DOMINION GAS HOLDINGS, LLC
Limited Liability Company Membership Interests
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 ¨ Dominion Gas
Holdings, LLC 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 Dominion Gas
Holdings, LLC 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 ¨ Dominion Gas
Holdings, LLC 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 ¨ Dominion Gas
Holdings, LLC 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. ¨ Virginia Electric and Power
Company x Dominion Gas Holdings,
LLC 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 ¨ |
Dominion Gas Holdings, LLC
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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 Dominion Gas
Holdings, LLC Yes ¨ No x
The aggregate market value of Dominion Resources, Inc. common stock held by non-affiliates of Dominion was approximately $41.1 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, 2015, Dominion had 588,138,107 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding. Dominion Resources, Inc. holds all of the membership interests of
Dominion Gas Holdings, LLC.
DOCUMENT INCORPORATED BY REFERENCE.
Portions of Dominions 2015 Proxy Statement are incorporated by reference in Part III.
This combined Form 10-K represents separate filings by Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings,
LLC. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Virginia Electric and Power Company and Dominion Gas Holdings, LLC make no representations as to the information relating
to Dominion Resources, Inc.s other operations.
VIRGINIA ELECTRIC AND POWER COMPANY AND DOMINION GAS HOLDINGS, LLC MEET THE
CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND ARE FILING THIS FORM 10-K UNDER THE REDUCED DISCLOSURE FORMAT.
Dominion Resources, Inc., Virginia Electric and
Power Company and Dominion Gas Holdings, LLC
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 |
2013 Biennial Review Order |
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Order issued by the Virginia Commission in November 2013 concluding the 20112012 biennial review of Virginia Powers base
rates, terms and conditions |
2013 Equity Units |
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Dominions 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013 |
2014 Equity Units |
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Dominions 2014 Series A Equity Units issued in July 2014 |
2015 Proxy Statement |
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Dominion 2015 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 |
Altavista |
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Altavista power station |
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 |
Atlantic Coast Pipeline |
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Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion, Duke Energy Corporation, Piedmont Natural Gas Company, Inc.
and AGL Resources Inc. |
Atlantic Coast Pipeline project |
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The approximately 550-mile natural gas pipeline running from West Virginia through Virginia to North Carolina which will be owned by
Dominion, Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources and constructed and operated by DTI |
BACT |
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Best available control technology |
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 |
Blue Racer |
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Blue Racer Midstream, LLC, a joint venture with Caiman |
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 1,358 MW combined cycle, natural gas-fired power station under construction 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 |
CAP |
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IRS Compliance Assurance Process |
CCR |
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Coal combustion residual |
CD&A |
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Compensation Discussion and Analysis |
CEA |
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Commodity Exchange Act |
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 |
CGT |
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Carolina Gas Transmission Corporation |
Chesapeake |
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Chesapeake power station |
Clean Power Plan |
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Guidelines proposed by the EPA in June 2014 for states to follow in developing plans to reduce CO2 emissions from existing fossil fuel-fired electric generating units |
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, Virginia Power and Dominion Gas, 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 |
Corporate Unit |
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A stock purchase contract and 1/20 interest in a RSN issued by Dominion |
Cove Point |
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Dominion Cove Point LNG, LP |
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Abbreviation or Acronym |
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Definition |
Cove Point Holdings |
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Cove Point GP Holding Company, LLC |
CPCN |
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Certificate of Public Convenience and Necessity |
Crayne interconnect |
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DTIs interconnect with Texas Eastern Transmission, LP in Greene County, Pennsylvania |
CSAPR |
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Cross State Air Pollution Rule |
CWA |
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Clean Water Act |
DEI |
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Dominion Energy, Inc. |
D.C. |
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District of Columbia |
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 Dominion Gas) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries |
Dominion
Direct® |
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A dividend reinvestment and open enrollment direct stock purchase plan |
Dominion Gas |
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The legal entity, Dominion Gas Holdings, LLC (a single member limited liability company), one or more of its consolidated subsidiaries
or operating segment, or the entirety of Dominion Gas Holdings, LLC and its consolidated subsidiaries |
Dominion Gas 2013 Senior Notes |
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The $400 million 2013 Series A 1.05% Senior Notes due 2016, $400 million 2013 Series B 3.55% Senior Notes due 2023 and $400 million 2013
Series C 4.80% Senior Notes due 2043 |
Dominion Iroquois |
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Dominion Iroquois, Inc. |
Dominion Midstream |
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The legal entity, Dominion Midstream Partners, LP, its consolidated subsidiary Cove Point Holdings, or the entirety of Dominion
Midstream Partners, LP, and its consolidated subsidiary |
Dominion NGL Pipelines, LLC |
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The initial owner of the 58-mile G-150 pipeline project, which is designed to transport approximately 27,000 barrels per day of NGLs
from Natrium to an interconnect with the Appalachia to Texas Express ethane line of Enterprise Product Partners, L.P. near Follansbee, West Virginia |
DRS |
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Dominion Resources Services, Inc. |
DSM |
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Demand-side management |
Dth |
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Dekatherm |
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 |
EA |
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Environmental assessment |
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 |
EPA |
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Environmental Protection Agency |
EPACT |
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Energy Policy Act of 2005 |
EPC |
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Engineering, procurement and construction |
EPCRA |
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Emergency Planning and Community Right-to-Know Act |
EPS |
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Earnings per share |
ERISA |
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The Employee Retirement Income Security Act of 1974 |
ERM |
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Enterprise Risk Management |
ERO |
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Electric Reliability Organization |
ESBWR |
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General Electric-Hitachis Economic Simplified Boiling Water Reactor |
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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First phase of 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 |
Gal |
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Gallon |
GHG |
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Greenhouse gas |
Green Mountain |
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Green Mountain Power Corporation |
Hastings |
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A natural gas processing and fractionation facility located near Pine Grove, West Virginia |
HATFA of 2014 |
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Highway and Transportation Funding Act of 2014 |
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 |
House Bill 95 |
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Ohio utility reform legislation effective September 2011 |
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Abbreviation or Acronym |
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Definition |
Illinois Gas Contracts |
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A Dominion Retail, Inc. natural gas book of business consisting of residential and commercial customers in Illinois |
INPO |
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Institute of Nuclear Power Operations |
IRCA |
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Intercompany revolving credit agreement |
Iroquois |
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Iroquois Gas Transmission System L.P. |
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 |
JD Power |
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J.D. Power and Associates |
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 |
Liability Management Exercise |
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Dominion exercise in 2014 to redeem certain debt and preferred securities |
LIBOR |
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London Interbank Offered Rate |
LIFO |
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Last-in-first-out inventory method |
Line TPL-2A |
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An approximately 11-mile, 30-inch gathering pipeline extending from Tuscarawas County, Ohio to Harrison County, Ohio |
Line TL-388 |
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A 37-mile, 24-inch gathering pipeline extending from Texas Eastern, LP in Noble County, Ohio to its terminus at Dominions Gilmore
Station in Tuscarawas County, Ohio |
Line TL-404 |
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An approximately 26-mile, 24- and 30- inch gas gathering pipeline that extends from Wetzel County, West Virginia to Monroe County,
Ohio |
Liquefaction Project |
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A natural gas export/liquefaction facility currently under construction by Cove Point |
LNG |
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Liquefied natural gas |
LTIP |
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Long-term incentive program |
MAP 21 Act |
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Moving Ahead for Progress in the 21st Century Act |
Maryland Commission |
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Maryland Public Service Commission |
Massachusetts Municipal |
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Massachusetts Municipal Wholesale Electric Company |
MATS |
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Utility Mercury and Air Toxics Standard Rule |
mcf |
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thousand cubic feet |
MD&A |
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Managements Discussion and Analysis of Financial Condition and Results of Operations |
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 |
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. |
MLP |
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Master limited partnership, also known as publicly traded partnership |
Moodys |
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Moodys Investors Service |
MW |
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Megawatt |
MWh |
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Megawatt hour |
NAAQS |
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National Ambient Air Quality Standards |
Natrium |
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A natural gas and fractionation facility located in Natrium, West Virginia, owned by Blue Racer |
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 Carolina Commission |
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North Carolina Utilities Commission |
Northern System |
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Collection of approximately 131 miles of various diameter natural gas pipelines in Ohio |
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 |
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Abbreviation or Acronym |
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Definition |
October 2014 hybrids |
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2014 Series A Enhanced Junior Subordinated Notes due 2054 |
ODEC |
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Old Dominion Electric Cooperative |
Ohio Commission |
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Public Utilities Commission of Ohio |
Order 1000 |
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Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development |
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 |
Philadelphia Utility Index |
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Philadelphia Stock Exchange Utility Index |
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 deployed by East Ohio |
PIR |
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Pipeline Infrastructure Replacement program deployed by East Ohio |
PJM |
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PJM Interconnection, L.L.C. |
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 |
PSD |
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Prevention of significant deterioration |
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, as amended in 2015 |
REIT |
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Real estate investment trust |
RGGI |
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Regional Greenhouse Gas Initiative |
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 |
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 T1 |
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A rate adjustment clause to recover the difference between revenues produced from transmission rates included in base rates, and the new
total revenue requirement developed annually for the rate years effective September 1 |
Rider U |
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A rate adjustment clause associated with the recovery of costs of new underground distribution facilities |
Rider US-1 |
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A rate adjustment clause associated with the recovery of costs related to Remington Solar Facility |
Rider W |
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A rate adjustment clause associated with the recovery of costs related to Warren County |
Riders C1A and C2A |
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Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in DSM cases |
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 |
RSN |
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Remarketable subordinated note |
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 |
SELC |
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Southern Environmental Law Center |
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 |
TSR |
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Total shareholder return |
U.S. |
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United States of America |
UAO |
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Unilateral Administrative Order |
UEX Rider |
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Uncollectible Expense Rider deployed by East Ohio |
VDEQ |
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Virginia Department of Environmental Quality |
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Abbreviation or Acronym |
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Definition |
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 |
VOWTAP |
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Virginia Offshore Wind Technology Advancement Project |
Warren County |
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A 1,342 MW combined-cycle, natural gas-fired power station in Warren County, Virginia |
West Virginia Commission |
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Public Service Commission of West Virginia |
Western System |
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Collection of approximately 212 miles of various diameter natural gas pipelines and three compressor stations in Ohio |
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. As of December 31, 2014, Dominions portfolio of assets includes approximately 24,600 MW of generating capacity, 6,400 miles of electric transmission lines, 57,100 miles of electric distribution lines, 10,900 miles of natural
gas transmission, gathering and storage pipeline and 21,900 miles of gas distribution pipeline, exclusive of service lines. As of December 31, 2014, Dominion serves over 5 million utility and retail energy customers in 10 states and
operates one of the nations largest underground natural gas storage systems, with approximately 947 bcf of storage capacity.
In September 2013, Dominion announced its plans to form an MLP in 2014 by contributing certain of its midstream natural gas assets to the MLP initially and over time. In October 2014, Dominion Midstream
launched its initial public offering and issued 20,125,000 common units representing limited partner interests, which included a 2,625,000 common unit over-allotment option that was exercised in full by the underwriters. Dominion owns the general
partner and 68.5% of the limited partner interests in Dominion Midstream, which owns a preferred equity interest and the general partner interest in Cove Point. Dominion Midstream is consolidated by Dominion, and is an SEC registrant. However, its
Form 10-K is filed separately and is not combined herein.
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. With this investment, Dominion expects 80% to 90% of future earnings from its primary
operating segments to come from regulated and long-term contracted businesses.
Dominion continues to expand and improve its
regulated and long-term contracted electric and natural gas businesses, in accordance with its six-year capital investment program. A major impetus for this program is to meet the anticipated increase in 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, to upgrade Dominions gas and electric
transmission and distribution networks, and to meet environmental requirements and standards set by various regulatory bodies. Investments in utility solar generation are expected to be a focus in meeting such environmental requirements,
particularly in Virginia. Investments to gather and process natural gas production from the Utica Shale formation, in eastern Ohio and western Pennsylvania, are being made by the Blue Racer joint venture. In September 2014, Dominion announced the
formation of Atlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately 550-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, to increase natural gas supplies in the region.
Dominion has transitioned to a more regulated, less volatile earnings mix as evidenced by
its capital investments in regulated infrastructure and infrastructure whose output is sold under long-term purchase agreements, as well as dispositions of certain merchant generation facilities during 2013 and the sale of the electric retail energy
marketing business in March 2014. Dominions nonregulated operations include merchant generation, energy marketing and price risk management activities and natural gas retail energy marketing operations. Dominions operations are
conducted through various subsidiaries, including Virginia Power and Dominion Gas.
Virginia Power, headquartered in
Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a wholly-owned subsidiary of Dominion and 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 stock is owned by Dominion.
Dominion Gas, a limited liability
company formed in September 2013, is a wholly-owned subsidiary of Dominion and a holding company. It serves as the intermediate parent company for the majority of Dominions regulated natural gas operating subsidiaries, which conduct business
activities through a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution operations in Ohio, and gas gathering and
processing activities primarily in West Virginia, Ohio and Pennsylvania. Dominion Gas wholly-owned subsidiaries are DTI, East Ohio and Dominion Iroquois. DTI is an interstate natural gas transmission pipeline company serving a broad mix of
customers such as local gas distribution companies, marketers, interstate and intrastate pipelines, electric power generators and natural gas producers. The DTI system links to other major pipelines and markets in the mid-Atlantic, Northeast, and
Midwest including Dominions Cove Point pipeline. DTI also operates one of the largest underground natural gas storage systems in the U.S. and is a producer and supplier of NGLs. East Ohio is a regulated natural gas distribution operation
serving residential, commercial and industrial gas sales and transportation customers. Its service territory includes Cleveland, Akron, Canton, Youngstown and other eastern and western Ohio communities. Dominion Iroquois holds a 24.72% general
partnership interest in a 416-mile FERCregulated interstate natural gas pipeline extending from the U.S.-Canadian border at Waddington, New York through the state of Connecticut to South Commack, New York and Hunts Point, Bronx, New York. All
of Dominion Gas membership interests are owned by Dominion.
Amounts and information disclosed for Dominion are inclusive
of Virginia Power and/or Dominion Gas, where applicable.
EMPLOYEES
As of
December 31, 2014, Dominion had approximately 14,400 full-time employees, of which approximately 5,300 employees are subject to collective bargaining agreements. As of December 31, 2014, Virginia Power had approximately 6,800
full-time employees, of which approximately 3,100 employees are subject to collective bargaining agreements. As of December 31, 2014, Dominion Gas had approximately 2,800 full-time employees, of which approximately 2,000 employees are subject
to collective bargaining agreements.
WHERE YOU CAN FIND MORE INFORMATION ABOUT
THE COMPANIES
The Companies 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.
The
Companies 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,
http://www.dom.com, as soon as reasonably practicable after filing or furnishing the material to the SEC. Information contained on Dominions website is not incorporated by reference in this report.
ACQUISITIONS AND DISPOSITIONS
Following are
significant acquisitions and divestitures by the Companies during the last five years.
ACQUISITION OF
SOLAR DEVELOPMENT PROJECTS
Throughout 2014, Dominion completed the acquisitions of 100% of
the equity interests in various solar development projects in California for approximately $200 million. The projects are expected to cost approximately $599 million to construct, including the initial acquisition cost, and are expected to generate
approximately 179 MW. See Note 3 to the Consolidated Financial Statements for additional information on solar acquisitions.
SALE OF ELECTRIC RETAIL ENERGY MARKETING
BUSINESS
In March 2014, Dominion completed the sale of its electric retail energy marketing business. The proceeds were
approximately $187 million, net of transaction costs. The sale of the electric retail energy marketing business did not qualify for discontinued operations classification. See Note 3 to the Consolidated Financial Statements for additional
information.
SALE OF PIPELINES AND PIPELINE
SYSTEMS
In March 2014, Dominion Gas sold the Northern System to an affiliate that subsequently sold the Northern System to
Blue Racer
for consideration of approximately $84 million. Dominion Gas consideration consisted of $17 million in cash proceeds and the extinguishment of affiliated current borrowings of $67 million
and Dominions consideration consisted of cash proceeds of approximately $84 million.
In September 2013, DTI sold Line
TL-388 to Blue Racer for approximately $75 million in cash proceeds.
In December 2012, East Ohio sold two pipeline systems to
an affiliate for consideration of approximately $248 million. East Ohios consideration consisted of $61 million in cash proceeds and the extinguishment of affiliated long-term debt of $187 million and Dominions consideration consisted of
a 50% interest in Blue Racer and cash proceeds of approximately $115 million.
See Note 9 to the Consolidated Financial
Statements for additional information on sales of pipelines and pipeline systems.
ASSIGNMENTS OF
MARCELLUS SHALE ACREAGE
In November 2014, DTI closed an agreement with a natural gas producer
to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provides for payments to DTI, subject to customary adjustments, of approximately $120 million over a
period of four years, and an overriding royalty interest in gas produced from the acreage.
In December 2013, DTI closed on
agreements with two natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several natural gas storage fields. The agreements provide for payments to DTI, subject to customary
adjustments, of approximately $200 million over a period of nine years, and overriding royalty interest in gas produced from that acreage.
See Note 10 to the Consolidated Financial Statements for additional information on these sales of Marcellus acreage.
SALE OF BRAYTON POINT, KINCAID AND EQUITY METHOD INVESTMENT
IN ELWOOD
In August 2013, Dominion completed the sale of Brayton Point, Kincaid and its equity method
investment in Elwood to Energy Capital Partners and received proceeds of approximately $465 million, net of transaction costs. The historical results of Brayton Points and Kincaids 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.
SALE OF E&P PROPERTIES
In April 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.
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.
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 discontinued, which is discussed in Note 3 to the Consolidated Financial Statements. In addition, Corporate and Other includes
specific items attributable to Dominions other 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.
Dominion Gas manages its daily operations through its primary operating segment: Dominion Energy. It also
reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segments performance.
While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by the Companies 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 |
|
Description of Operations |
|
Dominion |
|
|
Virginia
Power |
|
|
Dominion
Gas |
|
DVP |
|
Regulated electric distribution |
|
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X |
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X |
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Regulated electric transmission |
|
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X |
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X |
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|
Dominion Generation |
|
Regulated electric fleet |
|
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X |
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X |
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Merchant electric fleet |
|
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X |
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Nonregulated retail energy marketing |
|
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X |
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Dominion Energy |
|
Gas transmission and storage |
|
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X |
(1) |
|
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X |
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Gas distribution and storage |
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X |
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X |
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Gas gathering and processing |
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X |
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X |
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LNG import and storage |
|
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X |
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(1) |
Includes remaining producer services activities. |
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 the Companies 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 Dominion and Virginia Power includes Virginia Powers
regulated electric transmission and
dis-
tribution (including customer service) operations, which serve approximately 2.5 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.
DVP announced its six-year investment plan, which includes spending approximately $8.9 billion from 2015 through 2020 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.
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. Virginia Power continues
to see improvement as SAIDI performance results, excluding major events, were 113 minutes at the end of 2014, down from the three-year average of 120 minutes. Virginia Powers overall customer satisfaction improved year over year when compared
to its 2013 score in the South Large segment of JD Powers rankings. In the future, safety, electric service reliability and customer service will remain key focus 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.
COMPETITION
DVP
Operating SegmentDominion and Virginia Power
There is no competition for electric distribution service within Virginia Powers
service territory in Virginia and North Carolina and no such competition is currently permitted. Historically, since its electric transmission facilities are integrated into PJM and electric transmission services are administered by PJM, there was
no competition in relation to transmission service provided to customers within the PJM region. However, competition from non-incumbent PJM transmission owners for development, construction and ownership of certain transmission facilities in
Virginia Powers service territory is now permitted pursuant to FERC Order 1000, subject to state and local siting and
permit-
ting approvals. This could result in additional competition to build transmission lines in Virginia Powers service area in the future and could allow Dominion to seek opportunities to build
facilities in other service territories.
REGULATION
DVP Operating SegmentDominion and Virginia Power
Virginia Powers electric
retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia and North Carolina Commissions. 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 2013 Biennial Review Order.
PROPERTIES
DVP
Operating SegmentDominion and Virginia Power
Virginia Power has approximately 6,400 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.
As a part of PJMs RTEP process, PJM authorized the following material reliability projects
(including estimated cost):
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Mt. Storm-to-Doubs line ($336 million); |
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Surry-to-Skiffes Creek-to-Whealton lines ($150 million); |
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Dooms-to-Lexington line ($112 million); |
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Cunningham-to-Dooms ($100 million); and |
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Landstown voltage regulation project ($70 million). |
The following material reliability projects (including estimated cost) are awaiting PJM authorization:
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Warrenton project (including Remington CT-to-Warrenton, Vint Hill-to-Wheeler, Wheeler-to-Loudoun and Vint Hill and Wheeler switching stations) ($109
million); and |
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Cunningham-to-Elmont line ($106 million). |
Over the next 5 years, Virginia Power plans to increase transmission substation physical security and to invest in a new system operations center. Virginia Power expects to invest $300 million$500
million during that time to strengthen its electrical system to better protect critical equipment, enhance its spare equipment process, and create multiple levels of security.
In addition, Virginia Powers electric distribution network includes approximately 57,100 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.
Virginia legislation in 2014 provides for the recovery of costs, subject to approval by the Virginia Commission, for Virginia Power to
move approximately 4,000 miles of electric distribution lines underground. The program, designed to reduce restoration outage time, has an annual investment cap of approximately $175 million, and is expected to be implemented over the next decade.
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.
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 catastrophic 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 utilityrelated 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.
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. The Dominion Generation Operating Segment of Dominion includes
Virginia Powers generation facilities and its related energy supply operations as well as the generation operations of Dominions merchant fleet and energy marketing and price risk management activities for these assets and
Dominions nonregulated natural gas retail energy marketing operations.
Dominion Generations six-year electric
utility investment plan includes spending approximately $9.7 billion from 2015 through 2020 to construct new generation capacity to meet growing electricity demand within its utility service territory. The most significant project currently
under construction is Brunswick County, which is estimated to cost approximately $1.2 billion, excluding financing costs. See Properties for additional information on this and other utility projects.
In addition, Dominions merchant fleet has acquired and developed numerous renewable generation projects, which began operations in
2013 and 2014. The total cost of the projects is approximately $856 million, excluding financing costs, and includes a fuel cell generation facility in Connecticut and solar generation facilities in California, Indiana, Georgia, Tennessee and
Connecticut. The output of these facilities is sold under long-term power purchase agreements with terms ranging from 15 to
25 years. See Note 3 to the Consolidated Financial Statements for additional information regarding certain solar acquisitions.
Earnings for the Dominion 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. Base rates for the Virginia jurisdiction are set
using a modified cost-of-service rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. Earnings variability may arise
when revenues are impacted by factors not reflected in current rates, such as the impact of weather on customers demand for services. Likewise, earnings may reflect variations in the timing or nature of expenses as compared to those
contemplated in current rates, such as labor and benefit costs, capacity expenses, and the timing, duration and costs of scheduled and unscheduled outages. 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. The cost of new generation facilities is generally recovered through rate adjustment clauses in Virginia. Variability in earnings from rate adjustment clauses reflects
changes in the authorized ROE and the carrying amount of these facilities, which are largely driven by the timing and amount of capital investments, as well as depreciation. 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 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 nonrenewable 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 the electric price volatility of its merchant fleet by hedging a substantial portion of its expected near-term energy sales with derivative instruments.
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. In 2012 and 2013, Dominion sold or began decommissioning several of its merchant
generation facilities, including Brayton Point, Kincaid, State Line, Salem Harbor and Kewaunee.
Dominions retail energy
marketing operations compete in nonregulated energy markets. In March 2014, Dominion completed the sale of its electric retail energy marketing business; however, it still participates in the retail natural gas and energy-related products and
services businesses. The remaining customer base includes approximately 1.3 million customer accounts. Dominion has a heavy concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice.
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 nonrenewable merchant generation fleet is
dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that provides for a rate of return on its capital investments. Dominion Generations recently acquired and developed renewable
generation projects are not subject to significant competition as the output from these facilities is primarily sold under long-term power purchase agreements lasting between 15 and 25 years. Competition for the nonrenewable 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 nonrenewable merchant assets 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 nonrenewable 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 nonrenewable merchant fleet is competitive compared to similar assets within the region.
Dominions retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy
markets for natural gas. 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
Dominion Generation Operating SegmentDominion and Virginia Power
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 and Note 13 to the Consolidated Financial Statements 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 approximately 20,400 MW. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro, renewables, and power purchase agreements. Virginia Powers generation
facilities are located in Virginia, West Virginia and North Carolina and serve load in Virginia and northeastern North Carolina.
Virginia Power is developing, financing, and constructing new generation capacity to meet growing electricity demand within its service
territory. Significant projects under construction or development are set forth below:
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In August 2013, the Virginia Commission authorized the construction of Brunswick County, which is estimated to cost approximately $1.2 billion.
Construction of the facility commenced in the third quarter of 2013 with commercial operations expected to begin in mid- 2016. Brunswick County is expected to offset the expected reduction in capacity caused by the retirement of coal-fired units at
Chesapeake in December 2014 and at Yorktown as early as 2016, primarily due to the cost of compliance with MATS. |
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In January 2015, Virginia Power filed a CPCN with the Virginia Commission to build the states first utility-scale solar facility. The 20 MW
project would be built near Virginia Powers Remington Power Station in Fauquier County. The estimated in-service date for the facility, subject to regulatory approvals, is the fourth quarter of 2016. |
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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. |
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The BOEM auctioned approximately 113,000 acres of federal land off the Virginia coast as a single lease for construction of offshore wind turbines.
Virginia Power was awarded the lease, effective November 1, 2013. BOEM has several lease milestones with which Virginia Power must comply as conditions to being awarded the lease. |
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Virginia Power is also considering the development of a commercial offshore wind generation project through a federal land lease off the Virginia
coast. Virginia Power and several partners are collaborating to develop a 12 MW offshore wind demonstration project, which is proposed to be located approximately 24 miles off the coast of Virginia. In May 2014, the DOE selected the VOWTAP as one of
three projects to receive up to $47 million of follow-on funding. This project may be operational as early as the end of 2017, pending regulatory approvals. |
Dominion Generation Operating SegmentDominion
The generation capacity of
Dominions merchant fleet totals approximately 4,200 MW. The generation mix is diversified and
includes nuclear, natural gas, and renewables. Merchant nonrenewable generation facilities are located in Connecticut, Pennsylvania and Rhode Island, with a majority of that capacity concentrated
in New England. Dominions merchant renewable generation facilities include a fuel cell generation facility in Connecticut, solar generation facilities in Indiana, Georgia, California, Tennessee and Connecticut, and wind generation facilities
in Indiana and West Virginia. Additional solar projects under construction are as set forth below:
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In September 2014, Dominion entered into agreements to acquire 100% of the equity interests in two solar projects in California from EDF Renewable
Development, Inc. for approximately $175 million. The acquisitions are expected to close in the first half of 2015 prior to the projects commencing operations. The projects are expected to cost approximately $185 million once constructed,
including the initial acquisition cost. Upon completion, the facilities are expected to generate approximately 42 MW. |
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In October 2014, Dominion acquired 100% of the equity interests of a solar project in Utah from juwi solar Inc. The project is expected to cost
approximately $120 million once constructed, including the initial acquisition cost. The facility is expected to begin commercial operations in the second half of 2015 and generate approximately 50 MW. |
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 domestic 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 and Marcellus and Utica regions, 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 provides for reliable natural gas deliveries to its gas turbine fleet, while minimizing
costs.
BiomassDominion Generations biomass supply is obtained through long-term
contracts and short-term spot agreements from local suppliers.
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 and ISO-NE 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:
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Source |
|
2014 |
|
|
2013 |
|
|
2012 |
|
Nuclear(1) |
|
|
33 |
% |
|
|
33 |
% |
|
|
33 |
% |
Purchased power, net |
|
|
19 |
|
|
|
21 |
|
|
|
27 |
|
Coal(2) |
|
|
30 |
|
|
|
29 |
|
|
|
22 |
|
Natural gas |
|
|
15 |
|
|
|
16 |
|
|
|
17 |
|
Other(3) |
|
|
3 |
|
|
|
1 |
|
|
|
1 |
|
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 2014 Virginia in-system generation was $35.30 per MWh.
|
(3) |
Includes oil, hydro and biomass. |
Dominion Generation Operating Segment-Dominion
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
Dominion Generation Operating SegmentDominion and Virginia Power
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. See DVPSeasonality above for additional considerations that also apply to Dominion Generation.
Dominion Generation Operating SegmentDominion
The earnings of Dominions retail energy marketing operations also vary seasonally. Generally, the demand for gas peaks during the winter months to meet heating needs.
NUCLEAR DECOMMISSIONING
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 are placed into trusts and are 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 requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments 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 2014. These cost studies are generally completed every four to five 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 2078.
Dominion
Generation Operating SegmentDominion
In addition to the four nuclear units discussed above, Dominion has two licensed, operating
nuclear reactors at Millstone in Connecticut. A third Millstone unit ceased operations before Dominion acquired the power station. In May 2013, Dominion ceased operations at its single unit Kewaunee nuclear power station in Wisconsin and commenced
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 decommissioning is
completed are required to be refunded to Wisconsin ratepayers. Dominion believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the
Millstone and Kewaunee units. Dominion will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial
instruments 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 for Surry, North Anna and Millstone in 2014 and for
Kewaunee in 2013.
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 (2014
dollars)(1) |
|
|
Funds in
trusts at December 31,
2014 |
|
|
2014
contributions to trusts |
|
(dollars in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Surry |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit 1 |
|
|
2032 |
|
|
$ |
576 |
|
|
$ |
547 |
|
|
$ |
0.6 |
|
Unit 2 |
|
|
2033 |
|
|
|
596 |
|
|
|
539 |
|
|
|
0.6 |
|
North Anna |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit 1(2) |
|
|
2038 |
|
|
|
493 |
|
|
|
435 |
|
|
|
0.4 |
|
Unit
2(2) |
|
|
2040 |
|
|
|
504 |
|
|
|
409 |
|
|
|
0.3 |
|
Total (Virginia Power) |
|
|
|
|
|
|
2,169 |
|
|
|
1,930 |
|
|
|
1.9 |
|
Millstone |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit 1(3) |
|
|
n/a |
|
|
|
367 |
|
|
|
450 |
|
|
|
|
|
Unit 2 |
|
|
2035 |
|
|
|
540 |
|
|
|
569 |
|
|
|
|
|
Unit 3(4) |
|
|
2045 |
|
|
|
656 |
|
|
|
559 |
|
|
|
|
|
Kewaunee |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit
1(5) |
|
|
n/a |
|
|
|
520 |
|
|
|
688 |
|
|
|
|
|
Total (Dominion) |
|
|
|
|
|
$ |
4,252 |
|
|
$ |
4,196 |
|
|
$ |
1.9 |
|
(1) |
The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on Dominions and Virginia Powers
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 and Green Mountain.
Decommissioning cost is shown at Dominions ownership percentage. At December 31, 2014, the minority owners held approximately $35 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.
|
(5) |
Permanently ceased operations in 2013. |
Also see Note 14 and Note 22 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively, and Note 9 for information about nuclear decommissioning
trust investments.
Dominion Energy
The Dominion Energy Operating Segment of Dominion Gas includes the majority of Dominions regulated natural gas operations. DTI, the gas
transmission pipeline and storage business, serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in the transmission pipeline and storage business is gas gathering and processing activity, which
sells extracted products at market rates. East Ohio, the primary gas distribution business of Dominion, serves residential, commercial and industrial gas sales, transportation and gathering service customers. Dominion Iroquois holds a 24.72% general
partnership interest in Iroquois, which provides service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, through interconnecting pipelines and exchanges primarily in
New York.
Earnings for the Dominion Energy Operating Segment of Dominion Gas primarily result
from rates established by FERC and the Ohio Commission. The profitability of these businesses is dependent on Dominion Gas ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital
investments. Variability in earnings results from changes in 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.
Revenue from processing and fractionation operations largely results from the sale of commodities at market prices. For DTIs
processing plants, Dominion Gas purchases the wet gas product from producers and retains some or all of the extracted NGLs as compensation for its services. This exposes Dominion Gas to commodity price risk for the value of the spread between
the NGL products and natural gas. In addition, Dominion Gas has volumetric risk since gas deliveries to DTIs facilities are not under long-term contracts.
East Ohio utilizes 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.
In addition to the operations of Dominion Gas, the Dominion Energy Operating Segment of Dominion also includes LNG operations and
Hopes gas distribution operations in West Virginia, as well as Dominions investments in the Blue Racer joint venture, Atlantic Coast Pipeline and Dominion Midstream. See Properties and Investments below for additional information
regarding the Atlantic Coast Pipeline investment. 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.
Dominion has received DOE and FERC approval to export LNG from Cove Point and has begun construction on a bi-directional facility, which will be able to import LNG, and vaporize it as natural gas, and liquefy natural gas and export it as LNG. See
Note 22 to the Consolidated Financial Statements for more information.
In 2014, Dominion formed Dominion Midstream, an MLP
initially consisting of a preferred equity interest in Cove Point. See General above for more information. Also see Note 3 to the Consolidated Financial Statements for a description of Dominions acquisition of CGT, which Dominion
expects to contribute to Dominion Midstream in the first half of 2015.
The Blue Racer joint venture concentrates on building
new gathering, processing, fractionation and NGL transportation assets as the development of the Utica Shale formation increases. Dominion has contributed or sold various assets to the joint venture. See Note 9 to the Consolidated Financial
Statements for more information.
Dominion Energys six-year investment plan includes spending approximately
$8.9 billion from 2015 through 2020 to upgrade existing infrastructure or add new pipelines to meet growing energy needs within its service territory and maintain reliability. This plan includes spending for the Atlantic Coast Pipeline project
and approximately $2.6 billion, exclusive of financing costs, for the Liquefaction Project.
Earnings for the Dominion Energy Operating Segment of Dominion primarily result from
rates established by FERC and the West Virginia Commission. Additionally, Dominion Energy receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain LNG storage and regasification services. Hopes gas
distribution operations in West Virginia serve residential, commercial and industrial gas sales, transportation and gathering service customers. Revenue provided by Hopes operations is based primarily on rates established by the West Virginia
Commission. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. Variability in earnings results from changes
in 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. However, the processing and fractionation operations within Dominion
Energys Blue Racer joint venture are primarily managed under long-term fee-based contracts, which minimizes commodity risk.
COMPETITION
Dominion
Energy Operating SegmentDominion and Dominion Gas
Dominion Gas natural gas transmission operations compete with domestic and
Canadian pipeline companies. Dominion Gas 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.
DTIs processing and fractionation operations face competition in obtaining natural gas supplies for its processing and related services. Numerous factors impact any given customers choice of
processing services provider, including the location of the facilities, efficiency and reliability of operations, and the pricing arrangements offered.
In Ohio, there has been no legislation enacted to require supplier choice for natural gas distribution consumers. However, East Ohio has offered an Energy Choice program to residential and commercial
customers since October 2000. East Ohio has since taken various steps approved by the Ohio Commission toward exiting the merchant function, including restructuring its commodity service and placing Energy Choice-eligible customers in a direct retail
relationship with participating suppliers. Further, in April 2013, East Ohio fully exited the merchant function for its nonresidential customers, which are now required to choose a retail supplier or be assigned to one at a monthly variable rate set
by the supplier. At December 31, 2014, approximately 1 million of East Ohios 1.2 million Ohio customers were participating in the Energy Choice program.
Dominion Energy Operating SegmentDominion
For Hope, West Virginia does not allow
customers to choose their provider in its retail natural gas markets at this time. See
Regulation-State Regulations-Gas for additional information.
Cove
Points LNG operations are not subject to significant competition due to the long-term nature of their contracts.
REGULATION
Dominion
Energy Operating SegmentDominion and Dominion Gas
Dominion Gas natural gas transmission, storage, processing and gathering
operations are regulated primarily by FERC. East Ohios gas distribution operations, including the rates that it may charge to customers, are regulated by the Ohio Commission. See State Regulations and Federal Regulations in
Regulation for more information.
Dominion Energy Operating SegmentDominion
Dominions LNG operations are regulated primarily by FERC. Hopes gas distribution operations, including the rates that it may charge customers,
are regulated by the West Virginia Commission. See State Regulations and Federal Regulations in Regulation for more information.
PROPERTIES AND INVESTMENTS
Dominion Energy
Operating SegmentDominion and Dominion Gas
East Ohios gas distribution network is located in Ohio. This network involves
approximately 18,800 miles of pipe, exclusive of service lines. 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 Gas has approximately 7,700 miles of gas transmission,
gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Gas owns gas processing and fractionation facilities in West Virginia with a total processing capacity of 270,000
mcf per day and fractionation capacity of 580,000 Gals per day. Dominion Gas also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with approximately 2,000 storage wells and approximately 399,000
acres of operated leaseholds.
The total designed capacity of the underground storage fields operated by Dominion Gas is
approximately 947 bcf. Certain storage fields are jointly-owned and operated by Dominion Gas. The capacity of those fields owned by Dominion Gas partners totals about 242 bcf.
In December 2013, DTI closed on agreements with two natural gas producers to convey approximately 100,000 acres of Marcellus Shale
development rights underneath several of its natural gas storage fields. In September 2014, DTI closed on an agreement with a natural gas producer to convey approximately 24,000 acres of Marcellus Shale development rights underneath one of its
natural gas storage fields. In November 2014, DTI closed on an agreement with a natural gas producer to convey approximately 11,000 acres of Marcellus Shale development rights underneath
one of its Pennsylvania natural gas storage fields. See Note 10 to the Consolidated Financial Statements for further information.
In July 2013, East Ohio signed long-term precedent agreements with two customers to move 320,000 Dths per day of processed gas from the
outlet of new gas processing facilities in Ohio to interconnections with multiple interstate pipelines. The first phase of the Western Access Project provides system enhancements to facilitate the movement of processed gas over East Ohios
system. The initial phase of the project was completed in the fourth quarter of 2014 and cost approximately $85 million. During the second and third quarters of 2014, East Ohio executed long-term precedent agreements with customers for 450,000 Dths
per day of service to new interconnects with interstate pipelines. This second phase of the Western Access Project will expand the number of interstate pipelines to which East Ohio will deliver processed gas to four. The project is expected to
be completed in the fourth quarter of 2015 and cost approximately $130 million.
In September 2014, DTI announced its
intent to construct and operate the Supply Header Project which is expected to cost approximately $500 million and provide 1,500,000 Dths per day of firm transportation service to various customers. In October 2014, DTI requested authorization to
use the FERCs pre-filing process. The application to request FERC authorization to construct and operate the project facilities is expected to be filed in the third quarter of 2015, with the facilities expected to be in service in the fourth
quarter of 2018. In December 2014, DTI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header Project.
In June 2014, DTI executed binding precedent agreements with two power generators for the Leidy South Project. In November 2014, one of the power generators assigned a portion of its capacity to an
affiliate, bringing the total number of project customers to three. The project is expected to cost approximately $210 million and provide 155,000 Dths per day of firm transportation service from Clinton County, Pennsylvania to Loudoun County,
Virginia. Because the project facilities would be installed at existing DTI compressor stations rather than greenfield sites, DTI will submit a standard certificate application rather than utilize the FERC pre-filing process. The application to
request FERC authorization to construct and operate the project facilities is expected to be filed in the second quarter of 2015. Service under the 20-year contracts is expected to commence in the fourth quarter of 2017.
During the second quarter of 2014, DTI executed a binding precedent agreement with a customer for the Monroe-to-Cornwell Project. The
project is expected to cost approximately $70 million and provide 205,000 Dths per day of firm transportation service from Monroe County, Ohio to an interconnect near Cornwell, West Virginia. In October 2014, DTI filed an application to request
FERC authorization to construct and operate the project facilities, which are expected to be in service in the fourth quarter of 2016.
In the first quarter of 2014, DTI executed a binding precedent agreement for the Lebanon West II Project. The project is expected to cost approximately $112 million and provide 130,000 Dths per day of
firm transportation service from Butler County, Pennsylvania to an interconnect with Texas Gas Pipeline in Lebanon, Ohio. In September 2014, DTI filed an application to request
FERC authorization to construct and operate the project facilities, which are expected to be in service in the fourth quarter of 2016.
In November 2014, DTI placed into service its $42 million Natrium-to-Market project. The project is designed to provide 185,000 Dths per
day of firm transportation from an interconnect between DTI and the Natrium facility to the Crayne interconnect. Four customers have entered into binding precedent agreements for the full project capacity under 8-year and 13-year terms.
In September 2013, DTI executed binding precedent agreements with several local distribution company customers for the New Market Project.
The project is expected to cost approximately $159 million and provide 112,000 Dths per day of firm transportation service from Leidy, Pennsylvania to interconnects with Iroquois and Niagara Mohawk Power Corporations distribution system in the
Albany, New York market. In June 2014, DTI filed an application to request FERC authorization to construct and operate the project facilities, which are expected to be in service in the fourth quarter of 2016.
In October 2013, DTI executed a binding precedent agreement with CNX Gas Company LLC for the Clarington Project. The project is expected
to cost approximately $78 million and provide 250,000 Dths per day of firm transportation service from central West Virginia to Clarington, Ohio. In June 2014, DTI filed an application to request FERC authorization to construct and operate the
project facilities, which are expected to be in service in the fourth quarter of 2016.
In November 2014, DTI placed into
service its $112 million Allegheny Storage Project, which provides approximately 7.5 bcf of incremental storage service and 125,000 Dths per day of associated year-round firm transportation service to three local distribution companies under 15-year
contracts.
In 2008, East Ohio began PIR, aimed at replacing approximately 4,100 miles of its pipeline system at a cost of $2.7
billion. In 2011, approval was obtained to include an additional 1,450 miles and to increase annual capital investment to meet the program goal. The program will replace approximately 25% of the pipeline system and is anticipated to take place over
a total of 25 years.
Dominion Energy Operating SegmentDominion
In addition to the assets held by Dominion Gas detailed above, see Item 1. Business, General for further information regarding pipeline and storage capacity owned by Dominion. Dominion also has
about 15 bcf of above-ground storage capacity at Cove Point. Dominion has 142 compressor stations with approximately 869,000 installed compressor horsepower.
Cove PointDominion is pursuing the Liquefaction Project, which would enable Cove Point to liquefy domestically-produced natural gas for export as LNG. The DOE previously authorized Dominion
to export LNG to countries with free trade agreements. In September 2013, the DOE authorized Dominion to export LNG from Cove Point to non-free trade agreement countries.
In May 2014, the FERC staff issued its EA for the Liquefaction Project. In the EA, the FERC staff addressed a variety of topics related to the proposed construction and development of the Liquefaction
Project and its potential impact to the environment, and determined that with the implementation of appropriate mitigation measures, the Liquefaction Project can be built
and operated safely with no significant impact to the environment. In September 2014, Cove Point received the FERC order authorizing the Liquefaction Project with certain conditions. The
conditions regarding the Liquefaction Project set forth in the FERC order largely incorporate the mitigation measures proposed in the EA. In October 2014, Cove Point commenced construction of the Liquefaction Project, with an in-service date
anticipated in late 2017. The Cove Point facility is authorized to export at a rate of 770 million cubic feet of natural gas per day for a period of 20 years.
In April 2013, Dominion announced it had fully subscribed the capacity of the project with 20-year terminal service agreements. ST Cove Point, LLC, a joint venture of Sumitomo Corporation, a Japanese
corporation that is one of the worlds leading trading companies, and Tokyo Gas Co., Ltd., a Japanese corporation that is the largest natural gas utility in Japan, and GAIL Global (USA) LNG LLC, a wholly-owned indirect U.S. subsidiary of GAIL
(India) Ltd., have each contracted for half of the capacity. Following completion of the front-end engineering and design work, Dominion also announced it had awarded its EPC contract for new liquefaction facilities to IHI/Kiewit Cove Point, a joint
venture between IHI E&C International Corporation and Kiewit Energy Company.
Cove Point has historically operated as an
LNG import facility under various long-term import contracts. Since 2010, Dominion has renegotiated certain existing LNG import contracts in a manner that will result in a significant reduction in pipeline and storage capacity utilization and
associated anticipated revenues during the period from 2017 through 2028. Such amendments created the opportunity for Dominion to explore the Liquefaction Project, which, assuming it becomes operational, will extend the economic life of Cove
Point and contribute to Dominions overall growth plan. In total, these renegotiations reduced Cove Points expected annual revenues from the import-related contracts by approximately $150 million from 2017 through 2028, partially offset
by approximately $50 million of additional revenues in the years 2013 through 2017.
In December 2014, Cove Point filed an
application to request FERC authorization to construct and operate facilities that will provide firm transportation service for a new power generating facility located in Maryland. The $31 million St. Charles Transportation Project will provide
132,000 Dths per day of firm transportation service from Cove Points interconnect with Transcontinental Gas Pipe Line in Fairfax County, Virginia to CPV Maryland, LLCs facility in Charles County, Maryland. Service under a 20-year
contract is expected to commence in June 2016.
In December 2014, Cove Point filed an application to request FERC authorization
to construct and operate facilities that will provide firm transportation service for a new power generating facility located in Maryland. The $37 million Keys Energy Project will provide 107,000 Dths per day of firm transportation service from Cove
Points interconnect with Transcontinental Gas Pipe Line in Fairfax County, Virginia to Keys Energy Center, LLCs facility in Prince Georges County, Maryland. Service under a 20-year contract is expected to commence in March 2017.
See Item 2. Properties for more information about the Cove Point facility.
Dominion Energy Equity Method InvestmentsIn September 2014, Dominion, along
with Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc., announced the formation of Atlantic Coast Pipeline. The members, which are subsidiaries of the above-referenced parent companies, hold the following membership
interests: Dominion, 45%; Duke Energy Corporation, 40%; Piedmont Natural Gas Company, Inc., 10%; and AGL Resources Inc., 5%. Atlantic Coast Pipeline is focused on constructing an approximately 550-mile natural gas pipeline running from West Virginia
through Virginia to North Carolina, which has a total expected cost of $4.5 billion to $5.0 billion, excluding financing costs. In October 2014, Atlantic Coast Pipeline requested approval from FERC to utilize the pre-filing process under which
environmental review for the natural gas pipeline project will commence. It expects to file its FERC application in the third quarter of 2015, receive the FERC certificate in the summer of 2016, and begin construction shortly thereafter. The project
is subject to FERC, state and other federal approvals. See Note 9 to the Consolidated Financial Statements for further information about Dominions equity method investment in Atlantic Coast Pipeline.
In December 2012, Dominion formed Blue Racer with Caiman to provide midstream services to natural gas producers operating in the Utica
Shale region in Ohio and portions of Pennsylvania. Blue Racer is an equal partnership between Dominion and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital. Midstream services offered by Blue Racer
include gathering, processing, fractionation, and natural gas liquids transportation and marketing. Blue Racer is expected to leverage Dominions existing presence in the Utica region with significant additional new capacity designed to meet
producer needs as the development of the Utica Shale formation increases. See Note 9 to the Consolidated Financial Statements for further information about Dominions equity method investment in Blue Racer.
SOURCES OF ENERGY SUPPLY
Dominion Energy Operating SegmentDominion and Dominion Gas
Dominions and
Dominion Gas 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
and Dominion Gas large underground natural gas storage network and the location of their pipeline systems are a significant link between the countrys major interstate gas pipelines and large markets in the Northeast and mid-Atlantic
regions. Dominions and Dominion Gas 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 and Dominion Gas underground storage facilities play an important part in balancing gas
supply with consumer demand and are essential to serving the Northeast, mid-Atlantic and Midwest regions. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transmission capacity.
SEASONALITY
Dominion Energy Operating SegmentDominion and Dominion Gas
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. Earnings are also impacted by changes in commodity prices driven by seasonal weather changes, the effects of unusual weather events on operations and the economy.
Corporate and Other
Corporate and
Other SegmentVirginia Power and Dominion Gas
Virginia Powers and Dominion Gas Corporate and Other segments primarily
include certain specific items attributable to their 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 discontinued, which is discussed in Note 3 and Note 25 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
The Companies 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 four major elements:
|
|
Compliance with applicable environmental laws, regulations and rules; |
|
|
Conservation and load management; |
|
|
Renewable generation development; and |
|
|
Improvements in other energy infrastructure, including natural gas operations. |
This strategy incorporates the Companies efforts to voluntarily reduce GHG emissions, which are described below. See Dominion
Generation-Properties and Dominion Energy-Properties for more information on certain of the projects described below. 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
The Companies remain committed to compliance with applicable environmental laws, regulations and rules related to their operations. As part of their commitment to compliance with such laws, Dominion and
Virginia Power have sold or closed a number of coal-fired generation units over the past several years, and have plans to close additional units in the future. Additional information related to these and other of the Companies environmental
compliance matters can be found in Item 1. Operating Segments and Future Issues and Other Matters in Item 7. MD&A and in Notes 3, 6 and 22 to the Consolidated Financial Statements.
Conservation and Load Management
Conservation and
load management play 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 10% of the electric energy consumed in 2006 through the implementation of conservation programs. Additional legislation in 2009 added definitions of peak-shaving and energy efficiency programs, and allowed for a margin on operating expenses
and recovery of revenue reductions related to energy efficiency programs.
Virginia Powers DSM programs, implemented with
Virginia Commission approval, provide important incremental steps toward achieving the voluntary 10% energy conservation goal through activities such as energy audits and incentives for customers to upgrade or install certain energy efficient
measures and/or systems. The DSM programs began in Virginia in 2010 and in North Carolina in 2011. Currently, there are 22 total DSM programs active in the two states. Virginia Power continues to evaluate opportunities to redesign current DSM
programs and develop new DSM initiatives in Virginia and North Carolina.
In Ohio, East Ohio offers three DSM programs,
approved by the Ohio Commission, designed to help customers reduce their energy consumption.
Virginia Power continues to
upgrade meters to AMI, also referred to as smart meters, in portions of Virginia. The AMI meter upgrades are part of an ongoing project that will help Virginia Power further evaluate 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.
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.
See Item 1. Business, Operating Segments and Item 2.
Properties for additional information, including Dominions merchant solar properties.
Improvements in Other Energy Infrastructure
Virginia Powers six-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, maintain reliability, and to address environmental requirements. 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. See Properties in Item 1., Operating Segments, DVP for additional information.
Dominion and Dominion Gas, in connection with their six-year investment plan, are also pursuing the construction or upgrade of regulated infrastructure in their natural gas businesses. See Properties
and Investments in Item 1., Operating Segments, Dominion Energy for additional information, including natural gas infrastructure projects.
The Companies Strategy for Voluntarily Reducing GHG Emissions
The Companies have not established a standalone GHG emissions reduction target or timetable, but they are actively engaged in voluntary reduction efforts. The Companies have an integrated voluntary
strategy for reducing GHG emission intensity with diversification as its cornerstone. The six principal components of the strategy include initiatives that address electric energy management, electric energy production, electric energy delivery and
natural gas storage, transmission and delivery, as follows:
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Enhance conservation and energy efficiency programs to help customers use energy wisely and reduce environmental impacts; |
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Expand the Companies renewable energy portfolio, principally wind power, solar, fuel cells and biomass, to help diversify the Companies
fleet, meet state renewable energy targets and lower the carbon footprint; |
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Build other new generating capacity, including low-emissions natural-gas fired and emissions-free nuclear units to meet customers future
electricity needs; |
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Construct new electric transmission infrastructure to modernize the grid, promote economic security and help deliver more green energy to population
centers where it is needed most; |
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Construct new natural gas infrastructure to expand availability of this cleaner fuel, to reduce emissions, and to promote energy and economic security
both in the U.S. and abroad; and |
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Implement and enhance voluntary methane mitigation measures through the EPAs Natural Gas Star Program. |
Since 2000, Dominion and Virginia Power have tracked the emissions of their electric generation fleet, which employs
a mix of fuel and renewable energy sources. Comparing annual year 2000 to annual year 2013, the entire electric generating fleet (based on ownership percentage) reduced its average CO2 emissions rate per MWh of energy produced from electric generation by about 39%. Comparing annual year 2000 to annual year
2013, the regulated electric generating fleet (based on ownership percentage) reduced its average CO2 emissions rate per MWh of energy produced from electric generation by about 19%. Dominion and Virginia Power do not yet have final 2014 emissions data.
Dominion also developed a comprehensive GHG inventory for calendar
year 2013. For Dominion Generation, Dominions and Virginia Powers direct CO2 equivalent emissions, based on equity share (ownership), were approximately 33.9 million metric tons and 30.2 million metric tons, respectively, in 2013, compared to 36.2 million metric tons
and 24.4 million metric tons, respectively, in 2012. The overall decrease in emissions from the Dominion fleet from 2012 to 2013 is largely due to Dominions divestiture of three power stations (Brayton Point in Massachusetts, and Elwood and
Kincaid in Illinois), whereas the increase in emissions for the Virginia Power fleet was due to an increase in power generation after mild weather in 2012, which includes increased usage of coal, natural gas and oil. For the DVP operating
segments electric transmission and distribution operations, direct CO2 equivalent emissions for 2013 were 46,446 metric tons, representing a slight decrease from 2012. For 2013, DTIs (including Cove Point) direct CO2 equivalent emissions were approximately 1.0 million metric tons,
and Hopes and East Ohios direct CO2 equivalent
emissions were approximately 1.0 million metric tons, both similar to 2012. Dominions GHG inventory follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98 for calculating emissions.
Alternative Energy Initiatives
AES 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. AES has also conducted a number of studies
to evaluate potential transmission solutions for delivering offshore wind resources to its customers. In addition, AES has developed EDGE®, a conservation voltage management solution enabling utilities to deploy incremental grid-side energy management, and that requires no behavioral changes or purchases
by end customers.
REGULATION
The Companies are subject to regulation by various federal,
state and local authorities, including the Virginia Commission, North Carolina Commission, Ohio Commission, West Virginia Commission, SEC, FERC, EPA, DOE, NRC, Army Corps of Engineers, and the Department of Transportation.
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 CPCNs 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
Under the Regulation Act enacted in 2007, Virginia Powers base rates are set by a process that allows the recovery of operating costs and an ROIC. The Virginia Commission reviews and has the ability
to adjust 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. 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 determination by the Virginia Commission that Virginia Power has exceeded its authorized level of earnings 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.
In February 2015, the Virginia Governor signed legislation into law
which will keep Virginia Powers base rates unchanged until at least December 1, 2022. The legislation limits the 2015 biennial review to solely a determination of Virginia Powers actual earned ROE during the combined 2013-2014 test
period and whether any refunds are due to customers. In addition, no biennial reviews will be conducted by the Virginia Commission for the five successive 12-month test periods beginning January 1, 2015, and ending December 31, 2019. During this
suspension period, Virginia Power bears the risk of any severe weather events and natural disasters, as well as the risk of asset impairments related to the early retirement of any generation facilities due to the implementation of the Clean Power
Plan regulations, and Virginia Power may not recover its associated costs through increases to base rates. The legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utilitys ROE for use in
connection with rate adjustment clauses.
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; and it provides for enhanced returns on capital expenditures on specific new
generation projects. The Regulation Act also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.
Legislation enacted in February 2013 amended the Regulation Act prospectively, including elimination of the 50 basis points RPS ROE incentive. In addition, ROE incentives for newly proposed generation
projects were eliminated, except for nuclear and offshore wind projects, which were reduced from the previous 200 basis points ROE incentive to 100 basis points. In addition, through the 2013 amendments, the Virginia Commission has the discretion to
increase or decrease a utilitys authorized ROE based on the utilitys performance consistent with Virginia Commission precedent that existed prior to 2007. The legislation included 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 previous 60% level beginning with the biennial review for 2013-2014 to be filed in 2015.
If the Virginia Commissions future rate decisions, including actions relating to Virginia Powers rate adjustment clause
filings, differ materially from Virginia Powers expectations, such decisions may adversely affect Virginia Powers results of operations, financial condition and cash flows.
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. 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 were appealed to
the North Carolina Supreme Court by multiple parties. In June 2014, the North Carolina Supreme Court issued an opinion reversing the portion of the North Carolina Commissions December 2012 order from Virginia Powers 2012 base rate case
approving a 10.2% ROE for Virginia Power, and remanding the case to the North Carolina Commission for additional findings of fact in light of a 2013 opinion issued after the North Carolina Commissions order. This case is pending.
GAS
East Ohios
natural gas distribution services, including the rates it may charge its customers, are regulated by the Ohio Commission. Hopes natural gas distribution services are regulated by the West Virginia Commission.
Gas Regulation in Ohio
East Ohio is subject to
regulation of rates and other aspects of its business by the Ohio Commission. When necessary, East Ohio
seeks 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 which included an authorized return on equity of 10.38%.
In addition to general base rate increases, East Ohio
makes routine filings with the Ohio Commission to reflect changes in the costs of gas purchased for operational balancing on its system. 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 rider filings cover unrecovered gas costs plus prospective annual demand costs. Increases or decreases in gas cost
rider 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.
Gas Regulation in
West Virginia
Dominions gas distribution subsidiary is subject to regulation of rates and other aspects of its business by the West
Virginia Commission. When necessary, Hope seeks 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. 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, Hope makes routine separate filings with the West Virginia Commission 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 a prospective twelve-month period. 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.
Status of Competitive Retail Gas Services
Both of
the states in which Dominion and Dominion Gas have 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
pro-
gram. 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 requires those customers to choose
a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2014, approximately 1.0 million of Dominion Gas 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 allowing 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.
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 has evaluated its transmission facilities for any
discrepancies between design and actual field conditions and has taken necessary corrective actions. In addition, NERC has redefined critical assets which expanded the number of assets subject to NERC reliability standards, 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 DTI, Iroquois,
and certain services performed by Cove Point. The design, construction and operation of the Cove Point LNG facility, including associated natural gas pipelines, the Liquefaction Project and the import and export of LNG are also regulated by the
FERC.
Dominion Gas interstate gas transmission and storage activities are conducted on an open access basis, in
accordance with certificates, tariffs and service agreements on file with FERC and FERC regulations.
Dominion Gas operates in compliance with FERC standards of conduct, which prohibit the
sharing of certain non-public transmission information or customer specific data by its interstate gas transmission and storage companies with non-transmission function employees. Pursuant to these standards of conduct, Dominion Gas also makes
certain informational postings available on Dominions website.
See Note 13 to the Consolidated Financial Statements for
additional information.
Safety Regulations
Dominion Gas 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 Gas 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.
The Companies are subject to a number of federal
and state laws and regulations, including OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. The Companies have an internal safety, health and security program designed to monitor and enforce
compliance with worker safety requirements, which is routinely reviewed and considered for improvement. The Companies believe that they are in material compliance with all applicable laws and regulations related to worker health and safety.
Notwithstanding these preventive measures, incidents may occur that are outside of the Companies control.
Environmental Regulations
Each of the Companies 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 businesses) or market prices (in unregulated businesses), those costs could adversely affect future results of operations and cash flows. The Companies 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, which information is incorporated herein by reference.
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 and regulatory action in this area. The Companies 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 Note 22 to the Consolidated Financial Statements 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 Dominion and Virginia Power are required by the NRC to be financially prepared. For information on decommissioning trusts, see Dominion Generation-Nuclear Decommissioning above 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, the Companies 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.
See Item 1A. Risk Factors for additional information.
Item 1A. Risk Factors
The Companies 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.
The Companies results of operations can
be affected by changes in the weather. Fluctuations in weather can affect demand for the Companies services. For example, milder than normal weather can reduce demand for electricity and gas transmission and distribution services. In
addition, severe weather, including hurricanes, winter storms, earthquakes, floods and other natural disasters can disrupt operation of the Companies facilities and cause service outages, production delays 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 and Dominion Gas 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 and Dominion Gas 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 and
Dominion Gas gas transmission businesses are subject to review by FERC. Pursuant to FERCs February 2014 approval of DTIs uncontested settlement offer, DTIs base rates for storage and transportation services are subject to a
moratorium through the end of 2016. In addition, the rates of Dominions and Dominion Gas gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate. A failure by us to support these
rates could result in rate decreases from current rate levels, which could adversely affect our results of operations, cash flows and financial condition.
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.
Legislation signed by the Virginia Governor in February 2015 suspends biennial reviews for the five successive 12-month test periods
beginning January 1, 2015 and ending December 31, 2019, and no changes will be made to Virginia Powers existing base rates until at least December 1, 2022. During this period, Virginia Power bears the risk of any severe weather events and
natural disasters, as well as the risk of asset impairments related to the early retirement of any generation facilities due to the implementation of the Clean Power Plan regulations, and Virginia Power may not recover its associated costs through
increases to base rates. If Virginia Power incurs any such significant unusual expenses during this period, Virginia Power may not be able to recover its costs and/or earn a reasonable return on capital investment, which could negatively affect
Virginia Powers future earnings.
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.
The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of
operations and subject the Companies to monetary penalties. The Companies operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies.
Such laws and regulations govern the terms and conditions of the services we offer, our relationships with affiliates, protection of our critical electric infrastructure assets and pipeline safety, among other matters. 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 any of the Companies 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, changes in enforcement practices of regulators, or penalties
imposed for non-compliance with existing laws or regulations may result in substantial additional 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 or its interpretation of market rules, 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. In addition, there have been changes to the interpretation and
application of FERCs market manipulation rules. A failure to comply with these rules could lead to civil and criminal penalties.
The Companies infrastructure build and expansion plans often require regulatory approval before construction can commence. The Companies may not complete facility construction, pipeline,
conversion or other infrastructure 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 facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects have been announced and additional projects may be considered in the future. Dominion Gas competes for
projects with companies of varying size and financial capabilities, including some that may have advantages competing for natural gas and liquid gas supplies. Commencing construction on announced and future projects may require 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 counterparties or vendors, or other factors beyond the Companies control. Even if facility construction, pipeline, expansion, electric transmission line,
conversion and other infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of the Companies following completion of the projects may not meet expectations. Start-up
and operational issues can arise in connection with the commencement of commercial operations at our facilities, including but not limited to commencement of commercial operations at our power generation facilities following expansions and fuel type
conversions to natural gas and biomass. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, the Companies 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 facility construction, pipeline, electric transmission line, expansion, conversion and other infrastructure projects.
The development and construction of several large-scale infrastructure projects simultaneously involves significant execution risk. The Companies are currently simultaneously developing or
constructing several major projects, including the Liquefaction Project, the Atlantic Coast Pipeline project, the strategic undergrounding project, Brunswick County, and multiple DTI producer outlet projects, which together help contribute to the
over $16 billion in capital expenditures planned by the Companies through 2017. Several of the Companies key projects are increasingly large-scale, complex and being constructed in constrained geographic areas (for example, the Liquefaction
Project) or in difficult terrain (for example, the Atlantic Coast Pipeline project). The advancement of the Companies ventures is also affected by the activities of stakeholder and advocacy groups, some of which oppose natural gas-related and
energy infrastructure projects. Given that these projects provide the foundation for the Companies strategic growth plan, if the Companies are unable to obtain the required approvals, develop the necessary technical expertise, allocate and
coordinate sufficient resources, adhere to budgets and timelines, effectively handle public outreach efforts, or otherwise fail to successfully execute the projects, there could be an adverse impact to the Companies financial position, results
of operations and cash flows. Further, an inability to obtain financing or otherwise provide liquidity for the projects on acceptable terms could negatively affect the Companies financial condition, cash flows, the projects anticipated
financial results and/or impair the Companies ability to execute the business plan for the projects as scheduled.
Given
their significant anticipated capital expenditures and unique attributes, the Liquefaction Project and the Atlantic Coast Pipeline project in particular are subject to significant execution risk.
Cove Point Liquefaction ProjectThe Liquefaction Project, which is expected to cost approximately $2.6 billion to complete, exclusive of
financing costs, involves regulatory, construction, customer and other risks. Dominion has received the required approvals to commence construction of the Liquefaction Project from the DOE, FERC and the Maryland Commission, which are subject to
compliance with the applicable permit conditions. However, all DOE export licenses are subject to review and possible withdrawal should the DOE conclude that such export authorization is no longer in the public interest. The issuance of the FERC and
Maryland approval orders has been appealed by third parties. Dominion does not know whether any existing or potential interventions or other actions by third parties will interfere with its ability to maintain such approvals, but loss of any
material approval could have a material adverse effect on the construction or operation of the facility. In addition, the Liquefaction Project has been the subject of litigation in the past and could be the subject of litigation in the future.
Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect Dominions ability to execute its business plan.
Dominion is dependent on its contractors for the successful and timely completion of the
Liquefaction Project. There is limited recent industry experience in the U.S. regarding the construction or operation of large liquefaction projects. The construction is expected to take several years, will be confined within a limited geographic
area and could be subject to delays, cost overruns, labor disputes and other factors that could cause the total cost of the project to exceed the anticipated amount and adversely affect Dominions financial performance and/or impair
Dominions ability to execute the business plan for the project as scheduled.
The terminal service agreements are subject
to certain conditions precedent, including maintenance of certain regulatory approvals. Because the project will have only two customers, the financial performance of the project is highly dependent on those two counterparties, whose ability to
perform their obligations under the contracts is subject to factors outside Dominions control. Dominion will also be exposed to counterparty credit risk. While the counterparties obligations are supported by parental guarantees and
letters of credit, there is no assurance that such credit support would be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under either agreement resulting in a judgment in
Dominions favor, Dominion may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process.
Atlantic Coast Pipeline ProjectThe Atlantic Coast Pipeline project, which will be constructed by DTI, is expected to have a total cost of approximately $4.5 to $5 billion, excluding financing
costs, and will involve significant permitting and construction risks. The project requires the approval of FERC and other federal and state agencies, which could be delayed or withheld. Dominion expects opposition from certain landowners and
stakeholder groups, which could impede the acquisition of rights-of-way and other land rights on a timely basis or on acceptable terms.
The large diameter of the pipeline and difficult terrain of certain portions of the proposed pipeline route aggravate the typical construction risks with which DTI is familiar. In-service delays could
lead to cost overruns and potential customer termination rights.
Dominion owns a 45% membership interest in Atlantic Coast
Pipeline. Dominions lack of a controlling interest means that it has limited influence over this business. If another member were unable or otherwise failed to perform its obligations to provide capital and credit support for this business, it
could have an adverse effect on Dominions financial results.
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 the Companies 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 requir-
ing efficiency improvements from fossil fuel-fired electric generating units.
Compliance with GHG emission reduction requirements may require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon controls and/or reduction
programs, 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 Clean Power Plan uses a set of measures for reducing
emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units, expanding renewable resources and increasing customer energy
efficiency. Compliance with the Clean Power Plans anticipated implementing regulations may require Virginia Power to prematurely retire certain generating facilities, with the potential lack or delay of cost recovery and substantially higher
electric rates, which could affect consumer demand. 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 controls and/or reduction programs, and the selected compliance alternatives. Dominion and
Virginia Power 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 Dominions and Virginia Powers 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.
There are also potential impacts on Dominions and Dominion Gas 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. Several regions of the U.S. have moved forward with GHG emission regulations including regions where Dominion has
operations. For example, Rhode Island has implemented regulations requiring reductions in CO2 emissions through RGGI, a cap and trade program covering CO2 emissions from power plants in the Northeast. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products.
The Companies operations are subject to a number of environmental laws and regulations which impose significant compliance costs
to the Companies. The Companies 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 environmental 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 the Companies expect that they will remain significant in the
future. Certain facilities have become uneconomical to operate and have been shut down, converted to new fuel types or sold. These types of events could occur again in the future.
Existing environmental laws and regulations may be revised and/or new laws may be adopted or become applicable to the Companies. Risks
relating to expected regulation of GHG emissions from existing fossil fuel-fired electric generating units are discussed below. In addition, further regulation of air quality and GHG emissions under the CAA may be imposed on the natural gas sector,
including rules to limit methane leakage. The Companies are also subject to recently finalized federal water and waste regulations, including regulations concerning cooling water intake structures, coal combustion by-product handling and disposal
practices, and the potential further regulation of polychlorinated biphenyls.
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 the Companies results of operations, financial performance or liquidity.
Virginia Power is subject to risks associated with the disposal and storage of coal ash. Virginia Power historically produced and continues to produce coal ash as a by-product of its coal-fired
generation operations. The ash is stored and managed in impoundments (ash ponds) and landfills located at eight different facilities.
Virginia Power may face litigation regarding alleged CWA violations at Possum Point and Chesapeake and could incur settlement expenses and other costs, depending on the outcome of any such litigation,
including costs associated with closing, corrective action and ongoing monitoring of certain ash ponds. In addition, the federal government recently signed final regulations concerning the management and storage of CCRs and Virginia and West
Virginia may impose additional regulations which would apply to the facilities identified above. Such regulations could require Virginia Power to make additional capital expenditures, increase its operating and maintenance expenses or even cause it
to close certain facilities.
Further, while Virginia Power operates its ash ponds and landfills in compliance with applicable
state safety regulations, a release of coal ash with a significant environmental impact, such as the Dan River ash basin release by a neighboring utility, could result in remediation costs, civil and/or criminal penalties, claims, litigation,
increased regulation and compliance costs, and reputational damage, and could impact the financial condition of Virginia Power.
The Companies operations are subject to operational hazards, equipment failures, supply chain disruptions and personnel issues
which could negatively affect the Companies. 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, pipeline integrity
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. The Companies businesses are dependent upon sophisticated information technology systems and network infrastructure, the failure of which could
prevent them from accomplishing critical business functions. Because the Companies transmission facilities, pipelines and other facilities are interconnected with those of third parties, the operation of their facilities and pipelines 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.
In addition, there are many risks associated with the Companies operations and the transportation, storage and processing of natural gas and NGLs, including nuclear accidents, fires, explosions,
uncontrolled release of natural gas and other environmental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life
or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities,
heightened regulatory scrutiny and reputational risk. Further, the location of pipelines and storage facilities, or generation, transmission, substations and distribution facilities near populated areas, including residential areas, commercial
business centers and industrial sites, could increase the level of damages resulting from these risks.
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 and Dominion Gas depend on third parties to produce the natural gas they gather and process, and to provide NGLs they separate
into marketable products. A reduction in these quantities could reduce Dominions and Dominion Gas revenues. Dominion and Dominion Gas obtain their supply of natural gas and NGLs from numerous third-party producers. Most
producers are under no obligation to deliver a specific quantity of natural gas or NGLs to Dominions and Dominion Gas facilities. A number of factors could reduce the volumes of natural gas and NGLs available to Dominions and
Dominion Gas pipelines and other assets. Increased regulation of energy extraction activities or a decrease in natural gas prices or the availability of drilling equipment could result in reductions in drilling for new natural gas wells, which
could decrease the volumes of natural gas supplied to Dominion and Dominion Gas. Producers could shift their production activities to regions outside Dominions and Dominion Gas footprint. In addition, the extent of natural gas reserves
and the rate of production from such reserves may be less than anticipated. If producers were to decrease the supply of natural gas or NGLs to Dominions and Dominion Gas systems and facilities for any reason, Dominion and Dominion Gas
could experience lower revenues to the extent they are unable to replace the lost volumes on similar terms.
Dominions
merchant power business operates 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.
In addition, in the event that any of the merchant generation
facilities experience a forced outage, Dominion may not receive the level of revenue it anticipated.
The Companies
financial results can be adversely affected by various factors driving demand for electricity and gas and related services. Technological advances required by federal laws mandate new levels of energy efficiency in end-use devices, including
lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy
consumption by a fixed date. Further, Virginia Powers business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility generation. However, advances in distributed
generation technologies, such as solar cells, gas microturbines and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use our services.
Reduced energy demand or significantly slowed growth in demand due to customer adoption of energy efficient technology, conservation,
distributed generation or regional economic conditions, unless substantially offset through regulatory cost allocations, could adversely impact the value of the Companies business activities.
Dominion Gas has experienced a decline in demand for certain of its processing services due to competing facilities operating in nearby
areas.
Dominion Gas may not be able to maintain, renew or replace its existing portfolio of customer contracts
successfully, or on favorable terms. Upon contract expiration, customers may not elect to re-contract with Dominion Gas as a result of a variety of factors, including the amount of competition in the industry, changes in the price of natural
gas, their level of satisfaction with Dominion Gas services, the extent to which Dominion Gas is able to successfully execute its business plans and the effect of the regulatory framework on customer demand. The failure to replace any such
customer contracts on similar terms could result in a loss of revenue for Dominion Gas.
Exposure to counterparty
performance may adversely affect the Companies financial results of operations. The Companies 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. Defaults by customers, suppliers, joint venture partners or other third parties may adversely affect the Companies
financial results.
In addition, in an economic downturn, individual customers of East Ohio may have increased amounts of bad
debt. While rate riders have been obtained so that those losses will, for the most part, be recovered by future rates, such recovery will be over a period of time, while the cost is incurred earlier by East Ohio.
Market performance and other changes may decrease the value of Dominions decommissioning trust funds and Dominions and
Dominion Gas benefit plan assets or increase Dominions and Dominion Gas 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 Dominions and Dominion Gas pension and other postretirement benefit plans. Dominion and Dominion Gas have 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 and Dominion Gas pension and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates will affect the liabilities under
Dominions and Dominion Gas 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 mortality 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 and Dominion Gas 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. The Companies use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity and financial market risks. In addition, Dominion and Dominion Gas purchase and sell
commodity-based contracts for hedging purposes.
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, including rules regarding margin requirements for non-cleared swaps. If, as a result of the rulemaking process, the Companies 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 swaps provisions of the Dodd-Frank Act by the Companies
counterparties could result in increased costs related to the Companies derivative activities.
Changing rating agency
requirements could negatively affect the Companies 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, the
Companies 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 the Companies credit ratings could result in an increase in borrowing costs, loss of
access to certain markets, or both, thus adversely affecting operating results and could require the Companies to post additional collateral in connection with some of its price risk management activities.
Dominion Gas depends, in part, on an intercompany credit agreement with Dominion and certain bank syndicated credit facilities
available to Dominion and Dominion Gas for short-term borrowings to meet working capital needs. If Dominions short-term funding resources, which include the commercial paper market and its syndicated bank credit facilities, become
unavailable to Dominion, Dominion Gas access to short-term funding could also be in jeopardy. Dominion Gas relies, in part, on an IRCA with Dominion to provide Dominion Gas, and its subsidiaries, with short-term borrowings to meet working
capital and other cash needs. Dominion relies, in part, on the issuance of commercial paper in the short-term money markets to fund advances it makes to Dominion Gas under the IRCA. The issuance of commercial paper by Dominion is supported by its
access to two bank syndicated revolving credit facilities. In addition, these facilities could be drawn upon either by Dominion Gas directly or by Dominion to fund Dominion Gas borrowing requests under the IRCA.
In the event of a default under the bank syndicated credit facilities by any of the Companies, Dominion could lose access to these
facilities. In such an event, Dominion may not be able to rely on either the commercial paper market or the bank facility for its own short-term funding, and thus may not be able to fund a request by Dominion Gas under the IRCA.
An inability to access financial markets could adversely affect the execution of the Companies business plans. The
Companies rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for business plans with increasing capital expenditure needs, 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 the Companies
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 the Companies financial results. The Companies 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 disasters and other significant events could adversely affect the Companies operations. The Companies 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. For example, a physical attack on a critical substation in California resulted in serious impacts to the power grid. 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 the Companies operations, lead to the disclosure of confidential information,
damage the reputation of the Companies and otherwise have an adverse effect on the Companies 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. There appears to be an increasing level of activity, sophistication and maturity of threat actors, in particular nation state
actors, that wish to disrupt the U.S. bulk power system and the U.S. gas transmission or distribution system. Such parties could view the Companies computer systems, software or networks as attractive targets for cyber attack. For example,
malware has been designed to target software that runs the nations critical infrastructure such as power transmission grids and gas pipelines. In addition, the Companies businesses require that they and their vendors 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 cyber 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 the Companies operations. The Companies business strategy is dependent on their ability to recruit, retain and motivate employees. The Companies key executive officers are the CEO, CFO and presidents and those
responsible for financial, operational, legal, regulatory and accounting functions. Competition for skilled management employees in these areas of the Companies business operations is high. In addition, demand for skilled professional and
technical employees in gas transmission, storage, gathering, processing and distribution and in design and construction is high in light of growth in demand for natural gas, increased supply of natural gas as a result of developments in gas
production, increased infrastructure projects, increased risk in certain areas of the business, such as cybersecurity, and increased regulation of these activities. The Companies inability to retain and attract these employees could adversely
affect their business and future operating results. An aging workforce in the energy industry also necessitates recruiting, retaining and developing the next generation of leadership.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
As of December 31, 2014, 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 and Dominion Gas share Dominions 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, 2014; however, by leaving the indenture open, Virginia Power expects to retain the flexibility to issue mortgage bonds in the
future. Certain of Dominions merchant generation facilities are also subject to liens.
DOMINION ENERGY
Dominion Energys Cove Point LNG facility has an operational peak regasification daily send-out capacity of approximately 1.8 bcf and
an aggregate LNG storage capacity of approximately 14.6 bcf. In addition, Cove Point has a liquefier that has the potential to create approximately 0.01 bcf of LNG per day.
The Cove Point Pipeline is a 36-inch diameter underground, interstate natural gas pipeline that extends approximately 88 miles from Cove Point to interconnections with Transcontinental Gas Pipe Line
Company, LLC in Fairfax County, Virginia, and with Columbia Gas Transmission LLC and DTI in Loudoun County, Virginia. In 2009, the original pipeline was expanded to include a 36-inch diameter expansion that extends approximately 48 miles, roughly
75% of which is parallel to the original pipeline.
Dominion Gas also owns NGL processing plants capable of processing over
270,000 mcf per day of natural gas. Hastings is the largest plant and is capable of processing over 180,000 mcf per day of natural gas. Hastings can also fractionate over 580,000 Gals per day of NGLs into marketable products, including propane,
isobutane, butane, and natural gasoline. NGL operations have storage capacity of 1,226,500 Gals of propane, 109,000 Gals of isobutane, 442,000 Gals of butane, 2,000,000 Gals of natural gasoline, and 1,012,500 Gals of mixed NGLs.
See Item 1. Business, General and Item 1. Dominion Energy, Properties and Investments for details regarding Dominion
Energys pipeline and storage capacity.
DVP
See Item 1. Business, General
for details regarding DVPs principal properties, which primarily include transmission and distribution lines.
DOMINION GENERATION
Dominion and Virginia Power generate electricity for sale on a wholesale and a retail level. Dominion and Virginia Power supply electricity demand either from their generation facilities or through
purchased power contracts. As of December 31, 2014, Dominion Generations total utility and merchant generating capacity was approximately 24,600 MW.
The following tables list Dominion Generations utility and merchant generating units and capability, as of
December 31, 2014:
VIRGINIA POWER UTILITY GENERATION
|
|
|
|
|
|
|
|
|
|
|
Plant |
|
Location |
|
Net Summer
Capability (MW) |
|
|
Percentage
Net Summer
Capability |
|
Gas |
|
|
|
|
|
|
|
|
|
|
Warren County (CC) |
|
Warren County, VA |
|
|
1,342 |
|
|
|
|
|
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 |
|
|
|
|
|
Bremo(1) |
|
Bremo Bluff, VA |
|
|
227 |
|
|
|
|
|
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 |
|
|
|
|
6,158 |
|
|
|
30 |
% |
Coal |
|
|
|
|
|
|
|
|
|
|
Mt. Storm |
|
Mt. Storm, WV |
|
|
1,629 |
|
|
|
|
|
Chesterfield |
|
Chester, VA |
|
|
1,267 |
|
|
|
|
|
Virginia City Hybrid Energy Center |
|
Wise County, VA |
|
|
610 |
|
|
|
|
|
Clover |
|
Clover, VA |
|
|
439
|
(3)
|
|
|
|
|
Yorktown(2) |
|
Yorktown, VA |
|
|
323 |
|
|
|
|
|
Mecklenburg |
|
Clarksville, VA |
|
|
138 |
|
|
|
|
|
Total Coal |
|
|
|
|
4,406 |
|
|
|
22 |
|
Nuclear |
|
|
|
|
|
|
|
|
|
|
Surry |
|
Surry, VA |
|
|
1,676 |
|
|
|
|
|
North Anna |
|
Mineral, VA |
|
|
1,672
|
(4) |
|
|
|
|
Total Nuclear |
|
|
|
|
3,348 |
|
|
|
16 |
|
Oil |
|
|
|
|
|
|
|
|
|
|
Yorktown |
|
Yorktown, VA |
|
|
790 |
|
|
|
|
|
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 |
|
|
|
|
2,160 |
|
|
|
11 |
|
Hydro |
|
|
|
|
|
|
|
|
|
|
Bath County |
|
Warm Springs, VA |
|
|
1,802
|
(5)
|
|
|
|
|
Gaston |
|
Roanoke Rapids, NC |
|
|
220 |
|
|
|
|
|
Roanoke Rapids |
|
Roanoke Rapids, NC |
|
|
95 |
|
|
|
|
|
Other |
|
Various |
|
|
3 |
|
|
|
|
|
Total Hydro |
|
|
|
|
2,120 |
|
|
|
10 |
|
Biomass |
|
|
|
|
|
|
|
|
|
|
Pittsylvania |
|
Hurt, VA |
|
|
83 |
|
|
|
|
|
Altavista |
|
Altavista, VA |
|
|
51 |
|
|
|
|
|
Polyester |
|
Hopewell, VA |
|
|
51 |
|
|
|
|
|
Southhampton |
|
Southampton, VA |
|
|
51 |
|
|
|
|
|
Total Biomass |
|
|
|
|
236 |
|
|
|
1 |
|
Various |
|
|
|
|
|
|
|
|
|
|
Mt. Storm (CT) |
|
Mt. Storm, WV |
|
|
11 |
|
|
|
|
|
|
|
|
|
|
18,439 |
|
|
|
|
|
Power Purchase Agreements |
|
|
|
|
1,978 |
|
|
|
10 |
|
Total Utility Generation |
|
|
|
|
20,417 |
|
|
|
100 |
% |
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) |
Converted from coal to gas in 2014. |
(2) |
Coal-fired units are expected to be retired at Yorktown as early as 2016 as a result of the issuance of the MATS rule. |
(3) |
Excludes 50% undivided interest owned by ODEC. |
(4) |
Excludes 11.6% undivided interest owned by ODEC. |
(5) |
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 |
|
|
2,001
|
(1) |
|
|
|
|
Total Nuclear |
|
|
|
|
2,001 |
|
|
|
48 |
% |
Gas |
|
|
|
|
|
|
|
|
|
|
Fairless (CC) |
|
Fairless Hills, PA |
|
|
1,196 |
|
|
|
|
|
Manchester (CC) |
|
Providence, RI |
|
|
461 |
|
|
|
|
|
Total Gas |
|
|
|
|
1,657 |
|
|
|
39 |
|
Wind |
|
|
|
|
|
|
|
|
|
|
Fowler
Ridge(2) |
|
Benton County, IN |
|
|
150
|
(3)
|
|
|
|
|
NedPower Mt. Storm(2) |
|
Grant County, WV |
|
|
132 |
(4) |
|
|
|
|
Total Wind |
|
|
|
|
282 |
|
|
|
7 |
|
Solar(5) |
|
|
|
|
|
|
|
|
|
|
Camelot Solar |
|
Mojave, CA |
|
|
45 |
|
|
|
|
|
Indy Solar |
|
Indianapolis, IN |
|
|
29 |
|
|
|
|
|
CID Solar |
|
Corcoran, CA |
|
|
20 |
|
|
|
|
|
Kansas Solar |
|
Lenmore, CA |
|
|
20 |
|
|
|
|
|
Kent South Solar |
|
Lenmore, CA |
|
|
20 |
|
|
|
|
|
Old River One Solar |
|
Bakersfield, CA |
|
|
20 |
|
|
|
|
|
West Antelope Solar |
|
Lancaster, CA |
|
|
20 |
|
|
|
|
|
Adams East Solar |
|
Tranquility, CA |
|
|
19 |
|
|
|
|
|
Mulberry Solar |
|
Selmer, TN |
|
|
16 |
|
|
|
|
|
Selmer Solar |
|
Selmer, TN |
|
|
16 |
|
|
|
|
|
Columbia 2 Solar |
|
Mojave, CA |
|
|
15 |
|
|
|
|
|
Azalea Solar |
|
Davisboro, GA |
|
|
8 |
|
|
|
|
|
Somers Solar |
|
Somers, CT |
|
|
5 |
|
|
|
|
|
Total Solar |
|
|
|
|
253 |
|
|
|
6 |
|
Fuel Cell |
|
|
|
|
|
|
|
|
|
|
Bridgeport Fuel Cell |
|
Bridgeport, CT |
|
|
15 |
|
|
|
|
|
Total Fuel Cell |
|
|
|
|
15 |
|
|
|
|
|
Total Merchant Generation |
|
|
|
|
4,208 |
|
|
|
100 |
% |
Note: (CC) denotes combined cycle.
(1) |
Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. |
(2) |
Subject to a lien securing the facilitys debt. |
(3) |
Excludes 50% membership interest owned by BP. |
(4) |
Excludes 50% membership interest owned by Shell. |
(5) |
All solar facilities are alternating current. |
Item 3. Legal Proceedings
From time to time, the Companies 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 August 2014, Cove Point received a Request to Show Cause from the EPA alleging violations of certain release reporting
requirements under CERCLA and EPCRA. In February 2013, Cove Point first reported to the EPA a continuous release of ammonia emissions from the NOx control systems attached to its electric generating turbines as a part of normal operations. While
these emissions are not subject to permit limits, Cove Point verified and submitted to the EPA that the ammonia emissions periodically exceeded the reporting threshold between December 2012 and February 2013. Cove Point further submitted to the EPA
the required written follow-up reports. In December 2014, Cove Point and the EPA finalized a Consent Agreement and Final Order resolving this matter, which included a civil penalty of $365,000. Cove Point paid the penalty in December 2014.
In October 2014, Virginia Power received a draft consent order from the VDEQ in connection with excess carbon monoxide
emissions reported in February 2014 for Altavista. The draft consent order included a proposed penalty of approximately $135,000. In January 2015, Virginia Power and VDEQ finalized a consent order resolving this matter, which included a final
penalty of approximately $95,000. Virginia Power has also submitted to VDEQ a request to modify Altavistas Title V air permit to address the underlying operational issues.
In January 2015, Virginia Power received a draft consent order from the VDEQ in connection with excess particulate matter emissions
reported in August and September 2014 for Yorktown. Virginia Power submitted evidence in late September 2014 that the excess emissions have been corrected. In January 2015, Virginia Power and VDEQ finalized a consent order resolving this matter,
which included a penalty of approximately $107,000.
Also in January 2015, DTI received a draft consent agreement from the EPA
in connection with alleged violations of certain CAA monitoring and permitting requirements at the Hastings facility. The draft consent agreement includes a proposed penalty of approximately $160,000. DTI is working with the EPA to resolve this
matter. The ultimate resolution of the consent agreement is not expected to have a material effect on Dominion Gas.
See Notes
13 and 22 to the Consolidated Financial Statements and Future Issues and Other Matters in Item 7. 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 (60) |
|
Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date. Chairman and CEO of Dominion Midstream GP, LLC (the general
partner of Dominion Midstream) from March 2014 to date and President from February 2015 to date; CEO of Dominion Gas from September 2013 to date and Chairman from March 2014 to date; Chairman and CEO of Virginia Power from February 2006 to
date. |
|
|
Mark F. McGettrick (57) |
|
Executive Vice President and CFO of Dominion from June 2009 to date, Dominion Midstream GP, LLC from March 2014 to date, Virginia Power from June 2009 to date and Dominion Gas from September
2013 to date. |
|
|
David A. Christian (60) |
|
Executive Vice President and CEODominion Generation Group of Dominion from February 2013 to date; Executive Vice President of Dominion from May 2011 to February 2013; President and COO
of Virginia Power from June 2009 to date. |
|
|
Paul D. Koonce (55) |
|
Executive Vice President and CEOEnergy Infrastructure Group of Dominion from February 2013 to date; Executive Vice President of Dominion from April 2006 to February 2013; Executive Vice
President of Dominion Midstream GP, LLC from March 2014 to date; President and COO of Virginia Power from June 2009 to date; President of Dominion Gas from September 2013 to date. |
|
|
David A. Heacock (57) |
|
President and CNO of Virginia Power from June 2009 to date. |
|
|
Robert M. Blue (47) |
|
President of Virginia Power from January 2014 to date; Senior Vice President-Law, Public Policy and Environment of Dominion from January 2011 to December 2013; Senior Vice President-Public
Policy and Environment of Dominion from February 2010 to December 2010. |
|
|
Michele L. Cardiff (47) |
|
Vice President, Controller and CAO of Dominion from April 2014 to date; Vice President-Accounting of DRS from January 2014 to March 2014; Vice President, Controller and CAO of Virginia Power
from April 2014 to date, Dominion Gas from March 2014 to date, and Dominion Midstream GP, LLC from March 2014 to date and General Auditor of DRS from September 2012 to December 2013; Controller of Virginia Power from June 2009 to August
2012. |
|
|
Diane Leopold (48) |
|
President of DTI, East Ohio and Dominion Cove Point, Inc. from January 2014 to date; Senior Vice President of DTI from April 2012 to December 2013; Senior Vice PresidentBusiness
Development & Generation Construction of Virginia Power from April 2009 to March 2012. |
|
|
Mark O. Webb (50) |
|
Vice President, General Counsel and Chief Risk Officer of Dominion, Virginia Power and Dominion Gas from January 2014 to date; Vice President and
General Counsel of Dominion Midstream GP, LLC from March 2014 to date; Vice President and General Counsel of Dominion from January 2013 to December 2013; Deputy General Counsel of DRS from July 2011 to December 2012; Director-Policy & Business
Evaluation AES of DRS from May 2009 to June 2011. |
(1) |
Any service listed for Virginia Power, Dominion Midstream GP, LLC, Dominion Gas, DTI, East Ohio, Dominion Cove Point, Inc. and DRS reflects service at a subsidiary
of Dominion. |
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, 2015, there were approximately 132,000 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 2014 and 2013. 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 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
|
10/1/2014-10/31/14 |
|
|
405 |
|
|
$ |
69.26 |
|
|
|
N/A |
|
|
19,629,059 shares/$ |
1.18 billion |
|
11/1/2014-11/30/14 |
|
|
444 |
|
|
$ |
71.30 |
|
|
|
N/A |
|
|
19,629,059 shares/$ |
1.18 billion |
|
12/1/2014-12/31/14 |
|
|
|
|
|
$ |
|
|
|
|
N/A |
|
|
19,629,059 shares/$ |
1.18 billion |
|
Total |
|
|
849 |
|
|
$ |
70.33 |
|
|
|
N/A |
|
|
19,629,059 shares/$ |
1.18 billion |
|
(1) |
405 and 444 shares were tendered by employees to satisfy tax withholding obligations on vested restricted stock in October and November 2014, respectively.
|
(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 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) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
$ |
148 |
|
|
$ |
121 |
|
|
$ |
196 |
|
|
$ |
125 |
|
|
$ |
590 |
|
2013 |
|
|
148 |
|
|
|
120 |
|
|
|
195 |
|
|
|
116 |
|
|
|
579 |
|
As discussed in Note 18 to the Consolidated Financial Statements in this report, during 2014, Virginia Power redeemed all
shares of each outstanding series of its preferred stock. Effective October 30, 2014, the Virginia Power Board of Directors approved amendments to Virginia Powers Articles of Incorporation to delete references to the redeemed series of
preferred stock.
The text of the foregoing amendment to Virginia Powers Articles of Incorporation is included in the
Amended and Restated Articles of Incorporation filed with Virginia Powers quarterly report on Form 10-Q for the nine months ended September 30, 2014.
Dominion Gas
All of Dominion Gas membership interests are owned by Dominion. Restrictions on
Dominion Gas payment of distributions are discussed in Note 20 to the Consolidated Financial Statements. Dominion Gas paid quarterly distributions as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter |
|
|
Second
Quarter |
|
|
Third
Quarter |
|
|
Fourth
Quarter |
|
|
Full
Year |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
$ |
78 |
|
|
$ |
67 |
|
|
$ |
61 |
|
|
$ |
140 |
|
|
$ |
346 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
80 |
|
|
|
318 |
|
|
|
398 |
|
Item 6. Selected Financial Data
DOMINION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
(millions, except per share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
12,436 |
|
|
$ |
13,120 |
|
|
$ |
12,835 |
|
|
$ |
13,765 |
|
|
$ |
14,392 |
|
Income from continuing operations, net of tax(1) |
|
|
1,310 |
|
|
|
1,789 |
|
|
|
1,427 |
|
|
|
1,466 |
|
|
|
3,056 |
|
Loss from discontinued operations, net of tax(1) |
|
|
|
|
|
|
(92 |
) |
|
|
(1,125 |
) |
|
|
(58 |
) |
|
|
(248 |
) |
Net income attributable to Dominion |
|
|
1,310 |
|
|
|
1,697 |
|
|
|
302 |
|
|
|
1,408 |
|
|
|
2,808 |
|
Income from continuing operations before loss from discontinued operations per common share-basic |
|
|
2.25 |
|
|
|
3.09 |
|
|
|
2.49 |
|
|
|
2.56 |
|
|
|
5.19 |
|
Net income attributable to Dominion per common share-basic |
|
|
2.25 |
|
|
|
2.93 |
|
|
|
0.53 |
|
|
|
2.46 |
|
|
|
4.77 |
|
Income from continuing operations before loss from discontinued operations per common share-diluted |
|
|
2.24 |
|
|
|
3.09 |
|
|
|
2.49 |
|
|
|
2.55 |
|
|
|
5.18 |
|
Net income attributable to Dominion per common share-diluted |
|
|
2.24 |
|
|
|
2.93 |
|
|
|
0.53 |
|
|
|
2.45 |
|
|
|
4.76 |
|
Dividends declared per common share |
|
|
2.40 |
|
|
|
2.25 |
|
|
|
2.11 |
|
|
|
1.97 |
|
|
|
1.83 |
|
Total assets |
|
|
54,327 |
|
|
|
50,096 |
|
|
|
46,838 |
|
|
|
45,614 |
|
|
|
42,817 |
|
Long-term debt |
|
|
21,805 |
|
|
|
19,330 |
|
|
|
16,851 |
|
|
|
17,394 |
|
|
|
15,758 |
|
(1) |
Amounts attributable to Dominions common shareholders. |
2014 results include $248 million of after-tax charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore
wind facilities, a $193 million after-tax charge related to Dominions restructuring of its producer services business and a $174 million after-tax charge associated with the Liability Management Exercise.
2013 results include a $109 million after-tax charge related to Dominions restructuring of its producer services business ($76
million) and an impairment of certain natural gas infrastructure assets ($33 million). Also in 2013, Dominion recorded a $92 million after-tax net loss from the discontinued operations of Brayton Point and Kincaid.
2012 results include a $1.1 billion after-tax loss from discontinued operations, including impairment charges, of 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. 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.
Item 7. Managements Discussion and Analysis of Financial Condition and
Results of Operations
MD&A discusses Dominions results of operations and general financial condition and Virginia
Powers and Dominion Gas results of operations. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. Virginia Power and
Dominion Gas meet the conditions to file under the reduced disclosure format, and therefore have omitted certain sections of MD&A.
CONTENTS OF
MD&A
MD&A consists of the following information:
|
|
Forward-Looking Statements |
|
|
Accounting MattersDominion |
|
|
|
Segment Results of Operations |
|
|
Liquidity and Capital ResourcesDominion |
|
|
Future Issues and Other MattersDominion |
FORWARD-LOOKING
STATEMENTS
This report contains statements concerning the Companies 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.
The Companies 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, flooding and changes in water
temperatures and availability that can cause outages and property damage to facilities; |
|
|
Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;
|
|
|
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; |
|
|
Changes in enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;
|
|
|
Changes in regulator implementation of environmental standards and litigation exposure for remedial activities;
|
|
|
Difficult to anticipate mitigation requirements associated with environmental approvals; |
|
|
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 at facilities in which the Companies have an ownership interest; |
|
|
Fluctuations in energy-related commodity prices and the effect these could have on Dominions and Dominion Gas earnings and the
Companies 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; |
|
|
Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion
and Dominion Gas; |
|
|
Fluctuations in interest rates; |
|
|
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, transfers of assets to joint ventures or Dominion Midstream, and retirements of assets based on asset portfolio
reviews; |
|
|
Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; |
|
|
The timing and execution of Dominion Midstreams growth strategy; |
|
|
Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERCs
interpretation of market rules 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 supplies of natural gas delivered to Dominion Gas pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of
energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods; |
|
|
Additional competition in industries in which the Companies operate, including in electric markets in which Dominions merchant generation
facilities operate, and competition in the development, construction and ownership of certain 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;
|
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
|
|
Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG
storage, collected by Dominion; |
|
|
Changes in operating, maintenance and construction costs; |
|
|
Timing and receipt of regulatory approvals necessary for planned construction or expansion projects and compliance with conditions associated with such
regulatory approvals; |
|
|
The inability to complete planned construction, conversion or expansion projects at all, or with the outcomes or within the terms and time frames
initially anticipated; |
|
|
Adverse outcomes in litigation matters or regulatory proceedings; and |
|
|
The impact of operational hazards including adverse developments with respect to pipeline safety or integrity, and other catastrophic events.
|
Additionally, other risks that could cause actual results to differ from predicted results are set forth in
Item 1A. Risk Factors.
The Companies forward-looking statements are based on beliefs and assumptions using
information available at the time the statements are made. The Companies caution the reader not to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and
often do, differ materially from actual results. The Companies undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.
ACCOUNTING MATTERS
Critical Accounting Policies and Estimates
Dominion has 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 its financial condition or results of operations under different conditions or using different
assumptions. Dominion has discussed the development, selection and disclosure of each of these policies with the Audit Committee of its Board of Directors.
ACCOUNTING FOR REGULATED OPERATIONS
The accounting for Dominions regulated electric and gas operations differs from the accounting for nonregulated operations in that Dominion is required to reflect the effect of rate regulation in
its 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.
Dominion evaluates
whether or not recovery of its regulatory assets through future rates is probable and makes various assumptions in its analysis. The expectations of future recovery are generally based on orders issued by regulatory commissions,
legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. 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
recognizes 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, Dominion estimates the fair value of its AROs using present value techniques, in which it makes 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 Dominion revises any assumptions used to calculate the fair value of existing AROs, it adjusts the carrying amount of both the ARO liability and the related long-lived asset for assets that are in service; for assets that have
ceased operations, Dominion adjusts the carrying amount of the ARO liability with such changes recognized in income. Dominion accretes the ARO liability to reflect the passage of time.
In 2014, 2013 and 2012, Dominion recognized $81 million, $86 million and $77 million, respectively, of accretion, and expects to recognize
$86 million in 2015. Dominion records accretion and depreciation associated with utility nuclear decommissioning AROs as an adjustment to the regulatory liability related to its nuclear decommissioning trust.
A significant portion of Dominions AROs relates to the future decommissioning of its merchant and utility nuclear facilities. These
nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2014, Dominions nuclear decommissioning AROs totaled $1.4 billion, representing approximately 84% 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 Dominions nuclear decommissioning obligations.
Dominion obtains 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 its 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, Dominions cost estimates include cost escalation rates that are applied to the base year costs. Dominion determines 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 critical assumptions.
Primarily as a result of a shift of the delayed planned date on which the DOE is expected to begin
accepting spent nuclear fuel, in 2014 Dominion recorded an increase of $95 million to the nuclear decommissioning AROs.
In December 2013, Dominion recorded a reduction of $129 million ($47 million of which was
credited to income) in the nuclear decommissioning AROs for its units due to a reduction in estimated costs.
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, 2014, Dominion had $145 million of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of
statutes of limitations.
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 evaluates 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. Dominion establishes 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, 2014, Dominion had
established $87 million of valuation allowances.
ACCOUNTING FOR DERIVATIVE
CONTRACTS AND OTHER INSTRUMENTS AT FAIR VALUE
Dominion uses derivative contracts such as futures, swaps, forwards, options and FTRs to manage commodity, currency exchange and financial market risks of its 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 nuclear decommissioning and 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
evaluat-
ing pricing information provided by brokers and other pricing services, Dominion considers 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 Dominion believes that observable
pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, Dominion must estimate prices based on available historical and near-term future price information and use of
statistical methods, including regression analysis, that reflect its market assumptions.
Dominion maximizes the use of
observable inputs and minimizes the use of unobservable inputs when measuring fair value.
USE OF
ESTIMATES IN GOODWILL IMPAIRMENT TESTING
As of
December 31, 2014, Dominion reported $3.0 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 2014, 2013 and 2012 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. 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
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
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 selection of an appropriate discount rate. When determining whether an asset or asset group has been impaired, management groups assets at the lowest level that has identifiable cash flows.
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, mortality rates 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, healthcare cost trend rates and mortality
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; |
|
|
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. 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 8.75% for 2014 and 8.50% for 2013 and 2012. For 2015, the expected long-term rate of return for pension cost assumption is 8.75%. Dominion calculated
its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2014 and 7.75% for 2013 and 2012. For 2015, the expected long-term rate of return for other postretirement benefit cost
assumption is 8.50%. 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 ranged from 5.20% to 5.30% for pension plans and 5.00% to 5.10% for other postretirement benefit plans in 2014, ranged from 4.40% to 4.80%
in 2013 and were 5.50% in 2012. Dominion selected a discount rate of 4.40% for determining both its December 31, 2014 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, 2014 was 7.00% and is expected to gradually decrease to 5.00% by
2018 and continue at that rate for years thereafter.
Dominion develops its mortality assumption using plan-specific studies
and projects mortality improvement using scales developed by the Society of Actuaries.
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
|
|
|
$ |
1 |
|
Long-term rate of return on plan assets |
|
|
(0.25 |
)% |
|
|
15 |
|
|
|
3 |
|
Healthcare cost trend rate |
|
|
1 |
%
|
|
|
N/A |
|
|
|
26 |
|
In addition to the effects on cost, at December 31, 2014, a 0.25% decrease in the discount rate would
increase Dominions projected pension benefit obligation by $236 million and its accumulated postretirement benefit obligation by $47 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated
postretirement benefit obligation by $186 million.
See Note 21 to the Consolidated Financial Statements for additional
information on Dominions employee benefit plans.
DOMINION
RESULTS OF OPERATIONS
Presented below is a
summary of Dominions consolidated results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
$ Change |
|
|
2013 |
|
|
$ Change |
|
|
2012 |
|
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income attributable to Dominion |
|
$ |
1,310 |
|
|
$ |
(387 |
) |
|
$ |
1,697 |
|
|
$ |
1,395 |
|
|
$ |
302 |
|
Diluted EPS |
|
|
2.24 |
|
|
|
(0.69 |
) |
|
|
2.93 |
|
|
|
2.40 |
|
|
|
0.53 |
|
Overview
2014
VS. 2013
Net income attributable to Dominion decreased by 23% primarily due to charges associated with Virginia legislation
enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, charges associated with Dominions Liability Management Exercise, and the repositioning of Dominions producer
services business, which was completed in the first quarter of 2014. See Note 13 for more information on legislation related to North Anna and offshore wind facilities. See Liquidity and Capital Resources for more information on the Liability
Management Exercise. These decreases were partially offset by an increase in investment tax credits received, primarily from new solar projects.
2013 VS. 2012
Net income
attributable to Dominion increased by $1.4 billion primarily due to the absence of impairment and other charges recorded in 2012 related to the discontinued operations of Brayton Point and Kincaid and managements decision to cease operations
and begin decommissioning Kewaunee in 2013.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominions results of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
$ Change |
|
|
2013 |
|
|
$ Change |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue |
|
$ |
12,436 |
|
|
$ |
(684 |
) |
|
$ |
13,120 |
|
|
$ |
285 |
|
|
$ |
12,835 |
|
Electric fuel and other energy-related purchases |
|
|
3,400 |
|
|
|
(485 |
) |
|
|
3,885 |
|
|
|
240 |
|
|
|
3,645 |
|
Purchased electric capacity |
|
|
361 |
|
|
|
3 |
|
|
|
358 |
|
|
|
(29 |
) |
|
|
387 |
|
Purchased gas |
|
|
1,355 |
|
|
|
24 |
|
|
|
1,331 |
|
|
|
154 |
|
|
|
1,177 |
|
Net Revenue |
|
|
7,320 |
|
|
|
(226 |
) |
|
|
7,546 |
|
|
|
(80 |
) |
|
|
7,626 |
|
Other operations and maintenance |
|
|
2,765 |
|
|
|
306 |
|
|
|
2,459 |
|
|
|
(632 |
) |
|
|
3,091 |
|
Depreciation, depletion and amortization |
|
|
1,292 |
|
|
|
84 |
|
|
|
1,208 |
|
|
|
81 |
|
|
|
1,127 |
|
Other taxes |
|
|
542 |
|
|
|
(21 |
) |
|
|
563 |
|
|
|
13 |
|
|
|
550 |
|
Other income |
|
|
250 |
|
|
|
(15 |
) |
|
|
265 |
|
|
|
42 |
|
|
|
223 |
|
Interest and related charges |
|
|
1,193 |
|
|
|
316 |
|
|
|
877 |
|
|
|
61 |
|
|
|
816 |
|
Income tax expense |
|
|
452 |
|
|
|
(440 |
) |
|
|
892 |
|
|
|
81 |
|
|
|
811 |
|
Loss from discontinued operations |
|
|
|
|
|
|
92 |
|
|
|
(92 |
) |
|
|
1,033 |
|
|
|
(1,125 |
) |
An analysis of Dominions results of operations follows:
2014 VS. 2013
Net revenue decreased 3%, primarily
reflecting:
|
|
A $263 million decrease from retail energy marketing operations, primarily due to the sale of the retail electric business in March 2014; and
|
|
|
A $195 million decrease primarily related to the repositioning of Dominions producer services business which was completed in the first quarter
of 2014, reflecting the termination of natural gas trading and certain energy marketing activities. |
These
decreases were partially offset by:
|
|
A $171 million increase from electric utility operations, primarily reflecting: |
|
|
|
An increase from rate adjustment clauses at electric utility operations ($132 million); and |
|
|
|
An increase in sales from electric utility operations primarily due to an increase in heating degree days ($34 million);
|
|
|
A $46 million increase in gas transportation and storage activities and other revenues, largely due to various expansion projects being placed into
service; and |
|
|
A $35 million increase in merchant generation margins, primarily due to higher realized prices ($120 million), partially offset by lower generation
output due to the decommissioning of Kewaunee beginning in May 2013 ($95 million). |
Other operations and maintenance
increased 12%, primarily reflecting:
|
|
$370 million in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North
Anna and offshore wind facilities; |
|
|
A $135 million increase in planned outage costs at certain merchant generation facilities and at certain non-nuclear utility facilities; and
|
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
|
|
A $121 million charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities.
|
These increases were partially offset by:
|
|
A gain on the sale of Dominions electric retail energy marketing business in March 2014 ($100 million), net of a $31 million write-off of
goodwill; |
|
|
A $67 million decrease primarily due to the deferral of utility nuclear outage costs beginning in the second quarter of 2014, pursuant to the Virginia
legislation enacted in April 2014; |
|
|
The absence of a $65 million charge primarily reflecting impairment charges recorded in 2013 for certain natural gas infrastructure assets; and
|
|
|
A decrease in bad debt expense at regulated natural gas distribution operations primarily related to low-income assistance programs ($53 million).
These bad debt expenses are recovered through rates and do not impact net income. |
Interest and related charges increased 36%, primarily due to charges associated with Dominions
Liability Management Exercise in 2014 ($284 million) and higher long-term debt interest expense resulting from debt issuances in 2014 ($44 million).
Income tax expense decreased 49%, primarily reflecting lower pre-tax income ($350 million) and the impact of federal renewable energy investment tax
credits ($105 million).
Loss from discontinued operations reflects the
sale of Brayton Point and Kincaid in 2013.
2013 VS. 2012
Net Revenue decreased 1%, primarily reflecting:
|
|
A $162 million decrease in producer services primarily related to unfavorable price changes on economic hedging positions, partially offset by higher
physical margins, all associated with natural gas aggregation, marketing and trading activities; |
|
|
A $111 million decrease in retail energy marketing activities primarily due to the impact of lower margins on electric sales due to higher purchased
power costs; and |
|
|
A $98 million decrease from merchant generation operations, primarily due to lower generation output ($133 million) largely due to the May 2013 closure
of Kewaunee, partially offset by higher realized prices ($35 million). |
These decreases were partially offset
by:
|
|
A $161 million increase from electric utility operations, primarily reflecting: |
|
|
|
An increase in sales to retail customers, primarily due to an increase in heating degree days ($112 million); and |
|
|
|
An increase from rate adjustment clauses ($92 million); partially offset by |
|
|
|
A decrease in ancillary revenues received from PJM ($12 million) primarily due to a decrease in net operating reserve credits; and
|
|
|
A $144 million increase from regulated natural gas transmission operations primarily related to the Appalachian Gateway Project that was placed into
service in September 2012 ($44 million), an increase in gathering and storage services ($38 million), NGL activities primarily related to an increase in processing and fractionation volumes ($19 million) and the Northeast Expansion Project that was
placed into service in November 2012 ($16 million).
|
Other operations and
maintenance decreased 20%, primarily reflecting:
|
|
A $589 million decrease related to Kewaunee largely due to the absence of charges recorded in 2012 following managements decision to cease
operations and begin decommissioning in 2013; |
|
|
A $123 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates;
|
|
|
A $54 million decrease in storm damage and service restoration costs primarily due to the absence of damage caused by late June summer storms in 2012;
|
|
|
A $42 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 |
|
|
Increased gains from the sales of assets to Blue Racer ($32 million). |
These decreases were partially offset by:
|
|
A $65 million increase primarily related to impairment charges for certain natural gas infrastructure assets; |
|
|
A $46 million increase resulting from impacts of the 2013 Biennial Review Order; |
|
|
A $35 million increase due to the absence of adjustments recorded in 2012 in connection with the 2012 North Carolina rate case;
|
|
|
A $34 million increase in PJM operating reserves and reactive service charges; and |
|
|
A $26 million charge related to the expected shutdown of certain coal-fired generating units. |
Other Income increased 19%, primarily due to higher realized gains (including
investment income) on nuclear decommissioning trust funds ($40 million) and a gain on the sale of Dominions 50% equity method investment in Elwood ($35 million), partially offset by a decrease in the equity component of AFUDC ($15 million) and
a decrease in earnings from equity method investments ($11 million).
Income tax
expense increased 10%, primarily reflecting higher pre-tax income in 2013 ($169 million), partially offset by an increase in renewable energy investment tax credits ($46 million) and a lower effective rate for state income taxes ($45
million).
Loss from discontinued operations reflects the sale of
Brayton Point and Kincaid in 2013.
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 expects 80% to 90% of future earnings from its primary operating segments to come from regulated and long-term contracted businesses.
In 2015, Dominion is expected to experience an increase in net income on a per share basis as compared to 2014. Dominions
anticipated 2015 results reflect the following significant factors:
|
|
A return to normal weather in its electric utility operations; |
|
|
Growth in weather-normalized electric utility sales of approximately 1%, comparable to 2014 growth;
|
|
|
Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue;
|
|
|
The absence of certain charges incurred in 2014, including charges associated with Virginia legislation enacted in April 2014 relating to the
development of a third nuclear unit located at North Anna and offshore wind facilities, charges associated with Dominions Liability Management Exercise, charges related to the repositioning of Dominions producer services business, which
was completed in the first quarter of 2014, and charges related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities; |
|
|
Construction and operation of growth projects in gas transmission and distribution; partially offset by |
|
|
An increase in depreciation, depletion, and amortization; |
|
|
Higher operating and maintenance expenses; and |
|
|
A higher effective tax rate, driven primarily by higher state income tax expense and lower investment tax credits. |
Additionally, in 2015, Dominion expects to focus on meeting new and developing environmental requirements, including by making significant
investments in utility solar generation, particularly in Virginia.
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, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
|
Net
Income attribu-
table
to Dominion |
|
|
Diluted
EPS |
|
|
Net
Income attribu-
table to Dominion |
|
|
Diluted
EPS |
|
|
Net
Income attribu-
table to Dominion |
|
|
Diluted
EPS |
|
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DVP |
|
$ |
502 |
|
|
$ |
0.86 |
|
|
$ |
475 |
|
|
$ |
0.82 |
|
|
$ |
439 |
|
|
$ |
0.77 |
|
Dominion Generation |
|
|
1,101 |
|
|
|
1.88 |
|
|
|
1,031 |
|
|
|
1.78 |
|
|
|
1,021 |
|
|
|
1.78 |
|
Dominion Energy |
|
|
677 |
|
|
|
1.16 |
|
|
|
643 |
|
|
|
1.11 |
|
|
|
551 |
|
|
|
0.96 |
|
Primary operating segments |
|
|
2,280 |
|
|
|
3.90 |
|
|
|
2,149 |
|
|
|
3.71 |
|
|
|
2,011 |
|
|
|
3.51 |
|
Corporate and Other |
|
|
(970 |
) |
|
|
(1.66 |
) |
|
|
(452 |
) |
|
|
(0.78 |
) |
|
|
(1,709 |
) |
|
|
(2.98 |
) |
Consolidated |
|
$ |
1,310 |
|
|
$ |
2.24 |
|
|
$ |
1,697 |
|
|
$ |
2.93 |
|
|
$ |
302 |
|
|
$ |
0.53 |
|
DVP
Presented
below are operating statistics related to DVPs operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
% Change |
|
|
2013 |
|
|
% Change |
|
|
2012 |
|
Electricity delivered (million MWh) |
|
|
83.5 |
|
|
|
1 |
% |
|
|
82.4 |
|
|
|
2 |
% |
|
|
80.8 |
|
Degree days: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cooling |
|
|
1,638 |
|
|
|
|
|
|
|
1,645 |
|
|
|
(8 |
) |
|
|
1,787 |
|
Heating |
|
|
3,793 |
|
|
|
4 |
|
|
|
3,651 |
|
|
|
24 |
|
|
|
2,955 |
|
Average electric distribution customer accounts (thousands)(1) |
|
|
2,500 |
|
|
|
1 |
|
|
|
2,475 |
|
|
|
1 |
|
|
|
2,455 |
|
Presented below, on an after-tax basis, are the key factors impacting DVPs net income contribution:
2014 VS. 2013
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
|
Amount |
|
|
EPS |
|
(millions, except EPS) |
|
|
|
|
|
|
Regulated electric sales: |
|
|
|
|
|
|
|
|
Weather |
|
$ |
8 |
|
|
$ |
0.01 |
|
Other |
|
|
(1 |
) |
|
|
|
|
FERC transmission equity return |
|
|
27 |
|
|
|
0.04 |
|
Storm damage and service restoration |
|
|
13 |
|
|
|
0.02 |
|
Depreciation |
|
|
(8 |
) |
|
|
(0.01 |
) |
Other |
|
|
(12 |
) |
|
|
(0.02 |
) |
Change in net income contribution |
|
$ |
27 |
|
|
$ |
0.04 |
|
2013 VS. 2012
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
|
Amount |
|
|
EPS |
|
(millions, except EPS) |
|
|
|
|
|
|
Regulated electric sales: |
|
|
|
|
|
|
|
|
Weather |
|
$ |
24 |
|
|
$ |
0.04 |
|
Other |
|
|
(2 |
) |
|
|
|
|
FERC transmission equity return |
|
|
30 |
|
|
|
0.05 |
|
Storm damage and service restoration(1) |
|
|
(20 |
) |
|
|
(0.03 |
) |
Depreciation |
|
|
(7 |
) |
|
|
(0.01 |
) |
Other operations and maintenance expense |
|
|
7 |
|
|
|
0.01 |
|
Other |
|
|
4 |
|
|
|
0.01 |
|
Share dilution |
|
|
|
|
|
|
(0.02 |
) |
Change in net income contribution |
|
$ |
36 |
|
|
$ |
0.05 |
|
(1) |
Excludes restoration costs associated with damage caused by severe storms in 2012, which are reflected in the Corporate and Other segment.
|
Dominion Generation
Presented below are operating statistics related to Dominion Generations operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
% Change |
|
|
2013 |
|
|
% Change |
|
|
2012 |
|
Electricity supplied (million MWh): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility |
|
|
83.9 |
|
|
|
1 |
% |
|
|
82.8 |
|
|
|
2 |
% |
|
|
80.9 |
|
Merchant(1) |
|
|
25.0 |
|
|
|
(6 |
) |
|
|
26.6 |
|
|
|
(5 |
) |
|
|
28.0 |
|
Degree days (electric utility service area): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cooling |
|
|
1,638 |
|
|
|
|
|
|
|
1,645 |
|
|
|
(8 |
) |
|
|
1,787 |
|
Heating |
|
|
3,793 |
|
|
|
4 |
|
|
|
3,651 |
|
|
|
24 |
|
|
|
2,955 |
|
Average retail energy marketing customer accounts (thousands)(2) |
|
|
1,283 |
(3) |
|
|
(39 |
) |
|
|
2,119 |
|
|
|
|
|
|
|
2,129 |
|
(1) |
Excludes 7.6 million and 12.8 million MWh for 2013 and 2012, respectively, related to Kewaunee, Brayton Point, Kincaid, State Line, Salem and
Dominions equity method investment in Elwood. There are no exclusions related to these stations in 2014. |
(3) |
Excludes 511 thousand average retail electric energy marketing customer accounts due to the sale of this business in March 2014.
|
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
Presented below, on an after-tax basis, are the key factors impacting Dominion Generations net income
contribution:
2014 VS. 2013
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
|
Amount |
|
|
EPS |
|
(millions, except EPS) |
|
|
|
|
|
|
Merchant generation margin |
|
$ |
64 |
|
|
$ |
0.11 |
|
Regulated electric sales: |
|
|
|
|
|
|
|
|
Weather |
|
|
13 |
|
|
|
0.02 |
|
Other |
|
|
(7 |
) |
|
|
(0.01 |
) |
Retail energy marketing operations(1) |
|
|
(20 |
) |
|
|
(0.04 |
) |
Rate adjustment clause equity return |
|
|
(8 |
) |
|
|
(0.01 |
) |
PJM ancillary services |
|
|
24 |
|
|
|
0.04 |
|
Renewable energy investment tax credits |
|
|
97 |
|
|
|
0.17 |
|
Outage costs |
|
|
(40 |
) |
|
|
(0.07 |
) |
AFUDC equity return |
|
|
(17 |
) |
|
|
(0.04 |
) |
Salaries and benefits |
|
|
(11 |
) |
|
|
(0.03 |
) |
Other |
|
|
(25 |
) |
|
|
(0.04 |
) |
Change in net income contribution |
|
$ |
70 |
|
|
$ |
0.10 |
|
(1) |
Excludes earnings from Retail electric energy marketing, which was sold in March 2014. |
2013 VS. 2012
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
|
Amount |
|
|
EPS |
|
(millions, except EPS) |
|
|
|
|
|
|
Merchant generation margin |
|
$ |
(14 |
) |
|
$ |
(0.02 |
) |
Regulated electric sales: |
|
|
|
|
|
|
|
|
Weather |
|
|
44 |
|
|
|
0.08 |
|
Other |
|
|
(4 |
) |
|
|
(0.01 |
) |
Retail energy marketing operations |
|
|
(54 |
) |
|
|
(0.09 |
) |
Rate adjustment clause equity return |
|
|
35 |
|
|
|
0.06 |
|
PJM ancillary services |
|
|
(26 |
) |
|
|
(0.05 |
) |
Renewable energy investment tax credits |
|
|
40 |
|
|
|
0.07 |
|
Outage costs |
|
|
10 |
|
|
|
0.02 |
|
Other |
|
|
(21 |
) |
|
|
(0.04 |
) |
Share dilution |
|
|
|
|
|
|
(0.02 |
) |
Change in net income contribution |
|
$ |
10 |
|
|
$ |
|
|
Dominion Energy
Presented below are selected operating statistics related to Dominion Energys operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
% Change |
|
|
2013 |
|
|
% Change |
|
|
2012 |
|
Gas distribution throughput (bcf): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
32 |
|
|
|
10 |
% |
|
|
29 |
|
|
|
12 |
% |
|
|
26 |
|
Transportation |
|
|
353 |
|
|
|
26 |
|
|
|
281 |
|
|
|
8 |
|
|
|
259 |
|
Heating degree days |
|
|
6,330 |
|
|
|
8 |
|
|
|
5,875 |
|
|
|
18 |
|
|
|
4,986 |
|
Average gas distribution customer accounts
(thousands)(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
244 |
|
|
|
(1 |
) |
|
|
246 |
|
|
|
(2 |
) |
|
|
251 |
|
Transportation |
|
|
1,052 |
|
|
|
|
|
|
|
1,049 |
|
|
|
|
|
|
|
1,044 |
|
Presented below, on an after-tax basis, are the key factors impacting Dominion Energys net income
contribution:
2014 VS. 2013
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
|
Amount |
|
|
EPS |
|
(millions, except EPS) |
|
|
|
|
|
|
Gas distribution margin: |
|
|
|
|
|
|
|
|
Weather |
|
$ |
4 |
|
|
$ |
0.01 |
|
Rate adjustment clauses |
|
|
15 |
|
|
|
0.02 |
|
Other |
|
|
5 |
|
|
|
0.01 |
|
Assignments of Marcellus acreage |
|
|
31 |
|
|
|
0.05 |
|
Depreciation |
|
|
(8 |
) |
|
|
(0.01 |
) |
Blue Racer(1) |
|
|
(1 |
) |
|
|
|
|
Other |
|
|
(12 |
) |
|
|
(0.03 |
) |
Change in net income contribution |
|
$ |
34 |
|
|
$ |
0.05 |
|
(1) |
Includes a $24 million decrease in gains from the sale of assets. |
2013 VS. 2012
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) |
|
|
|
Amount |
|
|
EPS |
|
(millions, except EPS) |
|
|
|
|
|
|
Weather |
|
$ |
8 |
|
|
$ |
0.01 |
|
Producer services margin(1) |
|
|
(37 |
) |
|
|
(0.06 |
) |
Gas transmission margin(2) |
|
|
88 |
|
|
|
0.15 |
|
Blue Racer(3) |
|
|
17 |
|
|
|
0.03 |
|
Assignment of Marcellus acreage |
|
|
12 |
|
|
|
0.02 |
|
Other |
|
|
4 |
|
|
|
0.01 |
|
Share dilution |
|
|
|
|
|
|
(0.01 |
) |
Change in net income contribution |
|
$ |
92 |
|
|
$ |
0.15 |
|
(1) |
Excludes charges incurred in 2013 associated with the ongoing exit of natural gas trading and certain energy marketing activities which are reflected in the
Corporate and Other segment. |
(2) |
Primarily reflects a full year of the Appalachian Gateway Project in service. |
(3) |
Includes a $15 million increase in gains from the sale of assets. |
Corporate and Other
Presented below are the Corporate and Other segments after-tax results:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions, except EPS amounts) |
|
|
|
|
|
|
|
|
|
Specific items attributable to operating segments |
|
$ |
(544 |
) |
|
$ |
(184 |
) |
|
$ |
(1,467 |
) |
Specific items attributable to Corporate and Other segment |
|
|
(149 |
) |
|
|
|
|
|
|
(5 |
) |
Total specific items |
|
|
(693 |
) |
|
|
(184 |
) |
|
|
(1,472 |
) |
Other corporate operations |
|
|
(277 |
) |
|
|
(268 |
) |
|
|
(237 |
) |
Total net expense |
|
$ |
(970 |
) |
|
$ |
(452 |
) |
|
$ |
(1,709 |
) |
EPS impact |
|
$ |
(1.66 |
) |
|
$ |
(0.78 |
) |
|
$ |
(2.98 |
) |
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 those segments performance or allocating resources among the segments. See Note 25 to the Consolidated Financial Statements for discussion of these items in more detail. Corporate and other also includes
specific items attributable to the Corporate and Other segment. In 2014, this primarily includes $174 million in after-tax charges associated with Dominions Liability Management Exercise.
VIRGINIA POWER
RESULTS OF OPERATIONS
Presented below is a
summary of Virginia Powers consolidated results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
$ Change |
|
|
2013 |
|
|
$ Change |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
858 |
|
|
$ |
(280 |
) |
|
$ |
1,138 |
|
|
$ |
88 |
|
|
$ |
1,050 |
|
Overview
2014
VS. 2013
Net income decreased by 25% primarily due to charges associated with Virginia legislation enacted in April 2014
relating to the development of a third nuclear unit located at North Anna and offshore wind facilities.
2013 VS. 2012
Net income increased by 8% primarily due to an increase in rate adjustment clause revenue, the impact of more favorable weather on utility
operations, and the absence of restoration costs associated with damage caused by late June 2012 summer storms.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Powers results of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
$ Change |
|
|
2013 |
|
|
$ Change |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue |
|
$ |
7,579 |
|
|
$ |
284 |
|
|
$ |
7,295 |
|
|
$ |
69 |
|
|
$ |
7,226 |
|
Electric fuel and other energy-related purchases |
|
|
2,406 |
|
|
|
102 |
|
|
|
2,304 |
|
|
|
(64 |
) |
|
|
2,368 |
|
Purchased electric capacity |
|
|
360 |
|
|
|
2 |
|
|
|
358 |
|
|
|
(28 |
) |
|
|
386 |
|
Net Revenue |
|
|
4,813 |
|
|
|
180 |
|
|
|
4,633 |
|
|
|
161 |
|
|
|
4,472 |
|
Other operations and maintenance |
|
|
1,916 |
|
|
|
465 |
|
|
|
1,451 |
|
|
|
(15 |
) |
|
|
1,466 |
|
Depreciation and amortization |
|
|
915 |
|
|
|
62 |
|
|
|
853 |
|
|
|
71 |
|
|
|
782 |
|
Other taxes |
|
|
258 |
|
|
|
9 |
|
|
|
249 |
|
|
|
17 |
|
|
|
232 |
|
Other income |
|
|
93 |
|
|
|
7 |
|
|
|
86 |
|
|
|
(10 |
) |
|
|
96 |
|
Interest and related charges |
|
|
411 |
|
|
|
42 |
|
|
|
369 |
|
|
|
(16 |
) |
|
|
385 |
|
Income tax expense |
|
|
548 |
|
|
|
(111 |
) |
|
|
659 |
|
|
|
6 |
|
|
|
653 |
|
An analysis of Virginia Powers results of operations follows:
2014 VS. 2013
Other operations and maintenance increased 32%, primarily reflecting:
|
|
$370 million in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North
Anna and offshore wind facilities; and |
|
|
A $121 million charge related to a settlement offer to incur future ash pond closure costs at certain generation facilities.
|
Interest and related charges increased 11%, primarily
due to higher long-term debt interest expense resulting from debt issuances in August 2013 and February 2014.
Income tax expense decreased 17%, primarily reflecting lower pre-tax income.
2013 VS. 2012
Net Revenue increased 4%, primarily reflecting:
|
|
An increase in sales to retail customers, primarily due to an increase in heating degree days ($112 million); and |
|
|
An increase from rate adjustment clauses ($92 million); partially offset by |
|
|
A decrease in ancillary revenues received from PJM ($12 million) primarily due to a decrease in net operating reserve credits.
|
Other operations and maintenance decreased 1%, primarily reflecting:
|
|
A $123 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates; and
|
|
|
A $54 million decrease in storm damage and service restoration costs primarily due to the absence of damage caused by late June summer storms in 2012.
|
These decreases were partially offset by:
|
|
A $46 million increase resulting from impacts of the 2013 Biennial Review Order; |
|
|
A $35 million increase due to the absence of adjustments recorded in 2012 in connection with the 2012 North Carolina rate case;
|
|
|
A $34 million increase in PJM operating reserves and reactive service charges; |
|
|
A $26 million charge related to the expected shutdown of certain coal-fired generating units; and |
|
|
A $22 million increase in salaries, wages and benefits. |
DOMINION GAS
RESULTS OF
OPERATIONS
Presented below is a summary of Dominion Gas consolidated results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
$ Change |
|
|
2013 |
|
|
$ Change |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
$ |
512 |
|
|
$ |
51 |
|
|
$ |
461 |
|
|
$ |
2 |
|
|
$ |
459 |
|
Overview
2014
VS. 2013
Net income increased by 11% primarily due to the absence of impairment charges for certain natural gas
infrastructure assets and increased gains due to assignments of Marcellus acreage, partially offset by decreased gains on sales of assets to related parties.
2013 VS. 2012
Net income increased $2 million due to increased revenue from
operations, primarily reflecting the Appalachian Gateway Project and the Northeast Expansion Project being placed into service, partially offset by decreased gains on sales of assets and impairment charges related to certain natural gas
infrastructure assets.
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion Gas results of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
$ Change |
|
|
2013 |
|
|
$ Change |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue |
|
$ |
1,898 |
|
|
$ |
(39 |
) |
|
$ |
1,937 |
|
|
$ |
260 |
|
|
$ |
1,677 |
|
Purchased gas |
|
|
315 |
|
|
|
(8 |
) |
|
|
323 |
|
|
|
88 |
|
|
|
235 |
|
Other energy-related purchases |
|
|
40 |
|
|
|
(53 |
) |
|
|
93 |
|
|
|
52 |
|
|
|
41 |
|
Net Revenue |
|
|
1,543 |
|
|
|
22 |
|
|
|
1,521 |
|
|
|
120 |
|
|
|
1,401 |
|
Other operations and maintenance |
|
|
338 |
|
|
|
(85 |
) |
|
|
423 |
|
|
|
88 |
|
|
|
335 |
|
Depreciation and amortization |
|
|
197 |
|
|
|
9 |
|
|
|
188 |
|
|
|
12 |
|
|
|
176 |
|
Other taxes |
|
|
157 |
|
|
|
9 |
|
|
|
148 |
|
|
|
8 |
|
|
|
140 |
|
Other income |
|
|
22 |
|
|
|
(6 |
) |
|
|
28 |
|
|
|
(9 |
) |
|
|
37 |
|
Interest and related charges |
|
|
27 |
|
|
|
(1 |
) |
|
|
28 |
|
|
|
(12 |
) |
|
|
40 |
|
Income tax expense |
|
|
334 |
|
|
|
33 |
|
|
|
301 |
|
|
|
13 |
|
|
|
288 |
|
An analysis of Dominion Gas results of operations follows:
2014 VS. 2013
Other operations
and maintenance decreased 20%, primarily reflecting:
|
|
The absence of impairment charges related to certain natural gas infrastructure assets ($55 million); |
|
|
A decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs ($53 million).
These bad debt expenses are recovered through rates and do not impact net income; and |
|
|
An increase in gains associated with assignments of Marcellus acreage ($42 million); partially offset by |
|
|
Decreased gains on the sale of assets to related parties ($43 million). |
Income tax expense increased 11% primarily reflecting higher pre-tax income.
2013 VS. 2012
Net Revenue increased
9%, primarily reflecting:
|
|
An increase in gas transmission transportation revenue primarily due to the Appalachian Gateway Project being placed into service in September 2012
($64 million) and the Northeast Expansion Project that was placed into service in November 2012 ($16 million); |
|
|
An increase in gathering and storage services ($32 million); |
|
|
An increase in sales to gas distribution customers primarily due to an increase in heating degree days and other revenues ($18 million); and
|
|
|
an increase in AMR and PIR program revenues ($16 million). |
These increases were partially offset by:
|
|
A decrease in rider revenue primarily related to bad debt expense ($42 million) related to low income assistance programs.
|
Other operations and maintenance increased 26%,
primarily reflecting:
|
|
Decreased gains on the sales of pipeline systems ($72 million); and |
|
|
Impairment charges related to certain natural gas infrastructure assets ($55 million). |
These decreases were partially offset by:
|
|
A $42 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These
bad debt expenses are recovered through rates and not impact net income; and |
|
|
An $18 million gain from agreements to convey Marcellus Shale development rights underneath several natural gas storage fields.
|
Other income decreased 24%, primarily due to a
decrease in the equity component of AFUDC due to significant projects being placed into service in the second half of 2012.
Interest and related charges decreased 30%, primarily due to lower interest
on affiliated long-term debt resulting from lower outstanding debt due to the extinguishment of intercompany borrowings through the sale of two pipelines to an affiliate in December 2012 and the acquisition of intercompany borrowings from debt
issued to third parties in October 2013 ($18 million), partially offset by a decrease in the debt component of AFUDC ($7 million) due to significant projects being placed into service in the second half of 2012.
LIQUIDITY AND CAPITAL RESOURCES
Dominion depends 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, 2014, Dominion had $1.7 billion of unused capacity under its credit facilities. See additional discussion below
under Credit Facilities and Short-Term Debt.
A summary of Dominions cash flows is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
$ |
316 |
|
|
$ |
248 |
|
|
$ |
102 |
|
Cash flows provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
|
3,439 |
|
|
|
3,433 |
|
|
|
4,137 |
|
Investing activities |
|
|
(5,181 |
) |
|
|
(3,458 |
) |
|
|
(3,840 |
) |
Financing activities |
|
|
1,744 |
|
|
|
93 |
|
|
|
(151 |
) |
Net increase in cash and cash equivalents |
|
|
2 |
|
|
|
68 |
|
|
|
146 |
|
Cash and cash equivalents at end of year |
|
$ |
318 |
|
|
$ |
316 |
|
|
$ |
248 |
|
Operating Cash Flows
Net cash provided by Dominions operating activities did not change significantly for 2014.
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 2015,
Dominions Board of Directors updated the dividend policy it set in December 2012 to a target payout ratio of 70-75%, and established an annual dividend rate for 2015 of $2.59 per share of common stock, an 8% increase over the 2014 rate. In
January 2015, Dominions Board of Directors declared dividends payable March 20, 2015 of 64.75 cents per share of common stock. Declarations of dividends are subject to further Board of Directors approval.
Dominions 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, 2014 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) |
|
$ |
189 |
|
|
$ |
114 |
|
|
$ |
75 |
|
Non-investment grade(2) |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
No external ratings: |
|
|
|
|
|
|
|
|
|
|
|
|
Internally rated-investment grade(3) |
|
|
7 |
|
|
|
|
|
|
|
7 |
|
Internally rated-non-investment grade(4) |
|
|
31 |
|
|
|
|
|
|
|
31 |
|
Total |
|
$ |
228 |
|
|
$ |
114 |
|
|
$ |
114 |
|
(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 47% 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 6% of the total net credit exposure. |
(4) |
The five largest counterparty exposures, combined, for this category represented approximately 20% of the total net credit exposure. |
Investing Cash Flows
In 2014, net cash used in
Dominions investing activities increased by $1.7 billion, primarily due to higher capital expenditures and lower proceeds from sales of assets and businesses.
Financing Cash Flows and Liquidity
Dominion relies on capital markets as significant sources of
funding for capital requirements not satisfied by cash provided by its operations. As discussed in Credit Ratings, Dominions 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.
Dominion 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 Dominion to use
automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.
In 2014, net cash provided by Dominions financing activities increased by $1.7 billion, primarily reflecting higher net debt issuances, proceeds from Dominion Midstreams initial public
offering and the absence of the acquisition of the Juniper non-controlling interest recorded in 2013 related to Fairless.
LIABILITY MANAGEMENT
During 2014, Dominion elected to redeem certain debt and preferred securities prior to their stated maturities. Proceeds from the issuance of lower-cost senior and enhanced junior subordinated notes
were used to fund the redemption payments. See Note 17 to the Consolidated Financial Statements for descriptions of these redemptions.
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 tender offers or otherwise.
CREDIT FACILITIES AND
SHORT-TERM DEBT
Dominion uses 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, Dominion is required to provide collateral to counterparties under some circumstances.
Under certain collateral arrangements, Dominion 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, Dominion may 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 Dominion 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.
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominions commercial paper and letters of credit outstanding, as well as capacity
available under credit facilities, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
Facility
Limit |
|
|
Outstanding
Commercial Paper |
|
|
Outstanding
Letters of Credit |
|
|
Facility
Capacity Available |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(1) |
|
$ |
4,000 |
|
|
$ |
2,664 |
|
|
$ |
|
|
|
$ |
1,336 |
|
Joint revolving credit
facility(2) |
|
|
500 |
|
|
|
111 |
|
|
|
48 |
|
|
|
341 |
|
Total |
|
$ |
4,500 |
|
|
$ |
2,775 |
(3) |
|
$ |
48 |
|
|
$ |
1,677 |
|
(1) |
In May 2014, this credit facility was amended and restated. The facility limit was increased from $3 billion to $4 billion and the maturity date was extended from
September 2018 to April 2019. 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) |
In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. 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 0.38% and 0.33% at December 31, 2014
and 2013, respectively. |
SHORT-TERM NOTES
In November 2013, Dominion issued $400 million of private placement short-term notes that matured and were repaid in November 2014 and bore interest at a
variable rate. The proceeds were used for general corporate purposes.
In November 2014, Dominion issued $400 million of
private placement short-term notes that mature in November 2015 and bear interest at a variable rate. The proceeds were used for general corporate purposes.
LONG-TERM DEBT
During 2014, Dominion issued
the following long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
Type |
|
Principal |
|
|
Rate |
|
|
Maturity |
|
|
|
(millions) |
|
|
|
|
|
|
|
Senior notes |
|
$ |
400 |
|
|
|
1.25 |
% |
|
|
2017 |
|
Senior notes |
|
|
700 |
|
|
|
2.50 |
% |
|
|
2019 |
|
Senior notes |
|
|
450 |
|
|
|
2.50 |
% |
|
|
2019 |
|
Senior notes |
|
|
350 |
|
|
|
3.45 |
% |
|
|
2024 |
|
Senior notes |
|
|
450 |
|
|
|
3.60 |
% |
|
|
2024 |
|
Senior notes |
|
|
500 |
|
|
|
3.63 |
% |
|
|
2024 |
|
Senior notes |
|
|
600 |
|
|
|
4.45 |
% |
|
|
2044 |
|
Senior notes |
|
|
500 |
|
|
|
4.60 |
% |
|
|
2044 |
|
Senior notes |
|
|
450 |
|
|
|
4.70 |
% |
|
|
2044 |
|
Enhanced junior subordinated notes |
|
|
685 |
|
|
|
5.75 |
% |
|
|
2054 |
|
Remarketable subordinated notes |
|
|
1,000 |
|
|
|
1.50 |
% |
|
|
2020 |
|
Total notes issued |
|
$ |
6,085 |
|
|
|
|
|
|
|
|
|
During 2014, Dominion repaid and repurchased $4 billion of long-term debt, including redemption premiums.
ISSUANCE OF COMMON STOCK AND
OTHER EQUITY SECURITIES
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 2014, Dominion began purchasing its common stock on the open market for these plans. In April 2014, Dominion began issuing
new common shares for these direct stock purchase plans.
During 2014, Dominion issued approximately 3.8 million shares of
common stock totaling $273 million through employee savings plans, direct stock purchase and dividend reinvestment plans, converted securities and other employee and director benefit plans. Dominion received cash proceeds of $205 million from
the issuance of 2.9 million of such shares through Dominion Direct and employee savings plans.
In December 2014, Dominion
filed an SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at-the-market program. See Note 19 to the Consolidated Financial Statements for a description of the at-the-market
program.
In June 2013 and July 2014, Dominion issued equity units, initially in the form of Corporate Units. Each
Corporate Unit consists of a stock purchase contract and 1/20 interest in a RSN issued by Dominion. The stock purchase contracts obligate the holders to purchase shares of Dominion common stock at a future settlement date. See Note 17 to
the Consolidated Financial Statements for a description of common stock to be issued by Dominion.
REPURCHASE
OF COMMON STOCK
Dominion did not repurchase any shares in 2014 and does not plan to
repurchase shares during 2015, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which does not count against its stock repurchase authorization.
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 believes that its current credit ratings provide sufficient access
to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion may affect its ability to access these funding sources or cause an increase in the return required by investors. Dominions
credit ratings affect its liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which it is able to offer its 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 are
affected by its financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.
In November 2014, Standard & Poors changed Dominions rating outlook to
negative from stable. Dominion cannot predict the potential impact the negative outlook at Standard & Poors could have on its cost of borrowing. Credit ratings as of February 23, 2015 follow:
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Fitch |
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Moodys |
|
|
Standard & Poors |
|
Senior unsecured debt securities |
|
|
BBB+ |
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|
|
Baa2 |
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|
|
BBB+ |
|
Junior subordinated debt securities |
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BBB- |
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|
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Baa3 |
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|
|
BBB |
|
Enhanced junior subordinated notes |
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|
BBB- |
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|
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Baa3 |
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|
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BBB |
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Commercial paper |
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|
F2 |
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|
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P-2 |
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|
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A-2 |
|
As of February 23, 2015, Fitch and Moodys maintained a stable outlook for their respective
ratings of Dominion and Standard & Poors maintained a negative outlook for its respective ratings of Dominion.
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 could result in an increase in the cost of borrowing. Dominion works closely with Fitch, Moodys and Standard & Poors with the objective of achieving its
targeted credit ratings. Dominion may find it necessary to modify its business plan 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 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.
Some of the typical covenants include:
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The timely payment of principal and interest; |
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Information requirements, including submitting financial reports filed with the SEC and information about changes in Dominions credit ratings to
lenders; |
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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; |
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Compliance with collateral minimums or requirements related to mortgage bonds; and |
Dominion is required to pay annual commitment fees to maintain its credit facilities. In addition, Dominions credit agreements contain various terms and conditions that could affect its ability to
borrow under these facilities. They include maximum debt to total capital ratios and cross-default provisions.
As of December 31, 2014, the calculated total debt to total capital ratio,
pursuant to the terms of the agreements, was as follows:
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Company |
|
Maximum Allowed Ratio |
|
|
Actual
Ratio(1) |
|
Dominion |
|
|
65 |
% |
|
|
59 |
% |
(1) |
Indebtedness as defined by the bank agreements excludes junior subordinated and remarketable subordinated notes reflected as long-term debt as well as AOCI reflected
as equity in the Consolidated Balance Sheets. |
If Dominion or any of its 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 facilities and the lenders could terminate their commitment to lend
funds to that company. Accordingly, any default by Virginia Power or Dominion Gas under the joint credit facilities with Dominion would affect the lenders commitment to Dominion.
Dominion executed RCCs in connection with its issuance of the following hybrid securities:
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September 2006 hybrids; and |
In October 2014, Dominion redeemed all of the June 2009 hybrids. The redemption was conducted in compliance with the RCC. See Note 17 to the Consolidated Financial Statements for additional information,
including terms of the RCCs.
At December 31, 2014, the termination dates and covered debt under the RCCs associated
with Dominions hybrids were as follows:
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Hybrid |
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RCC
Termination Date |
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|
Designated Covered
Debt Under RCC |
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June 2006 hybrids |
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6/30/2036 |
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September 2006 hybrids |
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September 2006 hybrids |
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9/30/2036 |
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|
|
June 2006 hybrids |
|
Dominion monitors these debt covenants on a regular basis in order to ensure that events of default will
not occur. As of December 31, 2014, there have been no events of default under or changes to Dominions debt covenants.
Dividend
Restrictions
Certain agreements associated with Dominions credit facilities contain restrictions on the ratio of debt to total
capitalization. These limitations did not restrict Dominions ability to pay dividends or receive dividends from its subsidiaries at December 31, 2014.
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 and equity units, initially in the form of corporate units, which information is incorporated herein by reference.
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
CONTRACTUAL OBLIGATIONS
Dominion is party to numerous contracts and arrangements obligating it 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 is a party as of December 31, 2014. For purchase obligations
and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely
differ from amounts presented below. The table excludes all amounts classified as current liabilities in the Consolidated Balance Sheets, other than current maturities of long-term debt, interest payable and certain derivative instruments. The
majority of Dominions current liabilities will be paid in cash in 2015.
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|
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2015 |
|
|
2016-
2017 |
|
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2018-
2019 |
|
|
2020 and
thereafter |
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Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt(1) |
|
$ |
861 |
|
|
$ |
2,756 |
|
|
$ |
3,900 |
|
|
$ |
15,683 |
|
|
$ |
23,200 |
|
Interest payments(2) |
|
|
1,081 |
|
|
|
1,914 |
|
|
|
1,603 |
|
|
|
13,147 |
|
|
|
17,745 |
|
Leases(3) |
|
|
63 |
|
|
|
106 |
|
|
|
79 |
|
|
|
79 |
|
|
|
327 |
|
Purchase obligations(4): |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased electric capacity for utility operations |
|
|
313 |
|
|
|
408 |
|
|
|
169 |
|
|
|
99 |
|
|
|
989 |
|
Fuel commitments for utility operations |
|
|
769 |
|
|
|
825 |
|
|
|
488 |
|
|
|
2,052 |
|
|
|
4,134 |
|
Fuel commitments for nonregulated operations |
|
|
148 |
|
|
|
105 |
|
|
|
105 |
|
|
|
117 |
|
|
|
475 |
|
Pipeline transportation and storage |
|
|
176 |
|
|
|
278 |
|
|
|
244 |
|
|
|
750 |
|
|
|
1,448 |
|
Energy commodity purchases for resale(5) |
|
|
24 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
26 |
|
Other(6) |
|
|
1,021 |
|
|
|
79 |
|
|
|
24 |
|
|
|
13 |
|
|
|
1,137 |
|
Other long-term liabilities(7): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial derivative-commodities(5) |
|
|
18 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
32 |
|
Other contractual
obligations(8) |
|
|
98 |
|
|
|
201 |
|
|
|
109 |
|
|
|
19 |
|
|
|
427 |
|
Total cash payments |
|
$ |
4,572 |
|
|
$ |
6,688 |
|
|
$ |
6,721 |
|
|
$ |
31,959 |
|
|
$ |
49,940 |
|
(1) |
Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders. At the option of holders, $510 million of
Dominions 5.25% senior notes due 2033 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015. As a result, at December 31, 2014, the notes were included in Securities due within one year in the
Consolidated Balance Sheets. |
(2) |
Includes interest payments over the terms of the debt and payments on related stock purchase contracts. Interest is calculated using the applicable interest rate or
forward interest rate curve at December 31, 2014 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 and stock purchase contract payments on junior subordinated notes or RSNs and equity units, initially in the form of Corporate Units. |
(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 net losses, 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, $79 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. |
PLANNED CAPITAL EXPENDITURES
Dominions planned capital expenditures are expected to total approximately $5.8 billion, $5.6 billion and $4.6 billion in 2015, 2016 and 2017, 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
construction of the Liquefaction Project and Dominions portion of the Atlantic Coast Pipeline project.
Dominion expects
to fund its capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the Board of
Directors.
See DVP, Dominion Generation and Dominion Energy-Properties in Item 1. Business for a discussion of
Dominions expansion plans.
These estimates are based on a capital expenditures plan reviewed and endorsed by
Dominions Board of Directors in late 2014 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. Dominion 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 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 is 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 $192 million, $182 million and $189 million of expenses (including depreciation) during 2014, 2013, and 2012 respectively, in connection with environmental protection and
monitoring activities and expects these expenses to be approximately $193 million and $188 million in 2015 and 2016, respectively. In addition, capital expenditures related to environmental controls were $101 million, $64 million, and $213 million
for 2014, 2013 and 2012, respectively. These expenditures are expected to be approximately $97 million and $60 million for 2015 and 2016, 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, delegated 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 the Companies 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 issued final attainment/nonattainment designations in January 2015. Until states develop their implementation plans, Dominion cannot determine whether or how facilities located in
areas designated nonattainment for the standard will be impacted, but does not expect such impacts 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 Dominion operates. Until the states have developed implementation plans for these standards, the impact on Dominions facilities that emit NOX and SO2 is uncertain. Additionally, the impact of permit limits for implementing NAAQS on Dominions facilities is uncertain
at this time.
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. In November 2014, the EPA issued a new proposal to tighten the ozone standard and expects to finalize the rule in October 2015. The EPA is not
expected to complete attainment designations for a new standard until 2017 and states will have until 2020 to develop plans to address the new standard. 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. However, if significant expenditures are required to implement additional controls, it could adversely affect Dominions results of operations and 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. Dominion anticipates that the emission reductions achieved through compliance with other CAA-required programs will generally address this rule.
The Clear Power Plan uses a set of measures for reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization
of natural gas combined cycle units, expanding renewable resources and increasing customer energy efficiency. The proposal would require states to meet state-by-state emission rate or intensity-based CO2 binding goals or limits. The EPA is expected to finalize the guidelines
by summer 2015. States will then be required to submit plans to the EPA by summer 2016 identifying how they will comply with the rule, with possible one- or two-year extensions. Dominions most recent integrated resources plan filed in August
2014 included an alternative scenario benchmarked on the proposed EPA rule, as a plausible compliance strategy, that includes additional coal unit retirements and additional low or zero-carbon resources. However, until the state plans are developed
and the EPA approves the plans, Dominion cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.
In June 2014, the EPA published proposed performance standards to address CO2 emissions from modified and reconstructed electric generating units. The
proposed standards would only apply to coal- and natural-gas fired boilers and natural gas-fired combined cycle units, constructed for the purpose of supplying more than one-third of their potential output to the grid and which are designed to sell
approximately 25 MW, that meet certain, specific conditions described in the CAA for being modified or reconstructed. Modifications undertaken for the primary purpose of installing pollution control technology will not be subject to the proposed
standards. Dominion currently cannot predict with certainty the direct or indirect financial impact on operations from these rule revisions, but believes the expenditures to comply with any new requirements could be material.
In January 2015, the EPA announced plans to reduce methane emissions from natural gas processing and transmission sources as part of its
Climate Action Plan. The plan would impose regulations to reduce methane from new sources, including compressor stations and is expected to be proposed in summer 2015 and finalized in 2016. The EPA will develop control technology guidelines to
reduce emissions of volatile organic compounds from existing sources in ozone nonattainment areas in the northeast Ozone Transport Region. Until these regulations and guidelines are finalized, Dominion is unable to predict future requirements or
estimate compliance costs.
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
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 must comply with applicable aspects of the CWA programs at its operating facilities.
In June 2013, the EPA issued a
proposed rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The proposed rule establishes updated standards for wastewater discharges at coal, oil, gas, and nuclear steam generating stations.
Affected facilities could be required to convert from wet to dry coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. The EPA is subject to
a consent decree requiring that it take final action on the proposed rule by September 30, 2015. Dominion currently cannot predict with certainty the direct or indirect financial impact on operations from these rule revisions, but believes the
expenditures to comply with any new requirements could be material.
Climate Change Legislation and Regulation
Some regions and states in which Dominion operates 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.
Dodd-Frank Act
The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The CEA, as amended by Title
VII of the Dodd- Frank Act, requires certain over-the counter derivatives, or swaps, to be cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed on a designated contract market or
swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, may elect the end-user exception to the CEAs clearing requirements. Dominion has elected to exempt its swaps
from the CEAs clearing requirements. The CFTC may continue to adopt final rules and implement provisions of the Dodd-Frank Act through its ongoing rulemaking process, including rules regarding margin requirements for non-cleared swaps. If, as
a result of the rulemaking process, Dominions derivative activities are not exempted from clearing, exchange trading or margin requirements, it could be subject to higher costs due to decreased market liquidity or increased margin payments. In
addition, Dominions swap dealer counterparties may attempt to pass-through additional trading costs in connection with the implementation of, and compliance with, Title VII of the Dodd-Frank Act. Due to the ongoing rulemaking process, Dominion
is currently unable to assess the potential impact of the Dodd-Frank Acts derivative-related provisions on its financial condition, results of operations or cash flows.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The matters discussed in this Item may contain forward-looking statements as described in the introductory paragraphs of Item 7.
MD&A. The readers attention is directed to those paragraphs
and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact the Companies.
MARKET RISK
SENSITIVE INSTRUMENTS AND RISK MANAGEMENT
The Companies
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 and Dominions and Dominion Gas natural gas procurement and marketing 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 and future issuances of debt. In addition, the
Companies 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 and Dominion Gas primarily
holds commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of natural gas and other energy-related products.
The repositioning of Dominions producer services business was completed in the first quarter of 2014. This, combined with Dominions sale of its electric retail energy marketing business, has
reduced Dominions commodity price risk exposure.
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 commodity-based financial derivative instruments would have resulted in an increase in fair value of approximately $101 million and $171 million as of December 31, 2014 and 2013,
respectively. The decline in sensitivity is largely due to decreased commodity derivative activity and lower commodity prices.
A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of Virginia
Powers commodity-based financial derivatives as of December 31, 2014 or 2013.
A hypothetical 10% unfavorable
change in commodity prices of Dominion Gas commodity-based financial derivative
instru-
ments would have resulted in an increase in fair value of approximately $2 million and a decrease in fair value of $14 million as of December 31, 2014 and 2013, respectively. The
decline in sensitivity is largely due to decreased commodity derivative activity.
The impact of a change in energy commodity
prices on the Companies 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
The Companies 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 the Companies, a hypothetical 10% increase in market interest rates would not have resulted in a material change in annual earnings at December 31, 2014 or 2013.
The Companies may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. As of
December 31, 2014, Dominion, Virginia Power and Dominion Gas had $4.1 billion, $1.5 billion and $250 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 $46 million, $25 million and $2 million, respectively, in the fair value of Dominions, Virginia Powers and Dominion Gas interest rate derivatives at
December 31, 2014. As of December 31, 2013, Dominion, Virginia Power and Dominion Gas had $1.1 billion, $600 million and $450 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 $20 million, $13 million and $8 million, respectively, in the fair value of Dominions, Virginia Powers and Dominion Gas interest
rate derivatives at December 31, 2013.
The impact of a change in interest rates on the Companies 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 $176
million and $163 million in 2014 and 2013, 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 2014 and 2013, Dominion recorded, in AOCI and
regulatory liabilities, a net increase in unrealized gains on these investments of $172 million and $417 million, respectively.
Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $77 million and
$52 million in 2014 and 2013, 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 2014 and 2013, Virginia Power recorded, in AOCI and
regulatory liabilities, a net increase in unrealized gains on these investments of $87 million and $193 million, respectively.
Dominion sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit
payments. Virginia Power and Dominion Gas employees participate in these plans. Aggregate actual returns for Dominions pension and other postretirement plan assets were $706 million in 2014 and $959 million in 2013, versus expected returns of
$610 million and $554 million, respectively. Aggregate actual returns for pension and other postretirement benefit plan assets for Dominion Gas employees represented by collective bargaining units were $157 million in 2014 and $214 million in 2013,
versus expected returns of $138 million and $125 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 net 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. 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 $15 million and $14 million as of December 31, 2014 and 2013, respectively, for pension benefits and $3 million as of
December 31, 2014 and 2013, for other postretirement benefits. A hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion Gas plan assets, for employees represented by collective bargaining units, would result in
an increase in net periodic cost of approximately $4 million and $3 million as of December 31, 2014 and 2013, respectively, for pension benefits and $1 million as of both December 31, 2014 and 2013, for other postretirement benefits.
Risk Management Policies
The Companies 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 and Dominion Gas. 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 the Companies December 31, 2014 provision for credit losses, management believes that it is unlikely that a material adverse effect on the Companies financial position, results of operations
or cash flows would occur as a result of counterparty nonperformance.
Item 8. Financial Statements and Supplementary Data
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Page Number |
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|
|
Dominion Resources, Inc. |
|
|
|
|
Report of Independent Registered Public Accounting Firm |
|
|
57 |
|
Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012 |
|
|
58 |
|
Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and
2012 |
|
|
59 |
|
Consolidated Balance Sheets at December 31, 2014 and 2013 |
|
|
60 |
|
Consolidated Statements of Equity at December 31, 2014, 2013 and 2012 and for the years then
ended |
|
|
62 |
|
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012 |
|
|
63 |
|
|
|
Virginia Electric and Power Company |
|
|
|
|
Report of Independent Registered Public Accounting Firm |
|
|
64 |
|
Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012 |
|
|
65 |
|
Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and
2012 |
|
|
66 |
|
Consolidated Balance Sheets at December 31, 2014 and 2013 |
|
|
67 |
|
Consolidated Statements of Common Shareholders Equity at December
31, 2014, 2013 and 2012 and for the years then ended |
|
|
69 |
|
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012 |
|
|
70 |
|
|
|
Dominion Gas Holdings, LLC |
|
|
|
|
Report of Independent Registered Public Accounting Firm |
|
|
71 |
|
Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012 |
|
|
72 |
|
Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and
2012 |
|
|
73 |
|
Consolidated Balance Sheets at December 31, 2014 and 2013 |
|
|
74 |
|
Consolidated Statements of Equity at December 31, 2014, 2013 and 2012 and for the years then
ended |
|
|
76 |
|
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012 |
|
|
77 |
|
|
|
Combined Notes to Consolidated Financial Statements |
|
|
78 |
|
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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period
ended December 31, 2014, 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, 2014, based on the criteria established in
Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2015 expressed an unqualified opinion on Dominions internal control
over financial reporting.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 2015
Dominion Resources, Inc.
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions, except per share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue |
|
$ |
12,436 |
|
|
$ |
13,120 |
|
|
$ |
12,835 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
3,400 |
|
|
|
3,885 |
|
|
|
3,645 |
|
Purchased electric capacity |
|
|
361 |
|
|
|
358 |
|
|
|
387 |
|
Purchased gas |
|
|
1,355 |
|
|
|
1,331 |
|
|
|
1,177 |
|
Other operations and maintenance |
|
|
2,765 |
|
|
|
2,459 |
|
|
|
3,091 |
|
Depreciation, depletion and amortization |
|
|
1,292 |
|
|
|
1,208 |
|
|
|
1,127 |
|
Other taxes |
|
|
542 |
|
|
|
563 |
|
|
|
550 |
|
Total operating expenses |
|
|
9,715 |
|
|
|
9,804 |
|
|
|
9,977 |
|
Income from operations |
|
|
2,721 |
|
|
|
3,316 |
|
|
|
2,858 |
|
Other income |
|
|
250 |
|
|
|
265 |
|
|
|
223 |
|
Interest and related charges |
|
|
1,193 |
|
|
|
877 |
|
|
|
816 |
|
Income from continuing operations including noncontrolling interests before income taxes |
|
|
1,778 |
|
|
|
2,704 |
|
|
|
2,265 |
|
Income tax expense |
|
|
452 |
|
|
|
892 |
|
|
|
811 |
|
Income from continuing operations including noncontrolling interests |
|
|
1,326 |
|
|
|
1,812 |
|
|
|
1,454 |
|
Loss from discontinued operations(1) |
|
|
|
|
|
|
(92 |
) |
|
|
(1,125 |
) |
Net income including noncontrolling interests |
|
|
1,326 |
|
|
|
1,720 |
|
|
|
329 |
|
Noncontrolling interests |
|
|
16 |
|
|
|
23 |
|
|
|
27 |
|
Net income attributable to Dominion |
|
|
1,310 |
|
|
|
1,697 |
|
|
|
302 |
|
Amounts attributable to Dominion: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations, net of tax |
|
|
1,310 |
|
|
|
1,789 |
|
|
|
1,427 |
|
Loss from discontinued operations, net of tax |
|
|
|
|
|
|
(92 |
) |
|
|
(1,125 |
) |
Net income attributable to Dominion |
|
|
1,310 |
|
|
|
1,697 |
|
|
|
302 |
|
Earnings Per Common Share-Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
2.25 |
|
|
$ |
3.09 |
|
|
$ |
2.49 |
|
Loss from discontinued operations |
|
|
|
|
|
|
(0.16 |
) |
|
|
(1.96 |
) |
Net income attributable to Dominion |
|
$ |
2.25 |
|
|
$ |
2.93 |
|
|
$ |
0.53 |
|
Earnings Per Common Share-Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
2.24 |
|
|
$ |
3.09 |
|
|
$ |
2.49 |
|
Loss from discontinued operations |
|
|
|
|
|
|
(0.16 |
) |
|
|
(1.96 |
) |
Net income attributable to Dominion |
|
$ |
2.24 |
|
|
$ |
2.93 |
|
|
$ |
0.53 |
|
Dividends declared per common share |
|
$ |
2.40 |
|
|
$ |
2.25 |
|
|
$ |
2.11 |
|
(1) |
Includes income tax benefit of $43 million and $692 million in 2013 and 2012, respectively. For 2012, includes impairment charges of $1.6 billion related to Brayton
Point and Kincaid. See Note 6 for additional information. |
The accompanying notes are an integral part of Dominions
Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Statements of Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income including noncontrolling interests |
|
$ |
1,326 |
|
|
$ |
1,720 |
|
|
$ |
329 |
|
Other comprehensive income (loss), net of taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred gains (losses) on derivatives-hedging activities, net of $(20), $161 and $5 tax |
|
|
17 |
|
|
|
(243 |
) |
|
|
(8 |
) |
Changes in unrealized net gains on investment securities, net of $(59), $(136) and $(68) tax |
|
|
128 |
|
|
|
203 |
|
|
|
108 |
|
Changes in net unrecognized pension and other postretirement benefit costs, net of $189, $(341) and $209 tax |
|
|
(305 |
) |
|
|
516 |
|
|
|
(330 |
) |
Amounts reclassified to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative (gains) losses-hedging activities, net of $(59), $(53) and $34 tax |
|
|
93 |
|
|
|
77 |
|
|
|
(60 |
) |
Net realized gains on investment securities, net of $33, $35 and $16 tax |
|
|
(54 |
) |
|
|
(55 |
) |
|
|
(25 |
) |
Net pension and other postretirement benefit costs, net of $(24), $(39) and $(32) tax |
|
|
33 |
|
|
|
55 |
|
|
|
48 |
|
Changes in other comprehensive income (loss) from equity method investees, net of $3, $ and
$ tax |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
Total other comprehensive income (loss) |
|
|
(92 |
) |
|
|
553 |
|
|
|
(267 |
) |
Comprehensive income including noncontrolling interests |
|
|
1,234 |
|
|
|
2,273 |
|
|
|
62 |
|
Comprehensive income attributable to noncontrolling interests |
|
|
16 |
|
|
|
23 |
|
|
|
27 |
|
Comprehensive income attributable to Dominion |
|
$ |
1,218 |
|
|
$ |
2,250 |
|
|
$ |
35 |
|
The accompanying notes are an integral part of Dominions Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
318 |
|
|
$ |
316 |
|
Customer receivables (less allowance for doubtful accounts of $34 and $25) |
|
|
1,514 |
|
|
|
1,695 |
|
Other receivables (less allowance for doubtful accounts of $3 and $4) |
|
|
119 |
|
|
|
141 |
|
Inventories: |
|
|
|
|
|
|
|
|
Materials and supplies |
|
|
923 |
|
|
|
689 |
|
Fossil fuel |
|
|
413 |
|
|
|
393 |
|
Gas stored |
|
|
74 |
|
|
|
94 |
|
Derivative assets |
|
|
536 |
|
|
|
687 |
|
Margin deposit assets |
|
|
287 |
|
|
|
620 |
|
Prepayments |
|
|
167 |
|
|
|
192 |
|
Deferred income taxes |
|
|
800 |
|
|
|
778 |
|
Regulatory assets |
|
|
347 |
|
|
|
217 |
|
Other |
|
|
117 |
|
|
|
118 |
|
Total current assets |
|
|
5,615 |
|
|
|
5,940 |
|
Investments |
|
|
|
|
|
|
|
|
Nuclear decommissioning trust funds |
|
|
4,196 |
|
|
|
3,903 |
|
Investment in equity method affiliates |
|
|
1,081 |
|
|
|
916 |
|
Other |
|
|
284 |
|
|
|
283 |
|
Total investments |
|
|
5,561 |
|
|
|
5,102 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
51,406 |
|
|
|
46,969 |
|
Accumulated depreciation, depletion and amortization |
|
|
(15,136 |
) |
|
|
(14,341 |
) |
Total property, plant and equipment, net |
|
|
36,270 |
|
|
|
32,628 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Goodwill |
|
|
3,044 |
|
|
|
3,086 |
|
Pension and other postretirement benefit assets |
|
|
956 |
|
|
|
942 |
|
Intangible assets, net |
|
|
570 |
|
|
|
560 |
|
Regulatory assets |
|
|
1,642 |
|
|
|
1,228 |
|
Other |
|
|
669 |
|
|
|
610 |
|
Total deferred charges and other assets |
|
|
6,881 |
|
|
|
6,426 |
|
Total assets |
|
$ |
54,327 |
|
|
$ |
50,096 |
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Securities due within one year |
|
$ |
1,375 |
|
|
$ |
1,519 |
|
Short-term debt |
|
|
2,775 |
|
|
|
1,927 |
|
Accounts payable |
|
|
952 |
|
|
|
1,168 |
|
Accrued interest, payroll and taxes |
|
|
566 |
|
|
|
609 |
|
Derivative liabilities |
|
|
591 |
|
|
|
828 |
|
Other |
|
|
939 |
|
|
|
943 |
|
Total current liabilities |
|
|
7,198 |
|
|
|
6,994 |
|
Long-Term Debt |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
18,348 |
|
|
|
16,877 |
|
Junior subordinated notes |
|
|
1,374 |
|
|
|
1,373 |
|
Remarketable subordinated notes |
|
|
2,083 |
|
|
|
1,080 |
|
Total long-term debt |
|
|
21,805 |
|
|
|
19,330 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes and investment tax credits |
|
|
7,444 |
|
|
|
7,114 |
|
Asset retirement obligations |
|
|
1,633 |
|
|
|
1,484 |
|
Pension and other postretirement benefit liabilities |
|
|
1,296 |
|
|
|
481 |
|
Regulatory liabilities |
|
|
1,991 |
|
|
|
2,001 |
|
Other |
|
|
1,003 |
|
|
|
793 |
|
Total deferred credits and other liabilities |
|
|
13,367 |
|
|
|
11,873 |
|
Total liabilities |
|
|
42,370 |
|
|
|
38,197 |
|
Commitments and Contingencies (see Note 22) |
|
|
|
|
|
|
|
|
Subsidiary Preferred Stock Not Subject To Mandatory Redemption |
|
|
|
|
|
|
257 |
|
Equity |
|
|
|
|
|
|
|
|
Common stock-no
par(1) |
|
|
5,876 |
|
|
|
5,783 |
|
Retained earnings |
|
|
6,095 |
|
|
|
6,183 |
|
Accumulated other comprehensive loss |
|
|
(416 |
) |
|
|
(324 |
) |
Total common shareholders equity |
|
|
11,555 |
|
|
|
11,642 |
|
Noncontrolling interests |
|
|
402 |
|
|
|
|
|
Total equity |
|
|
11,957 |
|
|
|
11,642 |
|
Total liabilities and equity |
|
$ |
54,327 |
|
|
$ |
50,096 |
|
(1) |
1 billion shares authorized; 585 million shares and 581 million shares outstanding at December 31, 2014 and 2013, 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, 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(1) |
|
|
1 |
|
|
|
41 |
|
|
|
(27 |
) |
|
|
|
|
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
14 |
|
Tax benefit from stock awards and stock options exercised |
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
10 |
|
Dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,225
|
)(2)
|
|
|
|
|
|
|
(1,225 |
) |
|
|
(11 |
) |
|
|
(1,236 |
) |
Other comprehensive loss, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(267 |
) |
|
|
(267 |
) |
|
|
|
|
|
|
(267 |
) |
December 31, 2012 |
|
|
576 |
|
|
|
5,493 |
|
|
|
162 |
|
|
|
5,790 |
|
|
|
(877 |
) |
|
|
10,568 |
|
|
|
57 |
|
|
|
10,625 |
|
Net income including noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,714 |
|
|
|
|
|
|
|
1,714 |
|
|
|
6 |
|
|
|
1,720 |
|
Issuance of stock-employee and direct stock purchase plans |
|
|
4 |
|
|
|
278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278 |
|
|
|
|
|
|
|
278 |
|
Stock awards (net of change in unearned compensation) |
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
12 |
|
Other stock
issuances(3) |
|
|
1 |
|
|
|
15 |
|
|
|
(8 |
) |
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
7 |
|
Present value of stock purchase contract payments related to RSNs(4) |
|
|
|
|
|
|
|
|
|
|
(154 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
(156 |
) |
|
|
|
|
|
|
(156 |
) |
Fairless lease
buyout(5) |
|
|
|
|
|
|
(15 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15 |
) |
|
|
(57 |
) |
|
|
(72 |
) |
Dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,319
|
)(2)
|
|
|
|
|
|
|
(1,319 |
) |
|
|
(6 |
) |
|
|
(1,325 |
) |
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
553 |
|
|
|
553 |
|
|
|
|
|
|
|
553 |
|
December 31, 2013 |
|
|
581 |
|
|
|
5,783 |
|
|
|
|
|
|
|
6,183 |
|
|
|
(324 |
) |
|
|
11,642 |
|
|
|
|
|
|
|
11,642 |
|
Net income including noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,323 |
|
|
|
|
|
|
|
1,323 |
|
|
|
3 |
|
|
|
1,326 |
|
Issuance of Dominion Midstream common units, net of offering costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
392 |
|
|
|
392 |
|
Issuance of stock-employee and direct stock purchase plans |
|
|
3 |
|
|
|
205 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
205 |
|
|
|
|
|
|
|
205 |
|
Stock awards (net of change in unearned compensation) |
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
14 |
|
Other stock
issuances(1) |
|
|
1 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
14 |
|
Present value of stock purchase contract payments related to RSNs(4) |
|
|
|
|
|
|
(143 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(143 |
) |
|
|
|
|
|
|
(143 |
) |
Dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,411 |
)(2) |
|
|
|
|
|
|
(1,411 |
) |
|
|
|
|
|
|
(1,411 |
) |
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(92 |
) |
|
|
(92 |
) |
|
|
|
|
|
|
(92 |
) |
Other |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
7 |
|
|
|
10 |
|
December 31, 2014 |
|
|
585 |
|
|
$ |
5,876 |
|
|
$ |
|
|
|
$ |
6,095 |
|
|
$ |
(416 |
) |
|
$ |
11,555 |
|
|
$ |
402 |
|
|
$ |
11,957 |
|
(1) |
Contains shares issued in excess of principal amounts related to converted securities. See Note 17 for further information on convertible securities.
|
(2) |
Includes subsidiary preferred dividends related to noncontrolling interests of $13 million, $17 million and $16 million in 2014 and 2013 and 2012, respectively.
|
(3) |
Primarily includes $28 million in shares issued in excess of principal amounts related to converted securities, net of reclassification from other paid-in capital.
See Note 17 for further information on convertible securities. |
(4) |
See Note 17 for further information. |
(5) |
See Note 15 for further information. |
The accompanying notes are an integral part of Dominions Consolidated Financial Statements
Dominion Resources, Inc.
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income including noncontrolling interests |
|
$ |
1,326 |
|
|
$ |
1,720 |
|
|
$ |
329 |
|
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of generation assets |
|
|
|
|
|
|
48 |
|
|
|
2,089 |
|
Net payments related to rate refunds |
|
|
|
|
|
|
(5 |
) |
|
|
(151 |
) |
Depreciation, depletion and amortization (including nuclear fuel) |
|
|
1,560 |
|
|
|
1,390 |
|
|
|
1,443 |
|
Deferred income taxes and investment tax credits |
|
|
449 |
|
|
|
737 |
|
|
|
246 |
|
Gains on the sale of assets and businesses |
|
|
(220 |
) |
|
|
(122 |
) |
|
|
(81 |
) |
Charges associated with North Anna and offshore wind legislation |
|
|
374 |
|
|
|
|
|
|
|
|
|
Charges associated with Liability Management Exercise |
|
|
284 |
|
|
|
|
|
|
|
|
|
Charges associated with proposed settlement for ash pond closure costs |
|
|
121 |
|
|
|
|
|
|
|
|
|
Other adjustments |
|
|
(113 |
) |
|
|
(129 |
) |
|
|
(164 |
) |
Changes in: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
131 |
|
|
|
(98 |
) |
|
|
292 |
|
Inventories |
|
|
(43 |
) |
|
|
(29 |
) |
|
|
33 |
|
Deferred fuel and purchased gas costs, net |
|
|
(180 |
) |
|
|
102 |
|
|
|
368 |
|
Prepayments |
|
|
24 |
|
|
|
123 |
|
|
|
(85 |
) |
Accounts payable |
|
|
(202 |
) |
|
|
50 |
|
|
|
(61 |
) |
Accrued interest, payroll and taxes |
|
|
(41 |
) |
|
|
(27 |
) |
|
|
(12 |
) |
Margin deposit assets and liabilities |
|
|
361 |
|
|
|
(414 |
) |
|
|
45 |
|
Other operating assets and liabilities |
|
|
(392 |
) |
|
|
87 |
|
|
|
(154 |
) |
Net cash provided by operating activities |
|
|
3,439 |
|
|
|
3,433 |
|
|
|
4,137 |
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Plant construction and other property additions (including nuclear fuel) |
|
|
(5,345 |
) |
|
|
(4,065 |
) |
|
|
(4,145 |
) |
Acquisition of solar development projects |
|
|
(206 |
) |
|
|
(39 |
) |
|
|
|
|
Proceeds from sales of securities |
|
|
1,235 |
|
|
|
1,476 |
|
|
|
1,356 |
|
Purchases of securities |
|
|
(1,241 |
) |
|
|
(1,493 |
) |
|
|
(1,392 |
) |
Proceeds from the sale of Brayton Point, Kincaid and equity method investment in Elwood |
|
|
|
|
|
|
465 |
|
|
|
|
|
Proceeds from the sale of electric retail energy marketing business |
|
|
187 |
|
|
|
|
|
|
|
|
|
Proceeds from Blue Racer |
|
|
85 |
|
|
|
160 |
|
|
|
115 |
|
Proceeds from assignments of Marcellus acreage |
|
|
60 |
|
|
|
18 |
|
|
|
|
|
Restricted cash equivalents |
|
|
8 |
|
|
|
25 |
|
|
|
108 |
|
Other |
|
|
36 |
|
|
|
(5 |
) |
|
|
118 |
|
Net cash used in investing activities |
|
|
(5,181 |
) |
|
|
(3,458 |
) |
|
|
(3,840 |
) |
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Issuance (repayment) of short-term debt, net |
|
|
848 |
|
|
|
(485 |
) |
|
|
598 |
|
Issuance of short-term notes |
|
|
400 |
|
|
|
400 |
|
|
|
400 |
|
Repayment of short-term notes |
|
|
(400 |
) |
|
|
(400 |
) |
|
|
|
|
Issuance of long-term debt |
|
|
6,085 |
|
|
|
4,135 |
|
|
|
1,500 |
|
Repayment and repurchase of long-term debt, including redemption premiums |
|
|
(3,993 |
) |
|
|
(1,245 |
) |
|
|
(1,675 |
) |
Repayment of junior subordinated notes |
|
|
|
|
|
|
(258 |
) |
|
|
|
|
Acquisition of Juniper noncontrolling interest in Fairless |
|
|
|
|
|
|
(923 |
) |
|
|
|
|
Net proceeds from issuance of Dominion Midstream common units |
|
|
392 |
|
|
|
|
|
|
|
|
|
Subsidiary preferred stock redemption |
|
|
(259 |
) |
|
|
|
|
|
|
|
|
Issuance of common stock |
|
|
205 |
|
|
|
278 |
|
|
|
265 |
|
Common dividend payments |
|
|
(1,398 |
) |
|
|
(1,302 |
) |
|
|
(1,209 |
) |
Subsidiary preferred dividend payments |
|
|
(11 |
) |
|
|
(17 |
) |
|
|
(16 |
) |
Other |
|
|
(125 |
) |
|
|
(90 |
) |
|
|
(14 |
) |
Net cash provided by (used in) financing activities |
|
|
1,744 |
|
|
|
93 |
|
|
|
(151 |
) |
Increase in cash and cash equivalents |
|
|
2 |
|
|
|
68 |
|
|
|
146 |
|
Cash and cash equivalents at beginning of year |
|
|
316 |
|
|
|
248 |
|
|
|
102 |
|
Cash and cash equivalents at end of year |
|
$ |
318 |
|
|
$ |
316 |
|
|
$ |
248 |
|
Supplemental Cash Flow Information |
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid (received) during the year for: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest and related charges, excluding capitalized amounts |
|
$ |
889 |
|
|
$ |
852 |
|
|
$ |
913 |
|
Income taxes |
|
|
72 |
|
|
|
56 |
|
|
|
(58 |
) |
Significant noncash investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accrued capital expenditures |
|
|
315 |
|
|
|
375 |
|
|
|
388 |
|
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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in
conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 2015
Virginia Electric and Power Company
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue(1) |
|
$ |
7,579 |
|
|
$ |
7,295 |
|
|
$ |
7,226 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases(1) |
|
|
2,406 |
|
|
|
2,304 |
|
|
|
2,368 |
|
Purchased electric capacity |
|
|
360 |
|
|
|
358 |
|
|
|
386 |
|
Other operations and maintenance: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliated suppliers |
|
|
286 |
|
|
|
290 |
|
|
|
305 |
|
Other |
|
|
1,630 |
|
|
|
1,161 |
|
|
|
1,161 |
|
Depreciation and amortization |
|
|
915 |
|
|
|
853 |
|
|
|
782 |
|
Other taxes |
|
|
258 |
|
|
|
249 |
|
|
|
232 |
|
Total operating expenses |
|
|
5,855 |
|
|
|
5,215 |
|
|
|
5,234 |
|
Income from operations |
|
|
1,724 |
|
|
|
2,080 |
|
|
|
1,992 |
|
Other income |
|
|
93 |
|
|
|
86 |
|
|
|
96 |
|
Interest and related charges |
|
|
411 |
|
|
|
369 |
|
|
|
385 |
|
Income from operations before income tax expense |
|
|
1,406 |
|
|
|
1,797 |
|
|
|
1,703 |
|
Income tax expense |
|
|
548 |
|
|
|
659 |
|
|
|
653 |
|
Net Income |
|
|
858 |
|
|
|
1,138 |
|
|
|
1,050 |
|
Preferred dividends(2) |
|
|
13 |
|
|
|
17 |
|
|
|
16 |
|
Balance available for common stock |
|
$ |
845 |
|
|
$ |
1,121 |
|
|
$ |
1,034 |
|
(1) |
See Note 24 for amounts attributable to affiliates. |
(2) |
Includes $2 million associated with the write-off of issuance expenses related to the redemption of Virginia Powers preferred stock in 2014. See Note 18 for
additional information. |
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, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
858 |
|
|
$ |
1,138 |
|
|
$ |
1,050 |
|
Other comprehensive income (loss), net of taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred gains (losses) on derivatives-hedging activities, net of $2, $(3) and $3 tax |
|
|
(4 |
) |
|
|
6 |
|
|
|
(5 |
) |
Changes in unrealized net gains on nuclear decommissioning trust funds, net of $(9), $(13) and $(7) tax |
|
|
15 |
|
|
|
20 |
|
|
|
13 |
|
Amounts reclassified to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative (gains) losses-hedging activities, net of $2, $ and $(2) tax |
|
|
(3 |
) |
|
|
|
|
|
|
2 |
|
Net realized gains on nuclear decommissioning trust funds, net of $4, $2 and $2 tax |
|
|
(6 |
) |
|
|
(3 |
) |
|
|
(4 |
) |
Other comprehensive income |
|
|
2 |
|
|
|
23 |
|
|
|
6 |
|
Comprehensive income |
|
$ |
860 |
|
|
$ |
1,161 |
|
|
$ |
1,056 |
|
The accompanying notes are an integral part of Virginia Powers Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
15 |
|
|
$ |
16 |
|
Customer receivables (less allowance for doubtful accounts of $25 and $11) |
|
|
986 |
|
|
|
946 |
|
Other receivables (less allowance for doubtful accounts of $1 and $2) |
|
|
65 |
|
|
|
78 |
|
Inventories (average cost method): |
|
|
|
|
|
|
|
|
Materials and supplies |
|
|
455 |
|
|
|
418 |
|
Fossil fuel |
|
|
398 |
|
|
|
390 |
|
Prepayments |
|
|
252 |
|
|
|
32 |
|
Regulatory assets |
|
|
298 |
|
|
|
128 |
|
Deferred income taxes |
|
|
6 |
|
|
|
87 |
|
Other(1) |
|
|
76 |
|
|
|
68 |
|
Total current assets |
|
|
2,551 |
|
|
|
2,163 |
|
Investments |
|
|
|
|
|
|
|
|
Nuclear decommissioning trust funds |
|
|
1,930 |
|
|
|
1,765 |
|
Other |
|
|
4 |
|
|
|
12 |
|
Total investments |
|
|
1,934 |
|
|
|
1,777 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
35,180 |
|
|
|
32,848 |
|
Accumulated depreciation and amortization |
|
|
(11,080 |
) |
|
|
(10,580 |
) |
Total property, plant and equipment, net |
|
|
24,100 |
|
|
|
22,268 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Intangible assets, net |
|
|
205 |
|
|
|
193 |
|
Regulatory assets |
|
|
439 |
|
|
|
417 |
|
Other(1) |
|
|
280 |
|
|
|
143 |
|
Total deferred charges and other assets |
|
|
924 |
|
|
|
753 |
|
Total assets |
|
$ |
29,509 |
|
|
$ |
26,961 |
|
(1) See Note 24 for amounts attributable to affiliates.
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Securities due within one year |
|
$ |
211 |
|
|
$ |
58 |
|
Short-term debt |
|
|
1,361 |
|
|
|
842 |
|
Accounts payable |
|
|
458 |
|
|
|
479 |
|
Payables to affiliates |
|
|
92 |
|
|
|
69 |
|
Affiliated current borrowings |
|
|
427 |
|
|
|
97 |
|
Accrued interest, payroll and taxes |
|
|
199 |
|
|
|
218 |
|
Derivative liabilities |
|
|
60 |
|
|
|
12 |
|
Customer deposits |
|
|
107 |
|
|
|
95 |
|
Regulatory liabilities |
|
|
90 |
|
|
|
41 |
|
Other |
|
|
271 |
|
|
|
306 |
|
Total current liabilities |
|
|
3,276 |
|
|
|
2,217 |
|
Long-Term Debt |
|
|
8,726 |
|
|
|
7,974 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes and investment tax credits |
|
|
4,415 |
|
|
|
4,137 |
|
Asset retirement obligations |
|
|
848 |
|
|
|
689 |
|
Regulatory liabilities |
|
|
1,683 |
|
|
|
1,597 |
|
Pension and other postretirement benefit liabilities(1) |
|
|
219 |
|
|
|
147 |
|
Other |
|
|
287 |
|
|
|
145 |
|
Total deferred credits and other liabilities |
|
|
7,452 |
|
|
|
6,715 |
|
Total liabilities |
|
|
19,454 |
|
|
|
16,906 |
|
Commitments and Contingencies (see Note 22) |
|
|
|
|
|
|
|
|
Preferred Stock Not Subject to Mandatory Redemption |
|
|
|
|
|
|
257 |
|
Common Shareholders Equity |
|
|
|
|
|
|
|
|
Common stock-no
par(2) |
|
|
5,738 |
|
|
|
5,738 |
|
Other paid-in capital |
|
|
1,113 |
|
|
|
1,113 |
|
Retained earnings |
|
|
3,154 |
|
|
|
2,899 |
|
Accumulated other comprehensive income |
|
|
50 |
|
|
|
48 |
|
Total common shareholders equity |
|
|
10,055 |
|
|
|
9,798 |
|
Total liabilities and shareholders equity |
|
$ |
29,509 |
|
|
$ |
26,961 |
|
(1) |
See Note 24 for amounts attributable to affiliates. |
(2) |
500,000 shares authorized at December 31, 2014 and 2013; 274,723 shares outstanding at December 31, 2014 and 2013. |
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 |
|
|
Total |
|
|
|
Shares |
|
|
Amount |
|
|
|
|
|
(millions, except for shares) |
|
(thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,138 |
|
|
|
|
|
|
|
1,138 |
|
Dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(596 |
) |
|
|
|
|
|
|
(596 |
) |
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23 |
|
|
|
23 |
|
Balance at December 31, 2013 |
|
|
275 |
|
|
|
5,738 |
|
|
|
1,113 |
|
|
|
2,899 |
|
|
|
48 |
|
|
|
9,798 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
858 |
|
|
|
|
|
|
|
858 |
|
Dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(603 |
) |
|
|
|
|
|
|
(603 |
) |
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
Balance at December 31, 2014 |
|
|
275 |
|
|
$ |
5,738 |
|
|
$ |
1,113 |
|
|
$ |
3,154 |
|
|
$ |
50 |
|
|
$ |
10,055 |
|
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, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
858 |
|
|
$ |
1,138 |
|
|
$ |
1,050 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization (including nuclear fuel) |
|
|
1,090 |
|
|
|
1,016 |
|
|
|
927 |
|
Deferred income taxes and investment tax credits, net |
|
|
396 |
|
|
|
240 |
|
|
|
502 |
|
Charges associated with North Anna and offshore wind legislation |
|
|
374 |
|
|
|
|
|
|
|
|
|
Charges associated with proposed settlement for ash pond closure costs |
|
|
121 |
|
|
|
|
|
|
|
|
|
Net payments related to rate refunds |
|
|
|
|
|
|
(5 |
) |
|
|
(151 |
) |
Other adjustments |
|
|
(35 |
) |
|
|
(63 |
) |
|
|
(70 |
) |
Changes in: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(27 |
) |
|
|
(124 |
) |
|
|
126 |
|
Affiliated accounts receivable and payable |
|
|
23 |
|
|
|
3 |
|
|
|
(2 |
) |
Inventories |
|
|
(45 |
) |
|
|
(19 |
) |
|
|
8 |
|
Deferred fuel expenses, net |
|
|
(191 |
) |
|
|
93 |
|
|
|
378 |
|
Prepayments |
|
|
(220 |
) |
|
|
(9 |
) |
|
|
18 |
|
Accounts payable |
|
|
5 |
|
|
|
15 |
|
|
|
19 |
|
Accrued interest, payroll and taxes |
|
|
(19 |
) |
|
|
14 |
|
|
|
(22 |
) |
Other operating assets and liabilities |
|
|
(82 |
) |
|
|
30 |
|
|
|
(77 |
) |
Net cash provided by operating activities |
|
|
2,248 |
|
|
|
2,329 |
|
|
|
2,706 |
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Plant construction and other property additions |
|
|
(2,911 |
) |
|
|
(2,394 |
) |
|
|
(2,082 |
) |
Purchases of nuclear fuel |
|
|
(196 |
) |
|
|
(139 |
) |
|
|
(206 |
) |
Purchases of securities |
|
|
(574 |
) |
|
|
(603 |
) |
|
|
(638 |
) |
Proceeds from sales of securities |
|
|
549 |
|
|
|
572 |
|
|
|
626 |
|
Other |
|
|
(2 |
) |
|
|
(37 |
) |
|
|
18 |
|
Net cash used in investing activities |
|
|
(3,134 |
) |
|
|
(2,601 |
) |
|
|
(2,282 |
) |
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Issuance (repayment) of short-term debt, net |
|
|
519 |
|
|
|
(151 |
) |
|
|
98 |
|
Issuance (repayment) of affiliated current borrowings, net |
|
|
330 |
|
|
|
(338 |
) |
|
|
248 |
|
Issuance of long-term debt |
|
|
950 |
|
|
|
1,835 |
|
|
|
450 |
|
Repayment of long-term debt |
|
|
(61 |
) |
|
|
(470 |
) |
|
|
(641 |
) |
Preferred stock redemption |
|
|
(259 |
) |
|
|
|
|
|
|
|
|
Common dividend payments |
|
|
(590 |
) |
|
|
(579 |
) |
|
|
(559 |
) |
Preferred dividend payments |
|
|
(11 |
) |
|
|
(17 |
) |
|
|
(16 |
) |
Other |
|
|
7 |
|
|
|
(20 |
) |
|
|
(5 |
) |
Net cash provided by (used in) financing activities |
|
|
885 |
|
|
|
260 |
|
|
|
(425 |
) |
Decrease in cash and cash equivalents |
|
|
(1 |
) |
|
|
(12 |
) |
|
|
(1 |
) |
Cash and cash equivalents at beginning of year |
|
|
16 |
|
|
|
28 |
|
|
|
29 |
|
Cash and cash equivalents at end of year |
|
$ |
15 |
|
|
$ |
16 |
|
|
$ |
28 |
|
Supplemental Cash Flow Information |
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest and related charges, excluding capitalized amounts |
|
$ |
383 |
|
|
$ |
328 |
|
|
$ |
376 |
|
Income taxes |
|
|
386 |
|
|
|
427 |
|
|
|
225 |
|
Significant noncash investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accrued capital expenditures |
|
|
181 |
|
|
|
276 |
|
|
|
242 |
|
The accompanying notes are an integral part of Virginia Powers Consolidated Financial Statements.
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Dominion Gas Holdings, LLC
Richmond, Virginia
We have audited the
accompanying consolidated balance sheets of Dominion Gas Holdings, LLC (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (Dominion Gas) as of December 31, 2014 and 2013, 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, 2014. These financial statements are the responsibility of Dominion Gas 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. Dominion
Gas 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 Dominion Gas 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 Dominion Gas Holdings, LLC and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 2015
Dominion Gas Holdings, LLC
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue(1) |
|
$ |
1,898 |
|
|
$ |
1,937 |
|
|
$ |
1,677 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
gas(1) |
|
|
315 |
|
|
|
323 |
|
|
|
235 |
|
Other energy-related purchases |
|
|
40 |
|
|
|
93 |
|
|
|
41 |
|
Other operations and maintenance: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliated suppliers |
|
|
64 |
|
|
|
70 |
|
|
|
112 |
|
Other(2) |
|
|
274 |
|
|
|
353 |
|
|
|
223 |
|
Depreciation and amortization |
|
|
197 |
|
|
|
188 |
|
|
|
176 |
|
Other taxes |
|
|
157 |
|
|
|
148 |
|
|
|
140 |
|
Total operating expenses |
|
|
1,047 |
|
|
|
1,175 |
|
|
|
927 |
|
Income from operations |
|
|
851 |
|
|
|
762 |
|
|
|
750 |
|
Other income |
|
|
22 |
|
|
|
28 |
|
|
|
37 |
|
Interest and related charges(1) |
|
|
27 |
|
|
|
28 |
|
|
|
40 |
|
Income from operations before income tax expense |
|
|
846 |
|
|
|
762 |
|
|
|
747 |
|
Income tax expense |
|
|
334 |
|
|
|
301 |
|
|
|
288 |
|
Net Income |
|
$ |
512 |
|
|
$ |
461 |
|
|
$ |
459 |
|
(1) |
See Note 24 for amounts attributable to related parties. |
(2) |
Includes gains on the sales of assets to related parties of $59 million, $122 million and $176 million in 2014, 2013 and 2012, respectively. See Note 9 for more
information. |
The accompanying notes are an integral part of Dominion Gas Consolidated Financial Statements.
Dominion Gas Holdings, LLC
Consolidated Statements of Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
512 |
|
|
$ |
461 |
|
|
$ |
459 |
|
Other comprehensive income (loss), net of taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred gains (losses) on derivatives-hedging activities, net of $19, $(27) and $(10) tax |
|
|
(31 |
) |
|
|
39 |
|
|
|
13 |
|
Changes in unrecognized pension and other postretirement benefit costs, net of $6, $(18) and $5 tax |
|
|
(10 |
) |
|
|
26 |
|
|
|
(7 |
) |
Amounts reclassified to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative losses-hedging activities, net of $(5), $(5) and $(13) tax |
|
|
8 |
|
|
|
11 |
|
|
|
20 |
|
Net pension and other postretirement benefit costs, net of $(3), $(4) and $(4) tax |
|
|
5 |
|
|
|
6 |
|
|
|
5 |
|
Other comprehensive income (loss) |
|
|
(28 |
) |
|
|
82 |
|
|
|
31 |
|
Comprehensive income |
|
$ |
484 |
|
|
$ |
543 |
|
|
$ |
490 |
|
The accompanying notes are an integral part of Dominion Gas Consolidated Financial Statements.
Dominion Gas Holdings, LLC
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
9 |
|
|
$ |
8 |
|
Customer receivables (less allowance for doubtful accounts of $4 and $5)(1) |
|
|
322 |
|
|
|
311 |
|
Other receivables (less allowance for doubtful accounts of $1 at both dates) |
|
|
19 |
|
|
|
2 |
|
Affiliated receivables |
|
|
12 |
|
|
|
41 |
|
Inventories: |
|
|
|
|
|
|
|
|
Materials and supplies |
|
|
53 |
|
|
|
56 |
|
Gas stored |
|
|
12 |
|
|
|
7 |
|
Prepayments |
|
|
166 |
|
|
|
67 |
|
Regulatory assets |
|
|
38 |
|
|
|
79 |
|
Deferred income taxes |
|
|
96 |
|
|
|
89 |
|
Other(1) |
|
|
83 |
|
|
|
141 |
|
Total current assets |
|
|
810 |
|
|
|
801 |
|
Investments |
|
|
108 |
|
|
|
106 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
8,902 |
|
|
|
8,240 |
|
Accumulated depreciation and amortization |
|
|
(2,538 |
) |
|
|
(2,421 |
) |
Total property, plant and equipment, net |
|
|
6,364 |
|
|
|
5,819 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Goodwill |
|
|
542 |
|
|
|
545 |
|
Intangible assets, net |
|
|
79 |
|
|
|
82 |
|
Regulatory assets |
|
|
379 |
|
|
|
285 |
|
Pension and other postretirement benefit assets(1) |
|
|
1,486 |
|
|
|
1,436 |
|
Other(1) |
|
|
80 |
|
|
|
68 |
|
Total deferred charges and other assets |
|
|
2,566 |
|
|
|
2,416 |
|
Total assets |
|
$ |
9,848 |
|
|
$ |
9,142 |
|
(1) See Note 24 for amounts attributable to related parties.
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
247 |
|
|
$ |
277 |
|
Payables to affiliates |
|
|
41 |
|
|
|
45 |
|
Affiliated current borrowings |
|
|
384 |
|
|
|
1,342 |
|
Accrued interest, payroll and taxes |
|
|
194 |
|
|
|
209 |
|
Regulatory liabilities |
|
|
75 |
|
|
|
79 |
|
Other(1) |
|
|
97 |
|
|
|
118 |
|
Total current liabilities |
|
|
1,038 |
|
|
|
2,070 |
|
Long-Term Debt |
|
|
2,594 |
|
|
|
1,198 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes and investment tax credits |
|
|
2,158 |
|
|
|
1,977 |
|
Regulatory liabilities |
|
|
192 |
|
|
|
203 |
|
Other(1) |
|
|
300 |
|
|
|
267 |
|
Total deferred credits and other liabilities |
|
|
2,650 |
|
|
|
2,447 |
|
Total liabilities |
|
|
6,282 |
|
|
|
5,715 |
|
Commitments and Contingencies (see Note 22) |
|
|
|
|
|
|
|
|
Equity |
|
|
|
|
|
|
|
|
Membership interests |
|
|
3,652 |
|
|
|
3,485 |
|
Accumulated other comprehensive loss |
|
|
(86 |
) |
|
|
(58 |
) |
Total equity |
|
|
3,566 |
|
|
|
3,427 |
|
Total liabilities and equity |
|
$ |
9,848 |
|
|
$ |
9,142 |
|
(1) |
See Note 24 for amounts attributable to related parties. |
The accompanying notes are an integral part of Dominion Gas Consolidated Financial Statements.
Dominion Gas Holdings, LLC
Consolidated Statements of Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Membership Interests |
|
|
Accumulated Other Comprehensive Income (Loss) |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2011 |
|
$ |
3,167 |
|
|
$ |
(171 |
) |
|
$ |
2,996 |
|
Net income |
|
|
459 |
|
|
|
|
|
|
|
459 |
|
Distributions |
|
|
(210 |
) |
|
|
|
|
|
|
(210 |
) |
Other comprehensive income, net of tax |
|
|
|
|
|
|
31 |
|
|
|
31 |
|
Balance at December 31, 2012 |
|
|
3,416 |
|
|
|
(140 |
) |
|
|
3,276 |
|
Net income |
|
|
461 |
|
|
|
|
|
|
|
461 |
|
Equity contribution from parent |
|
|
6 |
|
|
|
|
|
|
|
6 |
|
Distributions |
|
|
(398 |
) |
|
|
|
|
|
|
(398 |
) |
Other comprehensive income, net of tax |
|
|
|
|
|
|
82 |
|
|
|
82 |
|
Balance at December 31, 2013 |
|
|
3,485 |
|
|
|
(58 |
) |
|
|
3,427 |
|
Net income |
|
|
512 |
|
|
|
|
|
|
|
512 |
|
Equity contribution from parent |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Distributions |
|
|
(346 |
) |
|
|
|
|
|
|
(346 |
) |
Other comprehensive loss, net of tax |
|
|
|
|
|
|
(28 |
) |
|
|
(28 |
) |
Balance at December 31, 2014 |
|
$ |
3,652 |
|
|
$ |
(86 |
) |
|
$ |
3,566 |
|
The accompanying notes are an integral part of Dominion Gas Consolidated Financial Statements.
Dominion Gas Holdings, LLC
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
512 |
|
|
$ |
461 |
|
|
$ |
459 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Gains on sales of assets |
|
|
(124 |
) |
|
|
(122 |
) |
|
|
(176 |
) |
Depreciation and amortization |
|
|
197 |
|
|
|
188 |
|
|
|
176 |
|
Deferred income taxes and investment tax credits, net |
|
|
216 |
|
|
|
102 |
|
|
|
294 |
|
Other adjustments |
|
|
2 |
|
|
|
(3 |
) |
|
|
2 |
|
Changes in: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(42 |
) |
|
|
(17 |
) |
|
|
63 |
|
Affiliated receivables |
|
|
(1 |
) |
|
|
2 |
|
|
|
(3 |
) |
Inventories |
|
|
(2 |
) |
|
|
|
|
|
|
5 |
|
Prepayments |
|
|
(99 |
) |
|
|
13 |
|
|
|
(9 |
) |
Accounts payable |
|
|
(35 |
) |
|
|
62 |
|
|
|
(52 |
) |
Payables to affiliates |
|
|
(4 |
) |
|
|
8 |
|
|
|
(12 |
) |
Accrued interest, payroll and taxes |
|
|
(15 |
) |
|
|
48 |
|
|
|
(43 |
) |
Other operating assets and liabilities |
|
|
(134 |
) |
|
|
(44 |
) |
|
|
(75 |
) |
Net cash provided by operating activities |
|
|
471 |
|
|
|
698 |
|
|
|
629 |
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Plant construction and other property additions |
|
|
(719 |
) |
|
|
(650 |
) |
|
|
(928 |
) |
Proceeds from sale of assets to an affiliate |
|
|
47 |
|
|
|
113 |
|
|
|
|
|
Proceeds from Blue Racer |
|
|
1 |
|
|
|
78 |
|
|
|
|
|
Proceeds from assignments of Marcellus acreage |
|
|
60 |
|
|
|
18 |
|
|
|
|
|
Advances to affiliate, net |
|
|
|
|
|
|
(5 |
) |
|
|
(14 |
) |
Other |
|
|
(5 |
) |
|
|
(14 |
) |
|
|
(10 |
) |
Net cash used in investing activities |
|
|
(616 |
) |
|
|
(460 |
) |
|
|
(952 |
) |
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Issuance (repayment) of affiliated current borrowings, net |
|
|
(892 |
) |
|
|
(545 |
) |
|
|
549 |
|
Repayment and acquisition of affiliated long-term debt |
|
|
|
|
|
|
(569 |
) |
|
|
(10 |
) |
Issuance of long-term debt |
|
|
1,400 |
|
|
|
1,200 |
|
|
|
|
|
Distribution payments |
|
|
(346 |
) |
|
|
(318 |
) |
|
|
(210 |
) |
Other |
|
|
(16 |
) |
|
|
(10 |
) |
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
146 |
|
|
|
(242 |
) |
|
|
329 |
|
Increase (decrease) in cash and cash equivalents |
|
|
1 |
|
|
|
(4 |
) |
|
|
6 |
|
Cash and cash equivalents at beginning of year |
|
|
8 |
|
|
|
12 |
|
|
|
6 |
|
Cash and cash equivalents at end of year |
|
$ |
9 |
|
|
$ |
8 |
|
|
$ |
12 |
|
Supplemental Cash Flow Information |
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest and related charges, excluding capitalized amounts |
|
$ |
23 |
|
|
$ |
31 |
|
|
$ |
43 |
|
Income taxes |
|
|
266 |
|
|
|
148 |
|
|
|
67 |
|
Significant noncash investing and financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accrued capital expenditures |
|
|
35 |
|
|
|
42 |
|
|
|
62 |
|
Extinguishment of affiliated long-term debt in exchange for assets sold to affiliate |
|
|
67 |
|
|
|
|
|
|
|
187 |
|
Distribution of non-cash asset (account receivable) to parent |
|
|
|
|
|
|
80 |
|
|
|
|
|
Proceeds from sale of assets to affiliate not yet received |
|
|
|
|
|
|
30 |
|
|
|
61 |
|
Conversion of affiliated current borrowings to membership interests |
|
|
|
|
|
|
|
|
|
|
61 |
|
The accompanying notes are an integral part of Dominion Gas 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 and Dominion Gas. Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and
northeastern North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Powers stock is owned by Dominion. Dominion Gas is a
holding company that conducts business activities through a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution
operations in Ohio, and gas gathering and processing activities primarily in West Virginia, Ohio and Pennsylvania. All of Dominion Gas membership interests are held by Dominion.
Dominions operations also include an LNG import, transport and storage facility in Maryland, a preferred equity interest in which
was contributed to Dominion Midstream in 2014, an equity investment in Atlantic Coast Pipeline and regulated gas transportation and distribution operations in West Virginia. Dominions nonregulated operations include merchant generation, energy
marketing and price risk management activities, retail energy marketing operations and an equity investment in Blue Racer.
In October 2014, Dominion Midstream launched its initial public offering of 20,125,000 common units representing limited partner
interests at a price of $21 per unit, which included an over-allotment option to purchase an additional 2,625,000 common units at the initial offering price, which was exercised in full by the underwriters. Dominion received $392 million in net
proceeds from the sale of the units, after deducting underwriting discounts, structuring fees and estimated offering expenses. Dominion owns the general partner and 68.5% of the limited partner interests in Dominion Midstream, which owns a preferred
equity interest and the general partner interest in Cove Point. The publics ownership interest in Dominion Midstream is reflected as non-controlling interest in Dominions Consolidated Financial Statements.
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 discontinued, which is discussed in Note 3 and Note 25. 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.
Dominion Gas manages its daily operations through one primary operating segment: Dominion
Energy. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segments performance
and the effect of certain items recorded at Dominion Gas as a result of the recognition of Dominions basis in the net assets contributed.
See Note 25 for further discussion of the Companies operating segments.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
General
The Companies 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.
The Companies Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of
their respective majority-owned subsidiaries.
The Companies 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 and Dominion Gas participate in certain of these plans. See Note 21 for further information on these plans.
Certain amounts in the 2013 and 2012 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2014 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 and/or Dominion Gas, 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. Dominion and Virginia Power collect sales,
consumption and consumer utility taxes and Dominion Gas collects sales taxes; however, these amounts are excluded from revenue. Dominions customer receivables at December 31, 2014 and 2013 included $564 million and $555 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, 2014 and 2013 included
$407 million and $395 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. Dominion Gas customer receivables at December 31, 2014 and 2013
included $127 million and $106 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas 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- and FERC-regulated 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; |
|
|
Gas transportation and storage
consists primarily of regulated sales of gathering, transmission, distribution and storage services. 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. |
The primary types of sales and service activities reported as operating revenue for Dominion Gas are as follows:
|
|
Regulated gas sales consist primarily
of state- and FERC-regulated 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 and sales of gas purchased from third parties. 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. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers;
|
|
|
NGL revenue consists primarily of
sales of NGL production and condensate, extracted products and associated derivative activity; and |
|
|
Other revenue consists primarily of
miscellaneous service revenue, gas processing and handling revenue and gathering revenue. |
Electric Fuel, Purchased Energy and
Purchased Gas-Deferred Costs
Where permitted by regulatory authorities, the differences between Dominions and Virginia Powers
actual electric fuel and purchased energy expenses and Dominions and Dominion Gas
purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of
current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.
Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 84% is currently subject to deferred fuel accounting, while substantially all of the
remaining amount is subject to recovery through similar mechanisms.
Virtually all of Dominion Gas, Cove Points and
Hopes natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale.
Income Taxes
A consolidated federal income tax
return is filed for Dominion and its subsidiaries, including Virginia Power and Dominion Gas subsidiaries. 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.
Although Dominion Gas is disregarded for income tax purposes, a provision for
income taxes is recognized to reflect the inclusion of its business activities in the tax returns of its parent, Dominion. Virginia Power and Dominion Gas participate in intercompany tax sharing agreements with Dominion and its subsidiaries, and
current income taxes are based on taxable income or loss, determined on a separate company basis.
Under the agreements, if a
subsidiary incurs a net operating loss, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or to the extent the net operating loss is absorbed by the taxable
income of other Dominion consolidated group members. Otherwise, the net operating loss is carried forward and is recognized as a deferred tax asset until realized.
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. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income
tax returns. 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. 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.
The Companies 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
Combined Notes to Consolidated Financial Statements, Continued
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. Except when such
amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, 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.
The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income, respectively.
Penalties are also recognized in other income.
Dominions, Virginia Powers and Dominion Gas interest and
penalties were immaterial in 2014, 2013 and 2012.
At December 31, 2014, Virginia Powers Consolidated Balance Sheet
included $225 million of federal and state income taxes receivable, $13 million of noncurrent state income taxes receivable and $38 million of noncurrent federal and state income taxes payable.
At December 31, 2013, Virginia Powers Consolidated Balance Sheet included $3 million of state income taxes receivable, $22 million
of federal and state income taxes payable, $12 million of noncurrent state income taxes receivable and $28 million of noncurrent federal and state income taxes payable.
At December 31, 2014, Dominion Gas Consolidated Balance Sheet included $96 million of federal and state income taxes receivable, $14 million of state income taxes payable, $7 million of noncurrent
state income taxes payable and $20 million noncurrent state income taxes receivable.
At December 31, 2013, Dominion Gas
Consolidated Balance Sheet included $17 million of federal income taxes payable, $23 million of state income taxes payable, $1 million of state income taxes receivable, $7 million of noncurrent state income taxes payable and $20 million noncurrent
state income taxes receivable.
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. The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies:
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
Dominion |
|
$ |
42 |
|
|
$ |
38 |
|
Virginia Power |
|
|
20 |
|
|
|
21 |
|
Dominion Gas |
|
|
9 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
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. Dominion Gas uses derivative instruments such as physical and financial forwards, futures and swaps to manage commodity price and interest rate risks.
All derivatives, except those for which an exception applies, are required to be 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.
The Companies 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 $287 million and $620 million associated with cash collateral at December 31, 2014 and 2013, respectively. Dominion had margin liabilities of $34 million and $2 million associated with cash collateral at December 31, 2014 and
2013, respectively. Virginia Power had margin assets of $6 million and $11 million associated with cash collateral at December 31, 2014 and 2013, respectively. Virginia Power did not have any margin liabilities associated with cash collateral
at December 31, 2014 or 2013. Dominion Gas did not have any margin assets or liabilities related to cash collateral at December 31, 2014 or 2013. See Note 7 for further information about derivatives.
To manage price risk, Dominion and Virginia Power hold certain derivative instruments that are not designated as hedges for accounting
purposes. However, to the extent Dominion and Virginia Power 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 formerly managed a portfolio of commodity-based financial derivative instruments held for trading purposes. Dominion used established
policies and procedures to manage the risks associated with price fluctuations in these energy commodities and used various derivative instruments to reduce risk by creating offsetting market positions. In the second quarter of 2013, Dominion
commenced a repositioning of its producer services business. The repositioning was completed in the first quarter of 2014 and resulted in the termination of natural gas trading and certain energy marketing activities.
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
The Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for
accounting purposes. For all derivatives designated as hedges, the Companies 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 hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing
basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or
losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such
changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges. 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 the Companies hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas, NGLs 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 the Companies 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.
Dominion entered into interest rate derivative instruments to hedge its forecasted interest payments
related to planned debt issuances in 2013 and 2014. These interest rate derivatives were designated by Dominion as cash flow hedges in 2012 and 2013, prior to the formation of Dominion Gas. For the purposes of the Dominion Gas financial statements,
the derivative balances, AOCI balance, and any income statement impact related to these
interest rate derivative instruments entered into by Dominion have been, and will continue to be, included in the Dominion Gas Consolidated Financial Statements as the forecasted interest
payments related to the debt issuances will now occur at Dominion Gas.
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 is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, 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 generally charged to expense as it is incurred.
In 2014, 2013 and 2012, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $80 million, $66 million and $91
million, respectively. In 2014, 2013 and 2012, Virginia Power capitalized AFUDC to property, plant and equipment of $39 million, $33 million and $31 million, respectively. In 2014, 2013 and 2012, Dominion Gas capitalized AFUDC to property, plant and
equipment of $1 million, $5 million and $23 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 2014, 2013 and 2012, Virginia Power
recorded $8 million, $32 million and $37 million of AFUDC related to these projects, respectively.
For property subject to
cost-of-service rate regulation, including Virginia Power electric distribution, electric transmission, and generation property, Dominion Gas natural gas distribution and transmission 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 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 abandoned.
For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not
asso-
Combined Notes to Consolidated Financial Statements, Continued
ciated 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. The Companies average composite depreciation rates on utility property, plant and equipment are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(percent) |
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
Generation |
|
|
2.66 |
|
|
|
2.71 |
|
|
|
2.62 |
|
Transmission |
|
|
2.38 |
|
|
|
2.36 |
|
|
|
2.17 |
|
Distribution |
|
|
3.12 |
|
|
|
3.13 |
|
|
|
3.17 |
|
Storage |
|
|
2.39 |
|
|
|
2.43 |
|
|
|
2.59 |
|
Gas gathering and processing |
|
|
2.81 |
|
|
|
2.39 |
|
|
|
2.49 |
|
General and other |
|
|
3.62 |
|
|
|
3.82 |
|
|
|
4.55 |
|
|
|
|
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
Generation |
|
|
2.66 |
|
|
|
2.71 |
|
|
|
2.62 |
|
Transmission |
|
|
2.34 |
|
|
|
2.28 |
|
|
|
1.98 |
|
Distribution |
|
|
3.34 |
|
|
|
3.33 |
|
|
|
3.32 |
|
General and other |
|
|
3.29 |
|
|
|
3.51 |
|
|
|
4.32 |
|
|
|
|
|
Dominion Gas |
|
|
|
|
|
|
|
|
|
|
|
|
Transmission |
|
|
2.40 |
|
|
|
2.43 |
|
|
|
2.35 |
|
Distribution |
|
|
2.47 |
|
|
|
2.50 |
|
|
|
2.66 |
|
Storage |
|
|
2.40 |
|
|
|
2.43 |
|
|
|
2.58 |
|
Gas gathering and processing |
|
|
2.82 |
|
|
|
2.39 |
|
|
|
2.50 |
|
General and other |
|
|
5.77 |
|
|
|
5.93 |
|
|
|
6.09 |
|
In 2013, Virginia Power revised its depreciation rates to reflect the results of a new depreciation study.
This change resulted in an increase of $19 million ($12 million after-tax) in depreciation and amortization expense in Virginia Powers Consolidated Statements of Income.
In 2014, Virginia Power also made a one-time adjustment to depreciation expense as ordered by the Virginia Commission. This adjustment resulted in an increase of $38 million ($23 million after-tax)
in depreciation and amortization expense in Virginia Powers Consolidated Statements of Income.
In 2013, Dominion Gas
revised the depreciation rates for East Ohio to reflect the results of a new depreciation study. This change resulted in a decrease of $8 million ($5 million after-tax) in depreciation and amortization expense in Dominion Gas Consolidated
Statements of Income.
Dominions nonutility property, plant and equipment is depreciated using the straight-line method
over the following estimated useful lives:
|
|
|
|
|
Asset |
|
Estimated Useful Lives |
|
Merchant generation-nuclear |
|
|
44 years |
|
Merchant generation-other |
|
|
15 - 36 years |
|
General and other |
|
|
5 - 59 years |
|
Depreciation and amortization related to Virginia Powers and Dominion Gas nonutility property,
plant and equipment and E&P properties was immaterial for the years ended December 31, 2014, 2013 and 2012.
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.
Long-Lived and Intangible Assets
The
Companies 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 and Dominion Gas 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, legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. 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
The Companies 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. At least annually, the Companies evaluate the key assumptions underlying their AROs including estimates of the amounts and timing of future cash flows associated with retirement activities. AROs are adjusted when
significant changes in these assumptions are identified. Dominion and Dominion Gas report accretion of AROs and depreciation on asset retirement costs associated with their 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 and depreciation on asset retirement costs associated with decommissioning its nuclear
power stations as an adjustment to the regulatory liability for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs is reported in other
operations and maintenance expense and depreciation expense in the Consolidated Statements of Income.
Debt Issuance Costs
The Companies 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. Deferred debt issuance costs are recorded as an asset and classified in other current assets and other deferred charges and other assets in the Consolidated Balance Sheets.
Unamortized costs associated with redemptions of debt securities prior to stated maturity dates are generally recognized and recorded in interest expense immediately. 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
The Companies 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 the Companies 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. The Companies 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. |
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, Dominion and Virginia Power record the credit loss in earnings and any remaining portion of the unrealized loss in AOCI. 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 |
Combined Notes to Consolidated Financial Statements, Continued
|
|
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 Dominion and
Virginia Power 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 for Dominion Gas used in East Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at
$12 million and $7 million at December 31, 2014 and December 31, 2013, respectively. Based on the average price of gas purchased during 2014 and 2013, the cost of replacing the current portion of stored gas inventory exceeded the
amount stated on a LIFO basis by approximately $98 million and $77 million, respectively. Stored gas inventory for Dominion 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 and Dominion Gas value 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 and Dominion Gas from other parties are reported in
other current assets and imbalances that Dominion and Dominion Gas owe to other parties are reported in other current liabilities in the Consolidated Balance Sheets.
Goodwill
Dominion and Dominion Gas evaluate 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. ACQUISITIONS AND DISPOSITIONS
DOMINION
ACQUISITION OF SOLAR DEVELOPMENT PROJECTS
In March 2014, Dominion acquired 100% of the equity interests of six solar development projects in California from Recurrent Energy Development Holdings,
LLC for approximately $50 million in cash. The projects cost approximately $446 million to construct, including the initial acquisition cost. The facilities, which began commercial operations in the fourth quarter of 2014, generate approximately 139
MW.
In November 2014, Dominion acquired 100% of the equity interests of a solar project in California from CSI Project Holdco,
LLC for approximately $79 million in cash. The project costs approximately $80 million to construct, including the initial acquisition cost. The facility, which began commercial operations in the
fourth quarter of 2014, generates approximately 20 MW.
In December 2014, Dominion acquired 100% of the equity interests of a
solar project in California from EDF Renewable Development, Inc. for approximately $71 million in cash. The project is expected to cost approximately $73 million to construct, including the initial acquisition cost. The facility, which began
commercial operations in January 2015, generates approximately 20 MW.
The purchase price for each of these acquisitions was
allocated to Property, Plant and Equipment.
In September 2014, Dominion entered into agreements to acquire 100% of the equity
interests in two additional solar projects in California from EDF Renewable Development, Inc. for approximately $175 million in cash. The acquisitions are expected to close in the first half of 2015 prior to the projects commencing operations. The
projects are expected to cost approximately $185 million once constructed, including the initial acquisition cost. Upon completion, the facilities are expected to generate approximately 42 MW.
These acquisitions provide Dominion with a large utility-scale solar presence and significantly increase its solar generation portfolio.
Long-term power purchase, interconnection and operation and maintenance agreements have been executed for the projects. Dominion has claimed or expects to claim federal investment tax credits on the projects.
ACQUISITION OF CGT
In January 2015, Dominion completed the acquisition of 100% of the equity interests of CGT from SCANA Corporation for approximately $495 million in cash, subject to final acquired working capital
adjustments. CGT owns and operates nearly 1,500 miles of FERC-regulated interstate natural gas pipeline in South Carolina and southeastern Georgia. This acquisition supports Dominions natural gas expansion into the Southeast. The acquired
assets of CGT will be included in the Dominion Energy operating segment. Subject to board approvals by Dominion and Dominion Midstream, Dominion expects to contribute CGT into Dominion Midstream for a combination of debt and Dominion Midstream
common units during the first half of 2015. The allocation of the purchase price to individual assets is under evaluation by management and has not been finalized.
SALE OF ELECTRIC RETAIL ENERGY MARKETING BUSINESS
In March 2014, Dominion completed the sale of its electric retail energy marketing business. The proceeds were approximately $187 million, net of
transaction costs. The sale resulted in a gain, subject to post-closing adjustments, of approximately $100 million ($57 million after-tax) net of a $31 million write-off of goodwill, and is included in other operations and maintenance expense in
Dominions Consolidated Statements of Income. The sale of the electric retail energy marketing business did not qualify for discontinued operations classification.
SALE OF ILLINOIS GAS CONTRACTS
In June 2013, Dominion completed the sale of Illinois Gas Contracts. The sales price was approximately $32 million, subject to post-closing adjustments. The sale resulted in a gain of
approx-
imately $29 million ($18 million after-tax) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in Dominions Consolidated Statement of
Income. The sale of Illinois Gas Contracts did not qualify for discontinued operations classification as it is not considered a component under applicable accounting guidance.
SALE OF BRAYTON POINT, KINCAID AND EQUITY METHOD INVESTMENT
IN ELWOOD
In March 2013, Dominion entered into an agreement with Energy Capital Partners to sell Brayton
Point, Kincaid, and its equity method investment in Elwood.
In the first and second quarters of 2013, Brayton Points and
Kincaids assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell, resulting in impairment charges totaling $48 million ($28 million after-tax), which are included in
discontinued operations in Dominions Consolidated Statements of Income. In both periods, Dominion used the market approach to estimate the fair value of Brayton Points and Kincaids long-lived assets. These were considered Level 2
fair value measurements given that they were based on the agreed-upon sales price.
Dominions 50% interest in Elwood was
an equity method investment and therefore, in accordance with applicable accounting guidance, the carrying amount of this investment was not classified as held for sale nor were the equity earnings from this investment reported as discontinued
operations.
In August 2013, Dominion completed the sale and received proceeds of approximately $465 million, net of
transaction costs. The sale resulted in a $35 million ($25 million after-tax) gain attributable to its equity method investment in Elwood, which is included in other income in Dominions Consolidated Statement of Income, which was partially
offset by a $17 million ($18 million after-tax) loss attributable to Brayton Point and Kincaid, which includes a $16 million write-off of goodwill and is reflected in loss from discontinued operations in Dominions Consolidated Statement of
Income. See Note 6 for other impairments related to these power stations.
The following table presents selected information
regarding the results of operations of Brayton Point and Kincaid, which are reported as discontinued operations in Dominions Consolidated Statements of Income:
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
Operating revenue |
|
$ |
304 |
|
|
$ |
258 |
|
Loss before income taxes |
|
|
(135 |
)(1) |
|
|
(1,768 |
)(2) |
(1) |
Includes $64 million of charges related to the defeasance of Brayton Point debt and the early redemption of Kincaid debt in 2013. |
(2) |
Includes a long-lived asset impairment charge of $1.6 billion. |
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. Also 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 reported as discontinued operations in Dominions Consolidated Statements of Income:
|
|
|
|
|
Year Ended December 31, |
|
2012 |
|
(millions) |
|
|
|
Operating revenue |
|
$ |
57 |
|
Loss before income taxes |
|
|
(49 |
) |
Dominion and Dominion Gas
BLUE RACER
See Note 9 for a discussion of transactions
related to Blue Racer.
MARCELLUS ACREAGE
See Note 10 for a discussion of assignments of Marcellus acreage.
NOTE 4. OPERATING REVENUE
The Companies operating revenue consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
Electric sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
|
$ |
7,460 |
|
|
$ |
7,193 |
|
|
$ |
7,102 |
|
Nonregulated |
|
|
1,839 |
|
|
|
2,511 |
|
|
|
2,483 |
|
Gas sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
|
|
334 |
|
|
|
323 |
|
|
|
250 |
|
Nonregulated |
|
|
751 |
|
|
|
930 |
|
|
|
1,071 |
|
Gas transportation and storage |
|
|
1,543 |
|
|
|
1,535 |
|
|
|
1,401 |
|
Other |
|
|
509 |
|
|
|
628 |
|
|
|
528 |
|
Total operating revenue |
|
$ |
12,436 |
|
|
$ |
13,120 |
|
|
$ |
12,835 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated electric sales |
|
$ |
7,460 |
|
|
$ |
7,193 |
|
|
$ |
7,102 |
|
Other |
|
|
119 |
|
|
|
102 |
|
|
|
124 |
|
Total operating revenue |
|
$ |
7,579 |
|
|
$ |
7,295 |
|
|
$ |
7,226 |
|
Dominion Gas |
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
|
$ |
209 |
|
|
$ |
202 |
|
|
$ |
138 |
|
Nonregulated |
|
|
26 |
|
|
|
32 |
|
|
|
28 |
|
Gas transportation and storage |
|
|
1,353 |
|
|
|
1,338 |
|
|
|
1,188 |
|
NGL revenue |
|
|
212 |
|
|
|
292 |
|
|
|
275 |
|
Other |
|
|
98 |
|
|
|
73 |
|
|
|
48 |
|
Total operating revenue |
|
$ |
1,898 |
|
|
$ |
1,937 |
|
|
$ |
1,677 |
|
Combined Notes to Consolidated Financial Statements, Continued
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. The Companies are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may
result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.
In December 2014, U.S. federal legislation was enacted that provides an extension of the 50% bonus depreciation allowance for qualifying capital expenditures incurred through 2014.
Continuing Operations
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion
|
|
|
Virginia Power |
|
|
Dominion
Gas |
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
(11 |
) |
|
$ |
317 |
|
|
$ |
43 |
|
|
$ |
85 |
|
|
$ |
357 |
|
|
$ |
70 |
|
|
$ |
86 |
|
|
$ |
158 |
|
|
$ |
(8 |
) |
State |
|
|
14 |
|
|
|
110 |
|
|
|
84 |
|
|
|
67 |
|
|
|
62 |
|
|
|
81 |
|
|
|
32 |
|
|
|
41 |
|
|
|
2 |
|
Total current expense (benefit) |
|
|
3 |
|
|
|
427 |
|
|
|
127 |
|
|
|
152 |
|
|
|
419 |
|
|
|
151 |
|
|
|
118 |
|
|
|
199 |
|
|
|
(6 |
) |
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes before operating loss carryforwards and investment tax credits |
|
|
956 |
|
|
|
563 |
|
|
|
645 |
|
|
|
381 |
|
|
|
224 |
|
|
|
482 |
|
|
|
192 |
|
|
|
92 |
|
|
|
257 |
|
Tax benefit of operating loss carryforwards |
|
|
(352 |
) |
|
|
(18 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment tax credits |
|
|
(152 |
) |
|
|
(48 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State |
|
|
(2 |
) |
|
|
(31 |
) |
|
|
40 |
|
|
|
16 |
|
|
|
17 |
|
|
|
21 |
|
|
|
24 |
|
|
|
10 |
|
|
|
37 |
|
Total deferred expense |
|
|
450 |
|
|
|
466 |
|
|
|
685 |
|
|
|
397 |
|
|
|
241 |
|
|
|
503 |
|
|
|
216 |
|
|
|
102 |
|
|
|
294 |
|
Amortization of deferred investment tax credits |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
$ |
452 |
|
|
$ |
892 |
|
|
$ |
811 |
|
|
$ |
548 |
|
|
$ |
659 |
|
|
$ |
653 |
|
|
$ |
334 |
|
|
$ |
301 |
|
|
$ |
288 |
|
For continuing
operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies effective income tax rate as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
Virginia Power |
|
|
Dominion Gas |
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
U.S. statutory rate |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
Increases (reductions) resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State taxes, net of federal benefit |
|
|
|
|
|
|
2.1 |
|
|
|
4.2 |
|
|
|
3.8 |
|
|
|
3.1 |
|
|
|
3.9 |
|
|
|
4.4 |
|
|
|
4.3 |
|
|
|
3.4 |
|
Investment tax credits |
|
|
(8.6 |
) |
|
|
(1.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production tax credits |
|
|
(1.2 |
) |
|
|
(0.6 |
) |
|
|
(0.5 |
) |
|
|
(0.6 |
) |
|
|
(0.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valuation allowances |
|
|
0.7 |
|
|
|
(0.1 |
) |
|
|
(0.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AFUDC - equity |
|
|
|
|
|
|
(0.6 |
) |
|
|
(0.9 |
) |
|
|
|
|
|
|
(0.8 |
) |
|
|
(0.9 |
) |
|
|
|
|
|
|
(0.1 |
) |
|
|
(0.6 |
) |
Employee stock ownership plan deduction |
|
|
(0.9 |
) |
|
|
(0.6 |
) |
|
|
(0.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other, net |
|
|
0.4 |
|
|
|
(0.4 |
) |
|
|
(0.6 |
) |
|
|
0.8 |
|
|
|
(0.4 |
) |
|
|
0.3 |
|
|
|
0.1 |
|
|
|
0.3 |
|
|
|
0.7 |
|
Effective tax rate |
|
|
25.4 |
% |
|
|
33.0 |
% |
|
|
35.8 |
% |
|
|
39.0 |
% |
|
|
36.7 |
% |
|
|
38.3 |
% |
|
|
39.5 |
% |
|
|
39.5 |
% |
|
|
38.5 |
% |
Dominions effective tax rate in 2014 reflects the recognition of state tax credits and previously unrecognized tax
benefits due to the expiration of statutes of limitations.
The Companies deferred income taxes consist of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
Virginia Power |
|
|
Dominion Gas |
|
At December 31, |
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets |
|
$ |
2,023 |
|
|
$ |
2,142 |
|
|
$ |
500 |
|
|
$ |
462 |
|
|
$ |
227 |
|
|
$ |
216 |
|
Total deferred income tax liabilities |
|
|
8,663 |
|
|
|
8,463 |
|
|
|
4,915 |
|
|
|
4,498 |
|
|
|
2,289 |
|
|
|
2,103 |
|
Total net deferred income tax liabilities |
|
$ |
6,640 |
|
|
$ |
6,321 |
|
|
$ |
4,415 |
|
|
$ |
4,036 |
|
|
$ |
2,062 |
|
|
$ |
1,887 |
|
Total deferred income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant and equipment, primarily depreciation method and basis differences |
|
$ |
5,895 |
|
|
$ |
5,383 |
|
|
$ |
3,965 |
|
|
$ |
3,628 |
|
|
$ |
1,417 |
|
|
$ |
1,266 |
|
Nuclear decommissioning |
|
|
1,241 |
|
|
|
1,136 |
|
|
|
474 |
|
|
|
441 |
|
|
|
|
|
|
|
|
|
Deferred state income taxes |
|
|
659 |
|
|
|
606 |
|
|
|
299 |
|
|
|
285 |
|
|
|
207 |
|
|
|
182 |
|
Federal benefit of deferred state income taxes |
|
|
(231 |
) |
|
|
(212 |
) |
|
|
(105 |
) |
|
|
(100 |
) |
|
|
(72 |
) |
|
|
(64 |
) |
Deferred fuel, purchased energy and gas costs |
|
|
27 |
|
|
|
(33 |
) |
|
|
18 |
|
|
|
(50 |
) |
|
|
7 |
|
|
|
13 |
|
Pension benefits |
|
|
272 |
|
|
|
435 |
|
|
|
(77 |
) |
|
|
(52 |
) |
|
|
567 |
|
|
|
522 |
|
Other postretirement benefits |
|
|
(17 |
) |
|
|
(78 |
) |
|
|
13 |
|
|
|
(3 |
) |
|
|
(12 |
) |
|
|
(13 |
) |
Loss and credit carryforwards |
|
|
(1,434 |
) |
|
|
(797 |
) |
|
|
(116 |
) |
|
|
(106 |
) |
|
|
(10 |
) |
|
|
(10 |
) |
Valuation allowances |
|
|
87 |
|
|
|
69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partnership basis differences |
|
|
304 |
|
|
|
125 |
|
|
|
|
|
|
|
|
|
|
|
42 |
|
|
|
42 |
|
Other |
|
|
(163 |
) |
|
|
(313 |
) |
|
|
(56 |
) |
|
|
(7 |
) |
|
|
(84 |
) |
|
|
(51 |
) |
Total net deferred income tax liabilities |
|
$ |
6,640 |
|
|
$ |
6,321 |
|
|
$ |
4,415 |
|
|
$ |
4,036 |
|
|
$ |
2,062 |
|
|
$ |
1,887 |
|
At December 31, 2014, Dominion had the following deductible loss and credit carryforwards:
|
|
|
Federal loss carryforwards of $2.2 billion that expire if unutilized during the period 2021 through 2034; |
|
|
|
Federal investment tax credits of $245 million that expire if unutilized during the period 2033 through 2034; |
|
|
|
Federal production and other tax credits of $65 million that expire if unutilized during the period 2031 through 2034; |
|
|
|
State loss carryforwards of $1.7 billion that expire if unutilized during the period 2018 through 2034. A valuation allowance on $962 million of these
carryforwards has been established; |
|
|
|
State minimum tax credits of $194 million that do not expire; and |
|
|
|
State investment tax credits of $29 million that expire if unutilized during the period 2016 through 2019. |
At December 31, 2014, Virginia Power had the following deductible loss and credit carryforwards:
|
|
|
Federal loss carryforwards of $279 million that expire if unutilized during the period 2031 through 2033; and |
|
|
|
Federal production and other tax credits of $14 million that expire if unutilized during the period 2031 through 2034.
|
At December 31, 2014, Dominion Gas had the following deductible loss
carryforwards:
|
|
|
Federal loss carryforwards of $25 million that expire if unutilized during the period 2031 through 2033; and |
|
|
|
State loss carryforwards of $4 million that expire if unutilized during the period 2031 through 2032. |
Dominion Gas had no credit carryforwards at December 31, 2014.
A reconciliation of changes in the Companies unrecognized tax benefits follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
Virginia Power |
|
|
Dominion Gas |
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1 |
|
$ |
222 |
|
|
$ |
293 |
|
|
$ |
347 |
|
|
$ |
39 |
|
|
$ |
57 |
|
|
$ |
114 |
|
|
$ |
29 |
|
|
$ |
30 |
|
|
$ |
30 |
|
Increases-prior period positions |
|
|
24 |
|
|
|
17 |
|
|
|
28 |
|
|
|
2 |
|
|
|
12 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Decreases-prior period positions |
|
|
(26 |
) |
|
|
(99 |
) |
|
|
(106 |
) |
|
|
(16 |
) |
|
|
(42 |
) |
|
|
(80 |
) |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
Increases-current period positions |
|
|
16 |
|
|
|
30 |
|
|
|
43 |
|
|
|
11 |
|
|
|
14 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Decreases-current period positions |
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlements with tax authorities |
|
|
|
|
|
|
(2 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
(2 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Expiration of statutes of limitations |
|
|
(91 |
) |
|
|
(12 |
) |
|
|
(15 |
) |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31 |
|
$ |
145 |
|
|
$ |
222 |
|
|
$ |
293 |
|
|
$ |
36 |
|
|
$ |
39 |
|
|
$ |
57 |
|
|
$ |
29 |
|
|
$ |
29 |
|
|
$ |
30 |
|
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax
rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. For Dominion and its subsidiaries, these unrecognized tax
benefits were $77 million, $126 million and $167 million at December 31, 2014, 2013 and 2012, respectively. For Dominion, the change in these unrecognized tax benefits decreased income tax expense by $47 million and $29 million in 2014 and
2013, respectively, and increased income tax expense by $1 million in 2012. For Virginia Power, these unrecognized tax benefits were $8 million at December 31, 2014 and 2013, and $13 million at December 31, 2012. For Virginia Power, the
change in these unrecognized tax benefits decreased income tax expense by less than $1 million in 2014, and increased income tax expense by $4 million and $1 million in 2013 and 2012, respectively. For Dominion Gas, these unrecognized tax benefits
were $19 million at December 31, 2014 and 2013 and $20 million at December 31, 2012. For Dominion Gas, the change in these unrecognized tax benefits affected income tax expense by less than $1 million in 2014, 2013 and 2012.
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 one that was subsequently settled in 2012.
Combined Notes to Consolidated Financial Statements, Continued
The IRS examination of tax years 2008, 2009, 2010 and 2011 concluded in late 2013,
resulting in a payment of $46 million, and an adjustment to a refund previously received by Dominion for its carryback of 2008 losses to 2007. The loss carryback, as adjusted, was submitted to the Joint Committee for review. Early in 2014, Dominion
received notification that the matter had been resolved with no further adjustments. Accordingly, the earliest tax year remaining open for examination of Dominions federal tax returns is 2012.
Effective for its 2014 tax year, Dominion has been accepted into the CAP. The CAP is a method of identifying and resolving tax issues
through open, cooperative, and transparent interaction between the IRS and taxpayers prior to the filing of a return. Through the CAP, Dominion will have the opportunity to resolve complex tax matters with the IRS before filing its federal income
tax returns, thus achieving certainty for such tax return filing positions accepted by the IRS. Under a Pre-CAP plan, the IRS audit of tax years 2012 and 2013 began in early 2014.
It is reasonably possible that settlement negotiations and expiration of statutes of limitations could result in a decrease in
unrecognized tax benefits in 2015 by up to $30 million for Dominion and up to $25 million for Virginia Power. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could
increase by up to $10 million for Dominion and $7 million for Virginia Power.
Otherwise, with regard to 2014 and prior years,
Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2015.
After considering the possibility of potential changes in the status of its remaining unrecognized tax benefits, Dominion Gas has concluded that no significant changes are reasonably possible to occur in
2015.
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(1) |
|
|
2010 |
|
Connecticut |
|
|
2011 |
|
Virginia(2) |
|
|
2011 |
|
West Virginia(1) |
|
|
2011 |
|
New
York(1) |
|
|
2007 |
|
(1) |
Considered a major state for Dominion Gas operations. |
(2) |
Considered a major state for Virginia Powers operations. |
The Companies 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
Details of income tax expense for Dominions discontinued operations were as follows:
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
Federal |
|
$ |
(274 |
) |
|
$ |
(248 |
) |
State |
|
|
(41 |
) |
|
|
(6 |
) |
Total current benefit |
|
|
(315 |
) |
|
|
(254 |
) |
Deferred: |
|
|
|
|
|
|
|
|
Federal |
|
|
232 |
|
|
|
(368 |
) |
State |
|
|
40 |
|
|
|
(70 |
) |
Total deferred expense (benefit) |
|
|
272 |
|
|
|
(438 |
) |
Total income tax benefit |
|
$ |
(43 |
) |
|
$ |
(692 |
) |
Dominions effective tax rate for 2013 reflects the impact of goodwill written off in the sale of Kincaid and Brayton
Point that is not deductible for tax purposes.
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 the Companies 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. Dominion Gas applies fair value measurements to certain assets and liabilities
including commodity and interest rate derivative instruments and investments held in 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, 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 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 certain statistical methods, including regression analysis, that reflect their market assumptions.
The Companies commodity derivative valuations are prepared by Dominions ERM department. The ERM department reports directly to
Dominions CFO. The ERM department creates daily mark-to-market valuations for the Companies derivative transactions using computer-based statistical models. 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 warehouse databases. The majority of forward prices are automatically uploaded into the data warehouse databases 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 mark-to-market valuations. During this meeting, the
changes in mark-to-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, Dominion and Virginia Power 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. Dominion and Virginia Power 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, Dominion and Virginia Power 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:
|
|
|
Forward commodity prices |
|
|
|
Forward foreign currency prices |
|
|
|
Credit quality of counterparties and the Companies |
For interest rate derivative contracts:
|
|
|
Credit quality of counterparties and the Companies |
For investments:
|
|
|
Quoted securities prices and indices |
|
|
|
Securities trading information including volume and restrictions |
|
|
|
NAV (for alternative investments and common/collective trust funds) |
The Companies 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:
|
|
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 certain exchange-traded derivatives, and exchange-listed equities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds
for Dominion and Virginia Power, benefit plan trust funds for Dominion and Dominion Gas, and rabbi 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
|
Combined Notes to Consolidated Financial Statements, Continued
|
|
primarily include commodity forwards and swaps, interest rate swaps, restricted cash equivalents, and certain Treasury securities, money market funds, common/collective trust funds, and
corporate, state and municipal debt securities held in nuclear decommissioning trust funds for Dominion and Virginia Power, benefit plan trust funds for Dominion and Dominion Gas, and rabbi 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 the Companies consist of long-dated commodity derivatives, FTRs, NGLs, natural gas peaking options and other modeled commodity derivatives. Additional instruments categorized in Level 3 for Dominion
and Dominion Gas include 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, the Companies 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.
The Companies enter into certain physical and financial forwards, futures, options and swaps, 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 and futures contracts. An option model is used to value Level 3
physical and financial options. 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. 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, the original sales prices, and volumes. For Level 3 fair value measurements, forward market prices, credit spreads and implied price volatilities 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.
The following table presents Dominions and Dominion Gas quantitative information about Level 3 fair value measurements at
December 31, 2014. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility and credit spreads.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value (millions) |
|
|
Valuation Techniques |
|
|
Unobservable Input |
|
|
|
|
Range |
|
|
Weighted Average(1)
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical and Financial Forwards and Futures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas(2) |
|
$ |
74 |
|
|
|
Discounted Cash Flow |
|
|
|
Market Price (per Dth) |
|
|
(4) |
|
|
(2) 11 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
Credit Spread |
|
|
(6) |
|
|
1% 5% |
|
|
|
2 |
% |
FTRs |
|
|
44 |
|
|
|
Discounted Cash Flow |
|
|
|
Market Price (per MWh) |
|
|
(4) |
|
|
(1) 21 |
|
|
|
3 |
|
NGLs(3) |
|
|
2 |
|
|
|
Discounted Cash Flow |
|
|
|
Market Price (per Gal) |
|
|
(4) |
|
|
0 2 |
|
|
|
1 |
|
Physical and Financial Options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
5 |
|
|
|
Option Model |
|
|
|
Market Price (per Dth) |
|
|
(4) |
|
|
2 4 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
Price Volatility |
|
|
(5) |
|
|
19% 67% |
|
|
|
33 |
% |
Total assets |
|
$ |
125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical and Financial Forwards and Futures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas(2) |
|
$ |
12 |
|
|
|
Discounted Cash Flow |
|
|
|
Market Price (per Dth) |
|
|
(4) |
|
|
(2) 4 |
|
|
|
2 |
|
FTRs |
|
|
4 |
|
|
|
Discounted Cash Flow |
|
|
|
Market Price (per MWh) |
|
|
(4) |
|
|
(21) 21 |
|
|
|
|
|
Physical and Financial Options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
2 |
|
|
|
Option Model |
|
|
|
Market Price (per Dth) |
|
|
(4) |
|
|
2 4 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
Price Volatility |
|
|
(5) |
|
|
19% 67% |
|
|
|
33 |
% |
Total liabilities |
|
$ |
18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Averages weighted by volume. |
(3) |
Information represents Dominion Gas quantitative information about Level 3 fair value measurements. |
(4) |
Represents market prices beyond defined terms for Levels 1 and 2. |
(5) |
Represents volatilities unrepresented in published markets. |
(6) |
Represents credit spreads unrepresented in published markets. |
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
|
|
|
|
|
|
|
|
|
Significant Unobservable Inputs |
|
Position |
|
Change to Input |
|
Impact on Fair Value Measurement |
|
Market Price |
|
Buy |
|
Increase (decrease) |
|
|
Gain (loss) |
|
Market Price |
|
Sell |
|
Increase (decrease) |
|
|
Loss (gain) |
|
Price Volatility |
|
Buy |
|
Increase (decrease) |
|
|
Gain (loss) |
|
Price Volatility |
|
Sell |
|
Increase (decrease) |
|
|
Loss (gain) |
|
Credit Spread |
|
Asset |
|
Increase (decrease) |
|
|
Loss (gain) |
|
Nonrecurring Fair Value Measurements
DOMINION GAS
Natural Gas Assets
In the fourth quarter of 2014, Dominion Gas recorded an impairment charge of $9 million ($6 million after-tax) in other operations and maintenance expense
in its Consolidated Statements of Income, to write off previously capitalized costs following the cancellation of a development project.
In June 2013, Dominion Gas purchased certain natural gas infrastructure facilities that were previously leased from third parties. The purchase price was based on terms in the lease, which exceeded
current market pricing. As a result of the purchase price and expected losses, Dominion Gas recorded an impairment charge of $49 million ($29 million after-tax) in other operations and maintenance expense in its Consolidated Statements of
Income, to write down the long-lived assets to their estimated fair values of less than $1 million. 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 Gas used the income approach (discounted cash flows)
to estimate the fair value of the assets in this impairment test. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs, including estimates of
future production and other commodity prices.
Also in June 2013, Dominion Gas recorded an impairment charge of $6 million
($4 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write off previously capitalized costs following the cancellation of two development projects.
DOMINION
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 was 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 loss from discontinued operations 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.
Combined Notes to Consolidated Financial Statements, Continued
See Note 3 for information regarding the sale of Brayton Point, Kincaid and Dominions
equity method investment in Elwood, including an additional impairment.
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 contracted to buy Kewaunees generation expired in December 2013 at a time of 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. Kewaunee ceased operations and decommissioning activities commenced in May 2013.
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 Statement 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.
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 and Dominion Gas 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
3 |
|
|
$ |
567 |
|
|
$ |
125 |
|
|
$ |
695 |
|
Interest rate |
|
|
|
|
|
|
24 |
|
|
|
|
|
|
|
24 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
2,669 |
|
|
|
|
|
|
|
|
|
|
|
2,669 |
|
Other |
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Non-U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
12 |
|
Fixed Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
|
|
|
|
441 |
|
|
|
|
|
|
|
441 |
|
U.S. Treasury securities and agency debentures |
|
|
419 |
|
|
|
190 |
|
|
|
|
|
|
|
609 |
|
State and municipal |
|
|
|
|
|
|
395 |
|
|
|
|
|
|
|
395 |
|
Other |
|
|
|
|
|
|
74 |
|
|
|
|
|
|
|
74 |
|
Cash equivalents and other |
|
|
3 |
|
|
|
10 |
|
|
|
|
|
|
|
13 |
|
Total assets |
|
$ |
3,112 |
|
|
$ |
1,701 |
|
|
$ |
125 |
|
|
$ |
4,938 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
3 |
|
|
$ |
571 |
|
|
$ |
18 |
|
|
$ |
592 |
|
Interest rate |
|
|
|
|
|
|
202 |
|
|
|
|
|
|
|
202 |
|
Total liabilities |
|
$ |
3 |
|
|
$ |
773 |
|
|
$ |
18 |
|
|
$ |
794 |
|
At December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
3 |
|
|
$ |
718 |
|
|
$ |
32 |
|
|
$ |
753 |
|
Interest rate |
|
|
|
|
|
|
137 |
|
|
|
|
|
|
|
137 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
2,417 |
|
|
|
|
|
|
|
|
|
|
|
2,417 |
|
Other |
|
|
79 |
|
|
|
|
|
|
|
|
|
|
|
79 |
|
Non-U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
13 |
|
Fixed Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
|
|
|
|
345 |
|
|
|
|
|
|
|
345 |
|
U.S. Treasury securities and agency debentures |
|
|
415 |
|
|
|
175 |
|
|
|
|
|
|
|
590 |
|
State and municipal |
|
|
|
|
|
|
343 |
|
|
|
|
|
|
|
343 |
|
Other |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
3 |
|
Cash equivalents and other |
|
|
|
|
|
|
103 |
|
|
|
|
|
|
|
103 |
|
Restricted cash equivalents |
|
|
|
|
|
|
8 |
|
|
|
|
|
|
|
8 |
|
Total assets |
|
$ |
2,927 |
|
|
$ |
1,832 |
|
|
$ |
32 |
|
|
$ |
4,791 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
3 |
|
|
$ |
1,051 |
|
|
$ |
48 |
|
|
$ |
1,102 |
|
Total liabilities |
|
$ |
3 |
|
|
$ |
1,051 |
|
|
$ |
48 |
|
|
$ |
1,102 |
|
(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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Balance at January 1, |
|
$ |
(16 |
) |
|
$ |
25 |
|
|
$ |
(71 |
) |
Total realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
97 |
|
|
|
(9 |
) |
|
|
(15 |
) |
Included in other comprehensive income (loss) |
|
|
7 |
|
|
|
1 |
|
|
|
101 |
|
Included in regulatory assets/liabilities |
|
|
109 |
|
|
|
(9 |
) |
|
|
30 |
|
Settlements |
|
|
(88 |
) |
|
|
(23 |
) |
|
|
47 |
|
Transfers out of Level 3 |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(67 |
) |
Balance at December 31, |
|
$ |
107 |
|
|
$ |
(16 |
) |
|
$ |
25 |
|
The amount of total gains (losses) for the period included in earnings attributable to the change
in unrealized gains (losses) relating to assets still held at the reporting date |
|
$ |
6 |
|
|
$ |
|
|
|
$ |
42 |
|
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, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gains (losses) included in earnings |
|
$ |
4 |
|
|
$ |
97 |
|
|
$ |
(4 |
) |
|
$ |
97 |
|
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 |
|
|
|
1 |
|
|
|
1 |
|
|
|
6 |
|
Year Ended December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gains (losses) included in earnings |
|
$ |
11 |
|
|
$ |
(19 |
) |
|
$ |
(1 |
) |
|
$ |
(9 |
) |
The amount of total gains (losses) for the period included in earnings attributable to the change
in unrealized gains (losses) relating to assets still held at the reporting date |
|
|
1 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
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 |
|
Combined Notes to Consolidated Financial Statements, Continued
VIRGINIA POWER
The following table presents Virginia Powers quantitative information about Level 3 fair value measurements at December 31, 2014. The range and weighted average are presented in dollars for
market price inputs and percentages for credit spreads.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value (millions) |
|
|
Valuation Techniques |
|
|
Unobservable Input |
|
|
Range |
|
|
Weighted
Average(1) |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical and Financial Forwards and Futures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FTRs |
|
$ |
44 |
|
|
|
Discounted Cash Flow |
|
|
|
Market Price (per MWh)(3) |
|
|
|
(1) 21 |
|
|
|
3 |
|
Natural gas(2) |
|
|
62 |
|
|
|
Discounted Cash Flow |
|
|
|
Market Price (per Dth)(3) |
|
|
|
(2) 7 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
Credit Spread(4) |
|
|
|
1% 5% |
|
|
|
2 |
% |
Total assets |
|
$ |
106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical and Financial Forwards and Futures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FTRs |
|
$ |
4 |
|
|
|
Discounted Cash Flow |
|
|
|
Market Price (per MWh)(3) |
|
|
|
(21) 21 |
|
|
|
|
|
Total liabilities |
|
$ |
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Averages weighted by volume. |
(3) |
Represents market prices beyond defined terms for Levels 1 and 2. |
(4) |
Represents credit spreads unrepresented in published markets. |
Sensitivity of the fair value measurements to changes in the significant unobservable
inputs is as follows:
|
|
|
|
|
|
|
|
|
Significant Unobservable Inputs |
|
Position |
|
Change to Input |
|
Impact on Fair Value Measurement |
|
Market Price |
|
Buy |
|
Increase (decrease) |
|
|
Gain (loss) |
|
Market Price |
|
Sell |
|
Increase (decrease) |
|
|
Loss (gain) |
|
Credit Spread |
|
Asset |
|
Increase (decrease) |
|
|
Loss (gain) |
|
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, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
7 |
|
|
$ |
106 |
|
|
$ |
113 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
1,157 |
|
|
|
|
|
|
|
|
|
|
|
1,157 |
|
Fixed Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
|
|
|
|
250 |
|
|
|
|
|
|
|
250 |
|
U.S. Treasury securities and agency debentures |
|
|
137 |
|
|
|
61 |
|
|
|
|
|
|
|
198 |
|
State and municipal |
|
|
|
|
|
|
211 |
|
|
|
|
|
|
|
211 |
|
Other |
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
23 |
|
Total assets |
|
$ |
1,294 |
|
|
$ |
552 |
|
|
$ |
106 |
|
|
$ |
1,952 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
11 |
|
|
$ |
4 |
|
|
$ |
15 |
|
Interest rate |
|
|
|
|
|
|
72 |
|
|
|
|
|
|
|
72 |
|
Total liabilities |
|
$ |
|
|
|
$ |
83 |
|
|
$ |
4 |
|
|
$ |
87 |
|
At December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
3 |
|
|
$ |
2 |
|
|
$ |
5 |
|
Interest rate |
|
|
|
|
|
|
48 |
|
|
|
|
|
|
|
48 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
1,021 |
|
|
|
|
|
|
|
|
|
|
|
1,021 |
|
Other |
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
36 |
|
Fixed Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
|
|
|
|
191 |
|
|
|
|
|
|
|
191 |
|
U.S. Treasury securities and agency debentures |
|
|
146 |
|
|
|
66 |
|
|
|
|
|
|
|
212 |
|
State and municipal |
|
|
|
|
|
|
164 |
|
|
|
|
|
|
|
164 |
|
Cash equivalents and other |
|
|
|
|
|
|
31 |
|
|
|
|
|
|
|
31 |
|
Restricted cash equivalents |
|
|
|
|
|
|
8 |
|
|
|
|
|
|
|
8 |
|
Total assets |
|
$ |
1,203 |
|
|
$ |
511 |
|
|
$ |
2 |
|
|
$ |
1,716 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
3 |
|
|
$ |
9 |
|
|
$ |
12 |
|
Total liabilities |
|
$ |
|
|
|
$ |
3 |
|
|
$ |
9 |
|
|
$ |
12 |
|
(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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Balance at January 1, |
|
$ |
(7 |
) |
|
$ |
2 |
|
|
$ |
(28 |
) |
Total realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
96 |
|
|
|
(17 |
) |
|
|
(50 |
) |
Included in regulatory assets/liabilities |
|
|
109 |
|
|
|
(9 |
) |
|
|
30 |
|
Settlements |
|
|
(96 |
) |
|
|
17 |
|
|
|
50 |
|
Balance at December 31, |
|
$ |
102 |
|
|
$ |
(7 |
) |
|
$ |
2 |
|
The gains and losses included in earnings in the Level 3 fair value category were classified in electric
fuel and other energy-related purchases expense in Virginia Powers Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012. 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, 2014, 2013 and 2012.
DOMINION GAS
The
following table presents Dominion Gas assets and liabilities for commodity and interest rate derivatives 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, 2014 |
|
|
|
|
Assets: |
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
2 |
|
Total assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
2 |
|
Liabilities: |
|
|
|
|
Interest rate |
|
$ |
|
|
|
$ |
9 |
|
|
$ |
|
|
|
$ |
9 |
|
Total liabilities |
|
$ |
|
|
|
$ |
9 |
|
|
$ |
|
|
|
$ |
9 |
|
At December 31, 2013 |
|
|
|
|
Assets: |
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
|
|
|
$ |
6 |
|
|
$ |
6 |
|
Interest rate |
|
|
|
|
|
|
34 |
|
|
|
|
|
|
|
34 |
|
Total assets |
|
$ |
|
|
|
$ |
34 |
|
|
$ |
6 |
|
|
$ |
40 |
|
Liabilities: |
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
13 |
|
|
$ |
12 |
|
|
$ |
25 |
|
Total liabilities |
|
$ |
|
|
|
$ |
13 |
|
|
$ |
12 |
|
|
$ |
25 |
|
Combined Notes to Consolidated Financial Statements, Continued
The following table presents the net change in Dominion Gas derivative assets and
liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Balance at January 1, |
|
$ |
(6 |
) |
|
$ |
(12 |
) |
|
$ |
(98 |
) |
Total realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
2 |
|
|
|
1 |
|
|
|
(15 |
) |
Included in other comprehensive income (loss) |
|
|
10 |
|
|
|
3 |
|
|
|
86 |
|
Settlements |
|
|
(4 |
) |
|
|
2 |
|
|
|
15 |
|
Balance at December 31, |
|
$ |
2 |
|
|
$ |
(6 |
) |
|
$ |
(12 |
) |
The gains and losses included in earnings in the Level 3 fair value category were classified in operating
revenue in Dominion Gas Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012. 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, 2014, 2013 and 2012.
Fair Value of Financial Instruments
Substantially all of the Companies financial instruments are recorded at fair value, with the exception of the instruments described below, which 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, restricted cash (which is recorded in other current assets), customer
and other receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies financial instruments
that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 |
|
|
2013 |
|
|
|
Carrying Amount |
|
|
Estimated Fair
Value(1) |
|
|
Carrying Amount |
|
|
Estimated Fair Value(1) |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, including securities due within one
year(2) |
|
$ |
19,723 |
|
|
$ |
21,881 |
|
|
$ |
18,396 |
|
|
$ |
19,887 |
|
Junior subordinated notes(3) |
|
|
1,374 |
|
|
|
1,396 |
|
|
|
1,373 |
|
|
|
1,394 |
|
Remarketable subordinated notes(3) |
|
|
2,083 |
|
|
|
2,362 |
|
|
|
1,080 |
|
|
|
1,192 |
|
Subsidiary preferred
stock(4) |
|
|
|
|
|
|
|
|
|
|
257 |
|
|
|
261 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, including securities due within one
year(3) |
|
$ |
8,937 |
|
|
$ |
10,293 |
|
|
$ |
8,032 |
|
|
$ |
8,897 |
|
Preferred
stock(4) |
|
|
|
|
|
|
|
|
|
|
257 |
|
|
|
261 |
|
Dominion Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt(3) |
|
$ |
2,594 |
|
|
$ |
2,672 |
|
|
$ |
1,198 |
|
|
$ |
1,169 |
|
(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) |
Carrying amount includes amounts which represent the unamortized discount and/or premium. At December 31, 2014, and 2013, includes the valuation of certain
fair value hedges associated with Dominions fixed rate debt, of approximately $19 million and $55 million, respectively. |
(3) |
Carrying amount includes amounts which represent the unamortized discount and/or premium. |
(4) |
Includes deferred issuance expenses of $2 million at December 31, 2013. See Note 18 for information about the redemption of preferred stock in 2014.
|
NOTE 7. DERIVATIVES AND HEDGE ACCOUNTING
ACTIVITIES
The Companies 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.
Derivative assets and liabilities are presented gross on the Companies Consolidated Balance Sheets. Dominions and Virginia Powers derivative contracts include both over-the-counter
transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Dominion Gas derivative contracts include
over-the-
counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or
clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements, and contract default provisions. In
addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions.
In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of
credit, and in some cases other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on the
Companies Consolidated Balance Sheets, as well as letters of credit and other forms of security, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net
exposure.
Combined Notes to Consolidated Financial Statements, Continued
DOMINION
Balance Sheet Presentation
The tables below present Dominions derivative asset and liability
balances by type of financial instrument, before and after the effects of offsetting:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
|
|
Gross Amounts of Recognized Assets |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Assets Presented in the Consolidated Balance
Sheet |
|
|
Gross Amounts of Recognized Assets |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
24 |
|
|
$ |
|
|
|
$ |
24 |
|
|
$ |
137 |
|
|
$ |
|
|
|
$ |
137 |
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
382 |
|
|
|
|
|
|
|
382 |
|
|
|
240 |
|
|
|
|
|
|
|
240 |
|
Exchange |
|
|
298 |
|
|
|
|
|
|
|
298 |
|
|
|
506 |
|
|
|
|
|
|
|
506 |
|
Total derivatives, subject to a master netting or similar arrangement |
|
|
704 |
|
|
|
|
|
|
|
704 |
|
|
|
883 |
|
|
|
|
|
|
|
883 |
|
Total derivatives, not subject to a master netting or similar arrangement |
|
|
15 |
|
|
|
|
|
|
|
15 |
|
|
|
7 |
|
|
|
|
|
|
|
7 |
|
Total |
|
$ |
719 |
|
|
$ |
|
|
|
$ |
719 |
|
|
$ |
890 |
|
|
$ |
|
|
|
$ |
890 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
|
|
|
December 31, 2013 |
|
|
|
|
|
|
Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Received |
|
|
Net Amounts |
|
|
Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Received |
|
|
Net Amounts |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
24 |
|
|
$ |
16 |
|
|
$ |
|
|
|
$ |
8 |
|
|
$ |
137 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
137 |
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
382 |
|
|
|
34 |
|
|
|
34 |
|
|
|
314 |
|
|
|
240 |
|
|
|
63 |
|
|
|
|
|
|
|
177 |
|
Exchange |
|
|
298 |
|
|
|
298 |
|
|
|
|
|
|
|
|
|
|
|
506 |
|
|
|
505 |
|
|
|
|
|
|
|
1 |
|
Total |
|
$ |
704 |
|
|
$ |
348 |
|
|
$ |
34 |
|
|
$ |
322 |
|
|
$ |
883 |
|
|
$ |
568 |
|
|
$ |
|
|
|
$ |
315 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
|
|
Gross Amounts of Recognized Liabilities |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
|
Gross Amounts of Recognized Liabilities |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
202 |
|
|
$ |
|
|
|
$ |
202 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
87 |
|
|
|
|
|
|
|
87 |
|
|
|
262 |
|
|
|
|
|
|
|
262 |
|
Exchange |
|
|
493 |
|
|
|
|
|
|
|
493 |
|
|
|
838 |
|
|
|
|
|
|
|
838 |
|
Total derivatives, subject to a master netting or similar arrangement |
|
|
782 |
|
|
|
|
|
|
|
782 |
|
|
|
1,100 |
|
|
|
|
|
|
|
1,100 |
|
Total derivatives, not subject to a master netting or similar arrangement |
|
|
12 |
|
|
|
|
|
|
|
12 |
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Total |
|
$ |
794 |
|
|
$ |
|
|
|
$ |
794 |
|
|
$ |
1,102 |
|
|
$ |
|
|
|
$ |
1,102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
|
|
|
December 31, 2013 |
|
|
|
|
|
|
Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Paid |
|
|
Net Amounts |
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Paid |
|
|
Net Amounts |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
202 |
|
|
$ |
16 |
|
|
$ |
|
|
|
$ |
186 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
87 |
|
|
|
34 |
|
|
|
1 |
|
|
|
52 |
|
|
|
262 |
|
|
|
63 |
|
|
|
69 |
|
|
|
130 |
|
Exchange |
|
|
493 |
|
|
|
298 |
|
|
|
195 |
|
|
|
|
|
|
|
838 |
|
|
|
505 |
|
|
|
333 |
|
|
|
|
|
Total |
|
$ |
782 |
|
|
$ |
348 |
|
|
$ |
196 |
|
|
$ |
238 |
|
|
$ |
1,100 |
|
|
$ |
568 |
|
|
$ |
402 |
|
|
$ |
130 |
|
Volumes
The following table presents the volume of Dominions derivative activity as of December 31, 2014. 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) |
|
|
52 |
|
|
|
13 |
|
Basis |
|
|
227 |
|
|
|
575 |
|
Electricity (MWh): |
|
|
|
|
|
|
|
|
Fixed price |
|
|
14,689,432 |
|
|
|
6,148,800 |
|
FTRs |
|
|
35,786,150 |
|
|
|
|
|
Capacity (MW) |
|
|
10,700 |
|
|
|
7,600 |
|
Liquids (Gals)(2) |
|
|
39,984,000 |
|
|
|
1,260,000 |
|
Interest rate |
|
$ |
1,300,000,000 |
|
|
$ |
4,450,000,000 |
|
(2) |
Includes NGLs and oil. |
Ineffectiveness and AOCI
For the years ended December 31, 2014, 2013 and 2012, 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, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AOCI After-Tax |
|
|
Amounts Expected to be Reclassified to Earnings during the next
12 Months After-Tax |
|
|
Maximum Term |
|
(millions) |
|
|
|
|
|
|
|
|
|
Commodities: |
|
|
|
|
|
|
|
|
|
|
|
|
Gas |
|
$ |
(8 |
) |
|
$ |
(7 |
) |
|
|
27 months |
|
Electricity |
|
|
56 |
|
|
|
46 |
|
|
|
24 months |
|
Other |
|
|
|
|
|
|
|
|
|
|
17 months |
|
Interest rate |
|
|
(226 |
) |
|
|
(6 |
) |
|
|
384 months |
|
Total |
|
$ |
(178 |
) |
|
$ |
33 |
|
|
|
|
|
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.
Combined Notes to Consolidated Financial Statements, Continued
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
- Derivatives under Hedge Accounting |
|
|
Fair Value - Derivatives not
under Hedge Accounting |
|
|
Total Fair Value |
|
(millions) |
|
|
|
|
|
|
|
|
|
At December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
281 |
|
|
$ |
242 |
|
|
$ |
523 |
|
Interest rate |
|
|
13 |
|
|
|
|
|
|
|
13 |
|
Total current derivative assets |
|
|
294 |
|
|
|
242 |
|
|
|
536 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
71 |
|
|
|
101 |
|
|
|
172 |
|
Interest rate |
|
|
11 |
|
|
|
|
|
|
|
11 |
|
Total noncurrent derivative assets(1) |
|
|
82 |
|
|
|
101 |
|
|
|
183 |
|
Total derivative assets |
|
$ |
376 |
|
|
$ |
343 |
|
|
$ |
719 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
224 |
|
|
$ |
267 |
|
|
$ |
491 |
|
Interest rate |
|
|
100 |
|
|
|
|
|
|
|
100 |
|
Total current derivative liabilities |
|
|
324 |
|
|
|
267 |
|
|
|
591 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
55 |
|
|
|
46 |
|
|
|
101 |
|
Interest rate |
|
|
102 |
|
|
|
|
|
|
|
102 |
|
Total noncurrent derivative liabilities(2) |
|
|
157 |
|
|
|
46 |
|
|
|
203 |
|
Total derivative liabilities |
|
$ |
481 |
|
|
$ |
313 |
|
|
$ |
794 |
|
At December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
49 |
|
|
$ |
522 |
|
|
$ |
571 |
|
Interest rate |
|
|
116 |
|
|
|
|
|
|
|
116 |
|
Total current derivative assets |
|
|
165 |
|
|
|
522 |
|
|
|
687 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
28 |
|
|
|
154 |
|
|
|
182 |
|
Interest rate |
|
|
21 |
|
|
|
|
|
|
|
21 |
|
Total noncurrent derivative assets(1) |
|
|
49 |
|
|
|
154 |
|
|
|
203 |
|
Total derivative assets |
|
$ |
214 |
|
|
$ |
676 |
|
|
$ |
890 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
267 |
|
|
$ |
561 |
|
|
$ |
828 |
|
Total current derivative liabilities |
|
|
267 |
|
|
|
561 |
|
|
|
828 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
119 |
|
|
|
155 |
|
|
|
274 |
|
Total noncurrent derivative liabilities(2) |
|
|
119 |
|
|
|
155 |
|
|
|
274 |
|
Total derivative liabilities |
|
$ |
386 |
|
|
$ |
716 |
|
|
$ |
1,102 |
|
(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 |
|
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) |
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014 |
|
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
|
$ |
(130 |
) |
|
|
|
|
Purchased gas |
|
|
|
|
|
|
(13 |
) |
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
|
|
|
|
7 |
|
|
|
|
|
Total commodity |
|
$ |
245 |
|
|
$ |
(136 |
) |
|
$ |
(4 |
) |
Interest
rate(3) |
|
|
(208 |
) |
|
|
(16 |
) |
|
|
(81 |
) |
Total |
|
$ |
37 |
|
|
$ |
(152 |
) |
|
$ |
(85 |
) |
Year Ended December 31, 2013 |
|
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
|
$ |
(58 |
) |
|
|
|
|
Purchased gas |
|
|
|
|
|
|
(47 |
) |
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
|
|
|
|
(10 |
) |
|
|
|
|
Total commodity |
|
$ |
(481 |
) |
|
$ |
(115 |
) |
|
$ |
5 |
|
Interest
rate(3) |
|
|
77 |
|
|
|
(15 |
) |
|
|
81 |
|
Total |
|
$ |
(404 |
) |
|
$ |
(130 |
) |
|
$ |
86 |
|
Year Ended December 31, 2012 |
|
|
|
|
|
|
|
|
|
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 |
) |
(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. |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging
instruments |
|
Amount of Gain (Loss) Recognized in Income on Derivatives(1) |
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
(310 |
) |
|
$ |
(45 |
) |
|
$ |
168 |
|
Purchased gas |
|
|
(51 |
) |
|
|
(9 |
) |
|
|
(14 |
) |
Electric fuel and other energy-related purchases |
|
|
113 |
|
|
|
(29 |
) |
|
|
(40 |
) |
Interest
rate(2) |
|
|
|
|
|
|
|
|
|
|
17 |
|
Total |
|
$ |
(248 |
) |
|
$ |
(83 |
) |
|
$ |
131 |
|
(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
Balance
Sheet Presentation
The tables below present Virginia Powers derivative asset and liability balances by type of financial instrument,
before and after the effects of offsetting:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
|
|
Gross Amounts of Recognized Assets |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
|
Gross Amounts of Recognized Assets |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
48 |
|
|
$ |
|
|
|
$ |
48 |
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
106 |
|
|
|
|
|
|
|
106 |
|
|
|
4 |
|
|
|
|
|
|
|
4 |
|
Exchange |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Total derivatives, subject to a master netting or similar arrangement |
|
|
106 |
|
|
|
|
|
|
|
106 |
|
|
|
53 |
|
|
|
|
|
|
|
53 |
|
Total derivatives, not subject to a master netting or similar arrangement |
|
|
7 |
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
113 |
|
|
$ |
|
|
|
$ |
113 |
|
|
$ |
53 |
|
|
$ |
|
|
|
$ |
53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
|
|
|
|
|
|
December 31, 2013 |
|
|
|
|
|
|
|
|
|
Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
|
|
Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Received |
|
|
Net Amounts |
|
|
Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Received |
|
|
Net Amounts |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
48 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
48 |
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
106 |
|
|
|
4 |
|
|
|
|
|
|
|
102 |
|
|
|
4 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
Exchange |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Total |
|
$ |
106 |
|
|
$ |
4 |
|
|
$ |
|
|
|
$ |
102 |
|
|
$ |
53 |
|
|
$ |
4 |
|
|
$ |
|
|
|
$ |
49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
|
|
Gross Amounts of Recognized Liabilities |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
|
Gross Amounts of Recognized Liabilities |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
72 |
|
|
$ |
|
|
|
$ |
72 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
8 |
|
|
|
|
|
|
|
8 |
|
|
|
12 |
|
|
|
|
|
|
|
12 |
|
Total derivatives, subject to a master netting or similar arrangement |
|
|
80 |
|
|
|
|
|
|
|
80 |
|
|
|
12 |
|
|
|
|
|
|
|
12 |
|
Total derivatives, not subject to a master netting or similar arrangement |
|
|
7 |
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
87 |
|
|
$ |
|
|
|
$ |
87 |
|
|
$ |
12 |
|
|
$ |
|
|
|
$ |
12 |
|
Combined Notes to Consolidated Financial Statements, Continued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
|
|
|
|
|
|
December 31, 2013 |
|
|
|
|
|
|
|
|
|
Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
|
|
Gross Amounts Not Offset
in the Consolidated Balance Sheet |
|
|
|
|
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance
Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Paid |
|
|
Net Amounts |
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Paid |
|
|
Net Amounts |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
72 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
72 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
8 |
|
|
|
4 |
|
|
|
|
|
|
|
4 |
|
|
|
12 |
|
|
|
4 |
|
|
|
7 |
|
|
|
1 |
|
Total |
|
$ |
80 |
|
|
$ |
4 |
|
|
$ |
|
|
|
$ |
76 |
|
|
$ |
12 |
|
|
$ |
4 |
|
|
$ |
7 |
|
|
$ |
1 |
|
Volumes
The following table presents the volume of Virginia Powers derivative activity at December 31, 2014. 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 |
|
|
7 |
|
|
|
|
|
Basis |
|
|
51 |
|
|
|
493 |
|
Electricity (MWh): |
|
|
|
|
|
|
|
|
FTRs |
|
|
33,709,386 |
|
|
|
|
|
Capacity (MW) |
|
|
10,700 |
|
|
|
7,600 |
|
Interest rate |
|
$ |
550,000,000 |
|
|
$ |
900,000,000 |
|
Ineffectiveness
For the years ended December 31, 2014, 2013 and 2012, gains or losses on hedging instruments determined to be ineffective were not material.
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value -
Derivatives under
Hedge Accounting |
|
|
Fair Value -
Derivatives not under
Hedge Accounting |
|
|
Total
Fair Value |
|
(millions) |
|
|
|
|
|
|
|
|
|
At December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
|
|
|
$ |
51 |
|
|
$ |
51 |
|
Total current derivative assets(1) |
|
|
|
|
|
|
51 |
|
|
|
51 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
|
|
|
|
|
62 |
|
|
|
62 |
|
Total noncurrent derivative assets(2) |
|
|
|
|
|
|
62 |
|
|
|
62 |
|
Total derivative assets |
|
$ |
|
|
|
$ |
113 |
|
|
$ |
113 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
3 |
|
|
$ |
12 |
|
|
$ |
15 |
|
Interest rate |
|
|
45 |
|
|
|
|
|
|
|
45 |
|
Total current derivative liabilities |
|
|
48 |
|
|
|
12 |
|
|
|
60 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate |
|
|
27 |
|
|
|
|
|
|
|
27 |
|
Total noncurrent derivative liabilities(3) |
|
|
27 |
|
|
|
|
|
|
|
27 |
|
Total derivative liabilities |
|
$ |
75 |
|
|
$ |
12 |
|
|
$ |
87 |
|
At December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
2 |
|
|
$ |
3 |
|
|
$ |
5 |
|
Interest rate |
|
|
48 |
|
|
|
|
|
|
|
48 |
|
Total current derivative assets(1) |
|
|
50 |
|
|
|
3 |
|
|
|
53 |
|
Total derivative assets |
|
$ |
50 |
|
|
$ |
3 |
|
|
$ |
53 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
1 |
|
|
$ |
11 |
|
|
$ |
12 |
|
Total current derivative liabilities |
|
|
1 |
|
|
|
11 |
|
|
|
12 |
|
Total derivative liabilities |
|
$ |
1 |
|
|
$ |
11 |
|
|
$ |
12 |
|
(1) |
Current derivative assets are presented in other current assets in Virginia Powers Consolidated Balance Sheets. |
(2) |
Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Powers Consolidated Balance Sheets.
|
(3) |
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 |
|
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) |
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014 |
|
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
|
|
|
$ |
5 |
|
|
|
|
|
Total commodity |
|
$ |
4 |
|
|
$ |
5 |
|
|
$ |
(4 |
) |
Interest
rate(3) |
|
|
(10 |
) |
|
|
|
|
|
|
(81 |
) |
Total |
|
$ |
(6 |
) |
|
$ |
5 |
|
|
$ |
(85 |
) |
Year Ended December 31, 2013 |
|
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
|
|
|
$ |
|
|
|
|
|
|
Total commodity |
|
$ |
|
|
|
$ |
|
|
|
$ |
5 |
|
Interest
rate(3) |
|
|
9 |
|
|
|
|
|
|
|
81 |
|
Total |
|
$ |
9 |
|
|
$ |
|
|
|
$ |
86 |
|
Year Ended December 31, 2012 |
|
|
|
|
|
|
|
|
|
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 |
) |
(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. |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging
instruments |
|
Amount of Gain (Loss) Recognized in Income on Derivatives(1) |
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity(2) |
|
$ |
105 |
|
|
$ |
(16 |
) |
|
$ |
(50 |
) |
Total |
|
$ |
105 |
|
|
$ |
(16 |
) |
|
$ |
(50 |
) |
(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.
|
DOMINION GAS
Balance Sheet Presentation
The
tables below present Dominion Gas derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
|
|
Gross Amounts of Recognized Assets |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
|
Gross
Amounts of Recognized Assets |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Assets Presented
in the Consolidated Balance Sheet |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
34 |
|
|
$ |
|
|
|
$ |
34 |
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
2 |
|
|
|
|
|
|
|
2 |
|
|
|
6 |
|
|
|
|
|
|
|
6 |
|
Total derivatives, subject to a master netting or similar arrangement |
|
$ |
2 |
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
40 |
|
|
$ |
|
|
|
$ |
40 |
|
Combined Notes to Consolidated Financial Statements, Continued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
|
|
|
|
|
|
December 31, 2013 |
|
|
|
|
|
|
|
|
|
Gross Amounts Not
Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
|
|
Gross Amounts Not Offset
in the Consolidated Balance
Sheet |
|
|
|
|
|
|
Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Received |
|
|
Net Amounts |
|
|
Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Received |
|
|
Net Amounts |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
34 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
34 |
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
6 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
40 |
|
|
$ |
6 |
|
|
$ |
|
|
|
$ |
34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
December 31, 2013 |
|
|
|
Gross Amounts of Recognized Liabilities |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
|
Gross Amounts of Recognized Liabilities |
|
|
Gross Amounts Offset in the Consolidated Balance Sheet |
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
9 |
|
|
$ |
|
|
|
$ |
9 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25 |
|
|
|
|
|
|
|
25 |
|
Total derivatives, subject to a master netting or similar arrangement |
|
$ |
9 |
|
|
$ |
|
|
|
$ |
9 |
|
|
$ |
25 |
|
|
$ |
|
|
|
$ |
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
|
|
|
|
|
|
December 31, 2013 |
|
|
|
|
|
|
|
|
|
Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
|
|
Gross Amounts Not Offset
in the Consolidated Balance Sheet |
|
|
|
|
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Paid |
|
|
Net Amounts |
|
|
Net Amounts of
Liabilities Presented in the Consolidated Balance Sheet |
|
|
Financial Instruments |
|
|
Cash Collateral Paid |
|
|
Net Amounts |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
$ |
9 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
9 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25 |
|
|
|
6 |
|
|
|
|
|
|
|
19 |
|
Total |
|
$ |
9 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
9 |
|
|
$ |
25 |
|
|
$ |
6 |
|
|
$ |
|
|
|
$ |
19 |
|
Volumes
The following table presents the volume of Dominion Gas derivative activity at December 31, 2014. 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 |
|
NGLs (Gals) |
|
|
32,340,000 |
|
|
|
|
|
Interest rate |
|
$ |
|
|
|
$ |
250,000,000 |
|
Ineffectiveness and AOCI
For the years ended December 31, 2014, 2013 and 2012, gains or losses on hedging instruments determined to be ineffective were not material.
The following table presents selected information related to gains (losses) on cash flow
hedges included in AOCI in Dominion Gas Consolidated Balance Sheet at December 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AOCI After-Tax |
|
|
Amounts Expected to be Reclassified to Earnings during the next
12 Months After-Tax |
|
|
Maximum Term |
|
(millions) |
|
|
|
|
|
|
|
|
|
Commodities: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
$ |
|
|
|
$ |
|
|
|
|
3 months |
|
NGLs |
|
|
|
|
|
|
|
|
|
|
12 months |
|
Interest rate |
|
|
(20 |
) |
|
|
|
|
|
|
360 months |
|
Total |
|
$ |
(20 |
) |
|
$ |
|
|
|
|
|
|
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.
Fair Value and Gains and Losses on Derivative Instruments
The following tables present the fair values of Dominion Gas derivatives and where they are presented in its Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value -
Derivatives under
Hedge Accounting |
|
|
Fair Value -
Derivatives not under
Hedge Accounting |
|
|
Total
Fair Value |
|
(millions) |
|
|
|
|
|
|
|
|
|
At December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
2 |
|
|
$ |
|
|
|
$ |
2 |
|
Total current derivative
assets(1) |
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Total derivative assets |
|
$ |
2 |
|
|
$ |
|
|
|
$ |
2 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate |
|
$ |
9 |
|
|
$ |
|
|
|
$ |
9 |
|
Total noncurrent derivative liabilities(2) |
|
|
9 |
|
|
|
|
|
|
|
9 |
|
Total derivative liabilities |
|
$ |
9 |
|
|
$ |
|
|
|
$ |
9 |
|
At December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
6 |
|
|
$ |
|
|
|
$ |
6 |
|
Interest rate |
|
|
34 |
|
|
|
|
|
|
|
34 |
|
Total current derivative
assets(1) |
|
|
40 |
|
|
|
|
|
|
|
40 |
|
Total derivative assets |
|
$ |
40 |
|
|
$ |
|
|
|
$ |
40 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
$ |
25 |
|
|
$ |
|
|
|
$ |
25 |
|
Total current derivative liabilities(3) |
|
|
25 |
|
|
|
|
|
|
|
25 |
|
Total derivative liabilities |
|
$ |
25 |
|
|
$ |
|
|
|
$ |
25 |
|
(1) |
Current derivative assets are presented in other current assets in Dominion Gas Consolidated Balance Sheets. |
(2) |
Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Gas Consolidated Balance Sheets.
|
(3) |
Current derivative liabilities are presented in other current liabilities in Dominion Gas Consolidated Balance Sheets.
|
The following tables present the gains and losses on Dominion Gas 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 |
|
Amount of Gain
(Loss) Recognized in
AOCI on Derivatives
(Effective Portion)(1) |
|
|
Amount of
Gain (Loss) Reclassified
from AOCI to
Income |
|
(millions) |
|
|
|
|
|
|
Year Ended December 31, 2014 |
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses) |
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
|
$ |
2 |
|
Purchased gas |
|
|
|
|
|
|
(14 |
) |
Total commodity |
|
$ |
12 |
|
|
$ |
(12 |
) |
Interest
rate(2) |
|
|
(62 |
) |
|
|
(1 |
) |
Total |
|
$ |
(50 |
) |
|
$ |
(13 |
) |
Year Ended December 31, 2013 |
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses) |
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
|
$ |
(2 |
) |
Purchased gas |
|
|
|
|
|
|
(14 |
) |
Total commodity |
|
$ |
(2 |
) |
|
$ |
(16 |
) |
Interest
rate(2) |
|
|
68 |
|
|
|
|
|
Total |
|
$ |
66 |
|
|
$ |
(16 |
) |
Year Ended December 31, 2012 |
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses) |
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
|
$ |
(15 |
) |
Purchased gas |
|
|
|
|
|
|
(18 |
) |
Total commodity |
|
$ |
64 |
|
|
$ |
(33 |
) |
Interest
rate(2) |
|
|
(41 |
) |
|
|
|
|
Total |
|
$ |
23 |
|
|
$ |
(33 |
) |
(1) |
Amounts deferred into AOCI have no associated effect in Dominion Gas Consolidated Statements of Income. |
(2) |
Amounts recorded in Dominion Gas 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
Net income attributable to Dominion |
|
$ |
1,310 |
|
|
$ |
1,697 |
|
|
$ |
302 |
|
Average shares of common stock outstanding-Basic |
|
|
582.7 |
|
|
|
578.7 |
|
|
|
572.9 |
|
Net effect of dilutive
securities(1) |
|
|
1.8 |
|
|
|
0.8 |
|
|
|
1.0 |
|
Average shares of common stock outstanding-Diluted |
|
|
584.5 |
|
|
|
579.5 |
|
|
|
573.9 |
|
Earnings Per Common Share-Basic |
|
$ |
2.25 |
|
|
$ |
2.93 |
|
|
$ |
0.53 |
|
Earnings Per Common Share-Diluted |
|
$ |
2.24 |
|
|
$ |
2.93 |
|
|
$ |
0.53 |
|
(1) |
Dilutive securities consist primarily of contingently convertible senior notes and the 2013 Equity Units for 2014 and contingently convertible senior notes for 2013
and 2012. Dominion redeemed all of its contingently convertible senior notes in 2014. See Note 17 for more information. |
The 2014 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the year ended December 31, 2014, as the dilutive stock price threshold was not
met. The 2013 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the year ended December 31, 2013. See Note 17 for more information. There were no potentially dilutive securities
excluded from the calculation of diluted EPS for the year ended December 31, 2012.
Combined Notes to Consolidated Financial Statements, Continued
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 $110 million and $107
million at December 31, 2014 and 2013, respectively. Cost-method investments held in Dominions rabbi trusts totaled $6 million and $10 million at December 31, 2014 and 2013, 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) |
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. large cap |
|
$ |
1,273 |
|
|
$ |
1,353 |
|
|
$ |
|
|
|
$ |
2,626 |
|
Marketable debt securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
424 |
|
|
|
19 |
|
|
|
(2 |
) |
|
|
441 |
|
U.S. Treasury securities and agency debentures |
|
|
597 |
|
|
|
13 |
|
|
|
(4 |
) |
|
|
606 |
|
State and municipal |
|
|
332 |
|
|
|
23 |
|
|
|
|
|
|
|
355 |
|
Other |
|
|
66 |
|
|
|
|
|
|
|
|
|
|
|
66 |
|
Cost method investments |
|
|
86 |
|
|
|
|
|
|
|
|
|
|
|
86 |
|
Cash equivalents and
other(2) |
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
16 |
|
Total |
|
$ |
2,794 |
|
|
$ |
1,408 |
|
|
$ |
(6 |
)(3) |
|
$ |
4,196 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
$ |
1,183 |
|
|
$ |
1,194 |
|
|
$ |
|
|
|
$ |
2,377 |
|
Other |
|
|
49 |
|
|
|
23 |
|
|
|
|
|
|
|
72 |
|
Marketable debt securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
332 |
|
|
|
16 |
|
|
|
(3 |
) |
|
|
345 |
|
U.S. Treasury securities and agency debentures |
|
|
589 |
|
|
|
8 |
|
|
|
(10 |
) |
|
|
587 |
|
State and municipal |
|
|
297 |
|
|
|
11 |
|
|
|
(5 |
) |
|
|
303 |
|
Other |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
3 |
|
Cost method investments |
|
|
106 |
|
|
|
|
|
|
|
|
|
|
|
106 |
|
Cash equivalents and
other(2) |
|
|
110 |
|
|
|
|
|
|
|
|
|
|
|
110 |
|
Total |
|
$ |
2,669 |
|
|
$ |
1,252 |
|
|
$ |
(18 |
)(3) |
|
$ |
3,903 |
|
(1) |
Included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
(2) |
Includes pending sales of securities of $3 million and $11 million at December 31, 2014 and 2013, respectively. |
(3) |
The fair value of securities in an unrealized loss position was $379 million and $604 million at December 31, 2014 and 2013, respectively.
|
The fair value of Dominions marketable debt securities held in nuclear
decommissioning trust funds at December 31, 2014 by contractual maturity is as follows:
|
|
|
|
|
|
|
Amount |
|
(millions) |
|
|
|
Due in one year or less |
|
$ |
169 |
|
Due after one year through five years |
|
|
390 |
|
Due after five years through ten years |
|
|
426 |
|
Due after ten years |
|
|
483 |
|
Total |
|
$ |
1,468 |
|
Presented below is selected information regarding Dominions marketable equity and
debt securities held in nuclear decommissioning trust funds:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Proceeds from sales |
|
$ |
1,235 |
|
|
$ |
1,476 |
|
|
$ |
1,356 |
|
Realized gains(1) |
|
|
171 |
|
|
|
157 |
|
|
|
98 |
|
Realized
losses(1) |
|
|
30 |
|
|
|
33 |
|
|
|
33 |
|
(1) |
Includes realized gains and losses recorded to the nuclear 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, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Total other-than-temporary impairment losses(1) |
|
$ |
21 |
|
|
$ |
31 |
|
|
$ |
26 |
|
Losses recorded to nuclear decommissioning trust regulatory liability |
|
|
(5 |
) |
|
|
(13 |
) |
|
|
(10 |
) |
Losses recognized in other comprehensive income (before taxes) |
|
|
(3 |
) |
|
|
(10 |
) |
|
|
(2 |
) |
Net impairment losses recognized in earnings |
|
$ |
13 |
|
|
$ |
8 |
|
|
$ |
14 |
|
(1) |
Amounts include other-than-temporary impairment losses for debt securities of $3 million, $18 million and $4 million at December 31, 2014, 2013 and 2012,
respectively. |
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) |
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. large cap |
|
$ |
563 |
|
|
$ |
594 |
|
|
$ |
|
|
|
$ |
1,157 |
|
Marketable debt securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
242 |
|
|
|
9 |
|
|
|
(1 |
) |
|
|
250 |
|
U.S. Treasury securities and agency debentures |
|
|
197 |
|
|
|
3 |
|
|
|
(2 |
) |
|
|
198 |
|
State and municipal |
|
|
197 |
|
|
|
13 |
|
|
|
|
|
|
|
210 |
|
Other |
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
23 |
|
Cost method investments |
|
|
86 |
|
|
|
|
|
|
|
|
|
|
|
86 |
|
Cash equivalents and
other(2) |
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Total |
|
$ |
1,314 |
|
|
$ |
619 |
|
|
$ |
(3 |
)(3) |
|
$ |
1,930 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
$ |
506 |
|
|
$ |
514 |
|
|
$ |
|
|
|
$ |
1,020 |
|
Other |
|
|
25 |
|
|
|
11 |
|
|
|
|
|
|
|
36 |
|
Marketable debt securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
185 |
|
|
|
8 |
|
|
|
(2 |
) |
|
|
191 |
|
U.S. Treasury securities and agency debentures |
|
|
214 |
|
|
|
1 |
|
|
|
(3 |
) |
|
|
212 |
|
State and municipal |
|
|
163 |
|
|
|
4 |
|
|
|
(4 |
) |
|
|
163 |
|
Cost method investments |
|
|
106 |
|
|
|
|
|
|
|
|
|
|
|
106 |
|
Cash equivalents and
other(2) |
|
|
37 |
|
|
|
|
|
|
|
|
|
|
|
37 |
|
Total |
|
$ |
1,236 |
|
|
$ |
538 |
|
|
$ |
(9 |
)(3) |
|
$ |
1,765 |
|
(1) |
Included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2. |
(2) |
Includes pending sales of securities of $6 million at December 31, 2014 and 2013. |
(3) |
The fair value of securities in an unrealized loss position was $170 million and $299 million at December 31, 2014 and 2013, respectively.
|
The fair value of Virginia Powers marketable debt securities at December 31,
2014, by contractual maturity is as follows:
|
|
|
|
|
|
|
Amount |
|
(millions) |
|
|
|
Due in one year or less |
|
$ |
40 |
|
Due after one year through five years |
|
|
180 |
|
Due after five years through ten years |
|
|
242 |
|
Due after ten years |
|
|
219 |
|
Total |
|
$ |
681 |
|
Presented below is selected information regarding Virginia Powers marketable equity and debt
securities.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Proceeds from sales |
|
$ |
549 |
|
|
$ |
572 |
|
|
$ |
626 |
|
Realized gains(1) |
|
|
73 |
|
|
|
52 |
|
|
|
42 |
|
Realized
losses(1) |
|
|
12 |
|
|
|
14 |
|
|
|
11 |
|
(1) |
Includes realized gains and losses recorded to the nuclear 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, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Total other-than-temporary impairment losses(1) |
|
$ |
8 |
|
|
$ |
15 |
|
|
$ |
11 |
|
Losses recorded to nuclear decommissioning trust regulatory liability |
|
|
(4 |
) |
|
|
(13 |
) |
|
|
(10 |
) |
Losses recorded in other comprehensive income (before taxes) |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
|
|
Net impairment losses recognized in earnings |
|
$ |
2 |
|
|
$ |
1 |
|
|
$ |
1 |
|
(1) |
Amounts include other-than-temporary impairment losses for debt securities of $2 million, $9 million and $2 million at December 31, 2014, 2013 and 2012,
respectively. |
EQUITY METHOD INVESTMENTS
Dominion and Dominion Gas
Investments that
Dominion and Dominion Gas account for under the equity method of accounting are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company |
|
Ownership% |
|
|
Investment Balance |
|
|
Description |
As of December 31, |
|
|
|
|
2014 |
|
|
2013 |
|
|
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Blue Racer Midstream, LLC |
|
|
50 |
% |
|
$ |
671 |
|
|
$ |
510 |
|
|
Midstream gas and related services |
Fowler I Holdings LLC |
|
|
50 |
% |
|
|
134 |
|
|
|
149 |
|
|
Wind-powered merchant generation facility |
NedPower Mount Storm LLC |
|
|
50 |
% |
|
|
128 |
|
|
|
131 |
|
|
Wind-powered merchant generation facility |
Iroquois Gas Transmission System, LP |
|
|
24.72 |
% |
|
|
107 |
|
|
|
105 |
|
|
Gas transmission system |
Other(1) |
|
|
various |
|
|
|
41 |
|
|
|
21 |
|
|
|
Total |
|
|
|
|
|
$ |
1,081 |
|
|
$ |
916 |
|
|
|
Dominion Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Iroquois Gas Transmission System, LP |
|
|
24.72 |
% |
|
$ |
107 |
|
|
$ |
105 |
|
|
Gas transmission system |
Total |
|
|
|
|
|
$ |
107 |
|
|
$ |
105 |
|
|
|
(1) |
Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018. Includes Dominions investment in Atlantic Coast
Pipeline. See Note 15 for more information. |
Combined Notes to Consolidated Financial Statements, Continued
Dominions equity earnings on its investments totaled $46 million, $14 million and $25
million in 2014, 2013 and 2012, respectively. Dominion received distributions from these investments of $60 million, $33 million and $58 million in 2014, 2013, and 2012, respectively. As of December 31, 2014 and 2013, the carrying amount of
Dominions investments exceeded its share of underlying equity in net assets by approximately $126 million and $36 million, respectively. $87 million of the differences relate to basis differences from Dominions investments in
Blue Racer and wind projects, which are being amortized over the useful lives of the underlying assets. The remaining $39 million of differences reflect equity method goodwill and are not being amortized.
Dominion Gas equity earnings on its investment totaled $21 million, $22 million and $23 million in 2014, 2013 and 2012,
respectively. Dominion Gas received distributions from its investment of $20 million, $19 million and $25 million in 2014, 2013, and 2012, respectively. As of December 31, 2014 and 2013, the carrying amount of Dominion Gas investment
exceeded its share of underlying equity in net assets by approximately $8 million. The differences reflect equity method goodwill and are not being amortized.
Equity earnings are recorded in other income in Dominions and Dominion Gas Consolidated Statements of Income.
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. Blue Racer is an equal partnership between Dominion and Caiman, with Dominion contributing midstream assets
and Caiman contributing private equity capital.
In December 2012, East Ohio sold two pipeline systems to an affiliate who then
contributed those systems to Blue Racer. East Ohio received consideration of $248 million, consisting of $61 million in cash proceeds and the extinguishment of affiliated long term debt of $187 million. The transaction resulted in a gain of
approximately $176 million ($110 million after-tax) that is recognized in other operations and maintenance expense in Dominion Gas Consolidated Statements of Income. Dominion recorded a 50% interest in Blue Racer and cash proceeds of $115
million for the contribution of the assets to the joint venture. Dominion recognized 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 Statements of Income.
In March 2013, DTI sold Line TL-404 to an affiliate, that subsequently sold
line TL-404 to Blue Racer for cash proceeds of approximately $47 million. The sale resulted in a gain of approximately $25 million ($14 million after-tax) net of a $2 million write-off of goodwill, and is included in other operations and maintenance
expense in both Dominion Gas and Dominions Consolidated Statements of Income.
Phase 1 of Natrium was completed in
the second quarter of 2013 and was contributed by Dominion to Blue Racer in the third quarter of 2013, resulting in an increased equity method
investment in Blue Racer of $473 million. Also in the third quarter of 2013, DTI sold Line TPL-2A to an affiliate, that subsequently sold Line TPL-2A to Blue Racer, and sold Line TL-388 to Blue Racer and received approximately $78 million in cash proceeds. The sales resulted in an approximately $74 million ($41 million after-tax) gain which is included in other operations and maintenance
expense in both Dominion Gas and Dominions Consolidated Statements of Income.
In the fourth quarter of 2013, DTI
sold the Western System to an affiliate, that subsequently sold the Western System to Blue Racer for cash proceeds of approximately $30 million. The sale resulted in a gain of approximately $3 million ($2 million after-tax) for DTI and $4 million
($2 million after-tax) for Dominion and is included in other operations and maintenance expense in both Dominion Gas and Dominions Consolidated Statement of Income.
Dominion NGL Pipelines, LLC was contributed in January 2014 by Dominion to Blue Racer, prior to commencement of service, resulting in an increased equity method investment of $155 million, including $6
million of goodwill allocated from Dominions goodwill balance to its equity method investment in Blue Racer.
In March
2014, Dominion Gas sold the Northern System to an affiliate, that subsequently sold the Northern System to Blue Racer for consideration of approximately $84 million. Dominion Gas consideration consisted of $17 million in cash proceeds and the
extinguishment of affiliated current borrowings of $67 million and Dominions consideration consisted of cash proceeds of approximately $84 million. The sale resulted in a gain of approximately $59 million ($35 million after-tax for Dominion
Gas and $34 million after-tax for Dominion) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in both Dominion Gas and Dominions Consolidated Statement of Income.
Dominion
ATLANTIC
COAST PIPELINE
In September 2014, Dominion, along with Duke Energy Corporation, Piedmont Natural Gas
Company, Inc. and AGL Resources Inc., announced the formation of Atlantic Coast Pipeline. The members, which are subsidiaries of the above-referenced parent companies, hold the following membership interests: Dominion, 45%; Duke Energy Corporation,
40%; Piedmont Natural Gas Company, Inc., 10%; and AGL Resources Inc., 5%. Atlantic Coast Pipeline is focused on constructing an approximately 550-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Subsidiaries
and affiliates of all four members plan to be customers of the pipeline under 20-year contracts, pending regulatory approvals. PSNC Energy also plans to be a customer of the pipeline under a 20-year contract, pending regulatory approvals. Atlantic
Coast Pipeline is considered an equity method investment as Dominion has the ability to exercise significant influence, but not control, over the investee. See Note 15 for more information.
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, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
Utility: |
|
|
|
|
|
|
|
|
Generation |
|
$ |
15,193 |
|
|
$ |
14,018 |
|
Transmission |
|
|
9,897 |
|
|
|
8,686 |
|
Distribution |
|
|
12,354 |
|
|
|
11,714 |
|
Storage |
|
|
2,350 |
|
|
|
2,190 |
|
Nuclear fuel |
|
|
1,411 |
|
|
|
1,375 |
|
Gas gathering and processing |
|
|
791 |
|
|
|
787 |
|
General and other |
|
|
845 |
|
|
|
812 |
|
Other-including plant under construction |
|
|
3,633 |
|
|
|
3,261 |
|
Total utility |
|
|
46,474 |
|
|
|
42,843 |
|
Nonutility: |
|
|
|
|
|
|
|
|
Merchant generation-nuclear |
|
|
1,267 |
|
|
|
1,153 |
|
Merchant generation-other |
|
|
2,023 |
|
|
|
1,328 |
|
Nuclear fuel |
|
|
860 |
|
|
|
770 |
|
Other-including plant under construction |
|
|
782 |
|
|
|
875 |
|
Total nonutility |
|
|
4,932 |
|
|
|
4,126 |
|
Total property, plant and equipment |
|
$ |
51,406 |
|
|
$ |
46,969 |
|
|
|
|
Virginia Power |
|
|
|
|
|
|
|
|
Utility: |
|
|
|
|
|
|
|
|
Generation |
|
$ |
15,193 |
|
|
$ |
14,018 |
|
Transmission |
|
|
5,884 |
|
|
|
4,959 |
|
Distribution |
|
|
9,526 |
|
|
|
9,103 |
|
Nuclear fuel |
|
|
1,411 |
|
|
|
1,375 |
|
General and other |
|
|
697 |
|
|
|
668 |
|
Other-including plant under construction |
|
|
2,464 |
|
|
|
2,719 |
|
Total utility |
|
|
35,175 |
|
|
|
32,842 |
|
Nonutility-other |
|
|
5 |
|
|
|
6 |
|
Total property, plant and equipment |
|
$ |
35,180 |
|
|
$ |
32,848 |
|
|
|
|
Dominion Gas |
|
|
|
|
|
|
|
|
Utility: |
|
|
|
|
|
|
|
|
Transmission |
|
$ |
3,690 |
|
|
$ |
3,407 |
|
Distribution |
|
|
2,530 |
|
|
|
2,333 |
|
Storage |
|
|
1,466 |
|
|
|
1,314 |
|
Gas gathering and processing |
|
|
786 |
|
|
|
783 |
|
General and other |
|
|
111 |
|
|
|
103 |
|
Plant under construction |
|
|
179 |
|
|
|
175 |
|
Total utility |
|
|
8,762 |
|
|
|
8,115 |
|
Nonutility: |
|
|
|
|
|
|
|
|
E&P properties being amortized and other |
|
|
140 |
|
|
|
125 |
|
Total nonutility |
|
|
140 |
|
|
|
125 |
|
Total property, plant and equipment |
|
$ |
8,902 |
|
|
$ |
8,240 |
|
There were no significant E&P properties under development, as defined by the SEC, excluded from
Dominion Gas amortization at December 31, 2014. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into
the amortization calculation.
Jointly-Owned Power Stations
Dominions and Virginia Powers proportionate share of jointly-owned power stations at December 31, 2014 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 |
|
$ |
1,039 |
|
|
$ |
2,426 |
|
|
$ |
573 |
|
|
$ |
1,104 |
|
Accumulated depreciation |
|
|
(542 |
) |
|
|
(1,137 |
) |
|
|
(206 |
) |
|
|
(290 |
) |
Nuclear fuel |
|
|
|
|
|
|
627 |
|
|
|
|
|
|
|
480 |
|
Accumulated amortization of nuclear fuel |
|
|
|
|
|
|
(486 |
) |
|
|
|
|
|
|
(342 |
) |
Plant under construction |
|
|
11 |
|
|
|
114 |
|
|
|
11 |
|
|
|
71 |
|
(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.
Assignments of Marcellus Acreage
In December 2013, DTI closed on agreements with two natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas
storage fields. The agreements provide for payments to DTI, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013, DTI received
approximately $100 million in cash proceeds, resulting in an approximately $20 million ($12 million after-tax) gain, recorded to operations and maintenance expense in Dominion Gas Consolidated Statements of Income. During the twelve months
ended December 31, 2014, DTI received $16 million in additional cash proceeds resulting from post-closing adjustments. At December 31, 2014, deferred revenue totaled approximately $85 million, which is expected to be recognized over the
remaining term of the agreement.
In November 2014, DTI closed an agreement with a natural gas producer to convey over time
approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provides for payments to DTI, subject to customary adjustments, of approximately $120 million over a period of four
years, and an overriding royalty interest in gas produced from the acreage. In November 2014, DTI closed on the agreement and received proceeds of approximately $60 million associated with an initial conveyance of approximately 12,000 acres,
resulting in an approximately $60 million ($36 million after-tax) gain, recorded to operations and maintenance expense in Dominion Gas Consolidated Statements of Income.
In November 2014, DTI signed an agreement with a natural gas producer to convey approximately 11,000 acres of Marcellus
Combined Notes to Consolidated Financial Statements, Continued
Shale development rights underneath one of its natural gas storage fields. The agreement provides for a payment to DTI, subject to customary adjustments, of approximately $27 million, and an
overriding royalty interest in gas produced from the acreage. DTI expects to close on the agreement in March 2015.
NOTE 11. GOODWILL AND INTANGIBLE ASSETS
Goodwill
The changes in
Dominions and Dominion Gas carrying amount and segment allocation of goodwill are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion
Generation |
|
|
Dominion
Energy |
|
|
DVP |
|
|
Corporate and
Other(1) |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2012(2) |
|
$ |
1,503 |
|
|
$ |
701 |
|
|
$ |
926 |
|
|
$ |
|
|
|
$ |
3,130 |
|
Asset disposition adjustment |
|
|
(19 |
)(3) |
|
|
(25 |
)(4) |
|
|
|
|
|
|
|
|
|
|
(44 |
) |
Balance at December 31, 2013(2) |
|
$ |
1,484 |
|
|
$ |
676 |
|
|
$ |
926 |
|
|
$ |
|
|
|
$ |
3,086 |
|
Asset disposition adjustment |
|
|
(32 |
)(3) |
|
|
(10 |
)(4) |
|
|
|
|
|
|
|
|
|
|
(42 |
) |
Balance at December 31,
2014(2) |
|
$ |
1,452 |
|
|
$ |
666 |
|
|
$ |
926 |
|
|
$ |
|
|
|
$ |
3,044 |
|
Dominion Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2012(2) |
|
$ |
|
|
|
$ |
552 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
552 |
|
Asset disposition adjustment |
|
|
|
|
|
|
(7 |
)(4) |
|
|
|
|
|
|
|
|
|
|
(7 |
) |
Balance at December 31, 2013(2) |
|
$ |
|
|
|
$ |
545 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
545 |
|
Asset disposition adjustment |
|
|
|
|
|
|
(3 |
)(4) |
|
|
|
|
|
|
|
|
|
|
(3 |
) |
Balance at December 31,
2014(2) |
|
$ |
|
|
|
$ |
542 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
542 |
|
(1) |
Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.
|
(2) |
Goodwill amounts do not contain any accumulated impairment losses. |
(3) |
See Note 3 for a discussion of Dominions dispositions and related goodwill write-offs. |
(4) |
Related to assets sold or contributed to an affiliate or Blue Racer.
|
Other Intangible Assets
The Companies other intangible assets are subject to amortization over their estimated useful lives. Dominions amortization expense for intangible assets was $71 million, $72 million and $82
million for 2014, 2013 and 2012, respectively. In 2014, Dominion acquired $115 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 15 years. Amortization expense for
Virginia Powers intangible assets was $24 million for 2014 and $22 million each year for 2013 and 2012. In 2014, Virginia Power acquired $45 million of intangible assets, primarily representing software, with an estimated weighted-average
amortization period of 14 years. Dominion Gas amortization expense for intangible assets was $17 million, $16 million and $15 million for 2014, 2013 and 2012, respectively. In 2014, Dominion Gas acquired $8 million of intangible assets,
primarily representing software, with an estimated weighted-average amortization period of approximately 7 years. The components of intangible assets are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 |
|
|
2013 |
|
|
|
Gross
Carrying
Amount |
|
|
Accumulated
Amortization |
|
|
Gross
Carrying Amount |
|
|
Accumulated
Amortization |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Software, licenses and other |
|
$ |
877 |
|
|
$ |
312 |
|
|
$ |
867 |
|
|
$ |
308 |
|
Emissions allowances |
|
|
10 |
|
|
|
5 |
|
|
|
3 |
|
|
|
2 |
|
Total |
|
$ |
887 |
|
|
$ |
317 |
|
|
$ |
870 |
|
|
$ |
310 |
|
|
|
|
|
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Software, licenses and other |
|
$ |
286 |
|
|
$ |
81 |
|
|
$ |
271 |
|
|
$ |
78 |
|
Total |
|
$ |
286 |
|
|
$ |
81 |
|
|
$ |
271 |
|
|
$ |
78 |
|
|
|
|
|
|
Dominion Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Software, licenses and other |
|
$ |
192 |
|
|
$ |
113 |
|
|
$ |
180 |
|
|
$ |
98 |
|
Total |
|
$ |
192 |
|
|
$ |
113 |
|
|
$ |
180 |
|
|
$ |
98 |
|
Annual amortization expense for these intangible assets is estimated to be as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
$ |
72 |
|
|
$ |
67 |
|
|
$ |
58 |
|
|
$ |
45 |
|
|
$ |
36 |
|
|
|
|
|
|
|
Virginia Power |
|
$ |
21 |
|
|
$ |
18 |
|
|
$ |
15 |
|
|
$ |
12 |
|
|
$ |
8 |
|
|
|
|
|
|
|
Dominion Gas |
|
$ |
17 |
|
|
$ |
16 |
|
|
$ |
13 |
|
|
$ |
11 |
|
|
$ |
11 |
|
NOTE 12. REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities include the following:
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014
|
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
Regulatory assets: |
|
|
|
|
|
|
|
|
Deferred rate adjustment clause costs(1) |
|
$
|
124
|
|
|
$ |
89 |
|
Deferred cost of fuel used in electric
generation(2) |
|
|
79 |
|
|
|
|
|
Deferred nuclear refueling outage costs(3) |
|
|
44 |
|
|
|
|
|
Unrecovered gas costs(4) |
|
|
36 |
|
|
|
50 |
|
Other |
|
|
64 |
|
|
|
78 |
|
Regulatory assets-current |
|
|
347 |
|
|
|
217 |
|
Unrecognized pension and other postretirement benefit
costs(5) |
|
|
1,050 |
|
|
|
706 |
|
Deferred rate adjustment clause costs(1) |
|
|
250 |
|
|
|
287 |
|
Income taxes recoverable through future rates(6) |
|
|
133 |
|
|
|
155 |
|
Derivatives(7) |
|
|
101 |
|
|
|
16 |
|
Other |
|
|
108 |
|
|
|
64 |
|
Regulatory assets-non-current |
|
|
1,642
|
|
|
|
1,228 |
|
Total regulatory assets |
|
$ |
1,989
|
|
|
$ |
1,445 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
PIPP(8) |
|
$
|
71
|
|
|
$ |
76 |
|
Other |
|
|
99 |
|
|
|
52 |
|
Regulatory
liabilities-current(9) |
|
|
170 |
|
|
|
128 |
|
Provision for future cost of removal and
AROs(10) |
|
|
1,072 |
|
|
|
1,028 |
|
Nuclear decommissioning trust(11) |
|
|
815 |
|
|
|
693 |
|
Deferred cost of fuel used in electric
generation(2) |
|
|
6 |
|
|
|
90 |
|
Other |
|
|
98 |
|
|
|
190 |
|
Regulatory liabilities-non-current |
|
|
1,991
|
|
|
|
2,001 |
|
Total regulatory liabilities |
|
$ |
2,161 |
|
|
$ |
2,129 |
|
Virginia Power |
|
|
|
|
|
|
|
|
Regulatory assets: |
|
|
|
|
|
|
|
|
Deferred rate adjustment clause costs(1) |
|
$
|
117
|
|
|
$ |
62 |
|
Deferred cost of fuel used in electric
generation(2) |
|
|
79 |
|
|
|
|
|
Deferred nuclear refueling outage costs(3) |
|
|
44 |
|
|
|
|
|
Other |
|
|
58 |
|
|
|
66 |
|
Regulatory assets-current |
|
|
298 |
|
|
|
128 |
|
Deferred rate adjustment clause costs(1) |
|
|
179 |
|
|
|
227 |
|
Derivatives(7) |
|
|
101 |
|
|
|
16 |
|
Income taxes recoverable through future rates(6) |
|
|
100 |
|
|
|
124 |
|
Other |
|
|
59 |
|
|
|
50 |
|
Regulatory assets-non-current |
|
|
439 |
|
|
|
417 |
|
Total regulatory assets |
|
$ |
737 |
|
|
$ |
545 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
Other |
|
$ |
90 |
|
|
$ |
41 |
|
Regulatory liabilities-current |
|
|
90 |
|
|
|
41 |
|
Provision for future cost of removal(10) |
|
|
852 |
|
|
|
807 |
|
Nuclear decommissioning trust(11) |
|
|
815 |
|
|
|
693 |
|
Deferred cost of fuel used in electric
generation(2) |
|
|
6 |
|
|
|
90 |
|
Other |
|
|
10 |
|
|
|
7 |
|
Regulatory liabilities-non-current |
|
|
1,683
|
|
|
|
1,597 |
|
Total regulatory liabilities |
|
$ |
1,773 |
|
|
$ |
1,638 |
|
Dominion Gas |
|
|
|
|
|
|
|
|
Regulatory assets: |
|
|
|
|
|
|
|
|
Unrecovered gas costs(4) |
|
$
|
29
|
|
|
$ |
40 |
|
Deferred rate adjustment clause costs(1) |
|
|
7 |
|
|
|
27 |
|
UEX Rider(12) |
|
|
|
|
|
|
11 |
|
Other |
|
|
2 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014
|
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
Regulatory assets-current |
|
|
38 |
|
|
|
79 |
|
Unrecognized pension and other postretirement benefit
costs(5) |
|
|
242 |
|
|
|
194 |
|
Deferred rate adjustment clause costs(1) |
|
|
71 |
|
|
|
59 |
|
Income taxes recoverable through future rates(6) |
|
|
24 |
|
|
|
24 |
|
Other |
|
|
42 |
|
|
|
8 |
|
Regulatory assets-non-current |
|
|
379 |
|
|
|
285 |
|
Total regulatory assets |
|
$ |
417 |
|
|
$ |
364 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
PIPP(8) |
|
$
|
71
|
|
|
$ |
76 |
|
Other |
|
|
4 |
|
|
|
3 |
|
Regulatory
liabilities-current |
|
|
75 |
|
|
|
79 |
|
Provision for future cost of removal and
AROs(10) |
|
|
172 |
|
|
|
177 |
|
Unrecognized pension and other postretirement benefit
costs(5) |
|
|
|
|
|
|
18 |
|
Other |
|
|
20 |
|
|
|
8 |
|
Regulatory liabilities-non-current |
|
|
192 |
|
|
|
203 |
|
Total regulatory liabilities |
|
$ |
267 |
|
|
$ |
282 |
|
(1) |
Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects for
Virginia Power. Reflects deferrals of costs associated with certain current and prospective rider projects for Dominion Gas. See Note 13 for more information. |
(2) |
Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Dominions and Virginia Powers generation operations. See Note 13 for more
information. For 2014 and 2013, amount includes approximately $5 million related to DOE claims. |
(3) |
Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any
nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months. |
(4) |
Reflects unrecovered gas costs at regulated gas operations, which are recovered through filings with the applicable regulatory authority.
|
(5) |
Represents unrecognized pension and other postretirement employee 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. |
(6) |
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. |
(7) |
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. |
(8) |
Under PIPP, eligible customers can make reduced payments 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. |
(9) |
Current regulatory liabilities are presented in other current liabilities in Dominions Consolidated Balance Sheets. |
(10) |
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. |
(11) |
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 AROs. |
(12) |
Represents East Ohios deferrals for the UEX Rider which are recovered through rates which are filed annually. Most of East Ohios bad debt expense is
recovered either through the UEX Rider or the PIPP Rider. |
|
See Note 13 for more information. |
At December 31, 2014, approximately $218 million of Dominions, $165 million of Virginia
Powers and $45 million of Dominion Gas regulatory assets represented past expenditures on which they do not currently earn a return. The majority of 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, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such
matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible
loss. For matters for which the Companies cannot estimate a range of possible loss, 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 estimate 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. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may 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 the Companies financial position, liquidity or results of operations.
FERCELECTRIC
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities.
Dominions merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominions market-based sales tariffs authorized by FERC. Virginia Power purchases and, under its FERC market-based rate authority, sells
electricity in the wholesale market. 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 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. 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. 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.
In March 2014, FERC issued an order excluding from Virginia Powers transmission rates for
wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable for non-Virginia wholesale transmission customers to be allocated the
incremental costs of undergrounding the facilities because the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to benefit the citizens of Virginia. The order is retroactively effective as of March
2010 and will cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC determined that there was not sufficient evidence on the
record to determine the magnitude of the underground increment and ordered a hearing to determine the appropriate amount of undergrounding cost to be allocated to each wholesale transmission customer in Virginia. While Virginia Power cannot predict
the outcome of the hearing, it is not expected to have a material effect on results of operations.
Other Regulatory Matters
ELECTRIC REGULATION IN VIRGINIA
The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginias planned transition to retail competition for electric
supply service to most classes of customers.
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, and also contains statutory provisions directing Virginia Power to file annual
fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.
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.
2013 Biennial Review
Pursuant to the Regulation Act, in March 2013, Virginia Power submitted its base rate filings and accompanying schedules in support of the Virginia Commissions 2013 biennial review of Virginia
Powers rates, terms and conditions, as well as of Virginia Powers earnings for 2011 and 2012 test periods. The Virginia Power earnings test analysis reviewed by the Virginia Commission reflected an ROE of 10.30% on its generation and
distribution services earnings for the combined test periods.
In November 2013, the Virginia Commission issued its 2013
Biennial Review Order. After deciding eleven contested earnings test adjustments, the Virginia Commission ruled that Virginia Power earned on average an ROE of approximately 10.25% on its generation and distribution services for the combined 2011
and 2012 test periods. Because this ROE was more than 50 basis points below Virginia Powers authorized ROE of 10.9%, the Virginia Commission authorized the deferred recovery, for earnings test purposes, of $23 million in costs related to asset
impairments with early retirement decisions, severe weather events, and natural disasters to be amortized over the 2013 calendar year. The Virginia Commission did not order a base rate increase because Virginia Power had previously waived its right
to any such increase, and because it determined that Virginia Power had a revenue sufficiency of approximately $280 million when projecting the annual revenues generated by base rates to the revenues required to cover costs of service and earn a
fair return. As part of its revenue sufficiency determination, the Virginia Commission also made findings on eleven rate case adjustments, in addition to changes to the cost of capital and capital structure, which resulted in changes to Virginia
Powers rate year revenues and expenses, and Virginia Powers rate base for generation and distribution, for the rate year beginning January 1, 2014. Virginia Power incurred a $55 million ($37 million after-tax) charge in connection
with the 2013 Biennial Review Order.
In its 2013 Biennial Review Order, the Virginia Commission also set the ROE that will be
used in Virginia Powers 2015 biennial review earnings test analysis for earnings on generation and distribution services for the combined 2013 and 2014 test periods, and that will be applied to Riders R, S, W, B, BW, C1A, and C2A. Pursuant to
the Regulation Act, Virginia Powers authorized ROE can be no lower than the average of the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., subject to certain
limitations as described in the Regulation Act. Following this statutory peer group analysis, the Virginia Commission determined that the peer group floor ROE for Virginia Power was 9.89%. It further held, declining to increase or decrease Virginia
Powers combined rate of return based on performance, that Virginia Powers ROE for earnings test purposes in its 2015 biennial review and for rate adjustment clause purposes is 10.0%, consistent with its determination that Virginia
Powers market cost of equity is 10.0%.
Virginia Fuel Expenses
In May 2014, Virginia Power submitted its annual fuel factor filing to the Virginia Commission to recover an estimated $1.9 billion in Virginia jurisdictional projected fuel expenses for the rate year
beginning July 1, 2014. Virginia Power also offered to defer recovery of 50% of its total estimated $268 million jurisdictional deferred fuel balance to the 2015-2016 fuel year, thereby
recovering $134 million of its jurisdictional deferred fuel balance for the rate year beginning July 1, 2014. In September 2014, the Virginia Commission approved Virginia Powers
increased fuel rate, which was already in effect on an interim basis since July 1, 2014. The new rate includes approval of Virginia Powers offer to defer recovery of 50% its jurisdictional deferred fuel balance and represents an annual
fuel revenue increase of approximately $300 million.
Rate Adjustment Clauses
Below is a discussion of significant riders associated with various Virginia Power projects:
|
|
The Virginia Commission previously approved Rider T1. In July 2014, the Virginia Commission approved an approximately $538 million revenue requirement
for the rate year beginning September 1, 2014, which represents an approximately $134 million increase over the previous year. |
|
|
The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2014, Virginia Power proposed
an approximately $244 million revenue requirement for the rate year beginning April 1, 2015. This case is pending. |
|
|
The Virginia Commission previously approved Rider W in conjunction with Warren County. In February 2015, the Virginia Commission approved an
approximately $135 million revenue requirement for the rate year beginning April 1, 2015. |
|
|
The Virginia Commission previously approved Rider BW in connection with Brunswick County. In October 2014, Virginia Power proposed a total revenue
requirement of approximately $111 million for the rate year beginning September 1, 2015. This case is pending. |
|
|
The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In August 2014, Virginia Power
proposed a total revenue requirement of approximately $47 million for the rate year beginning May 1, 2015. Virginia Power further proposed three new energy efficiency programs for Virginia Commission approval with a requested five-year
cost cap of approximately $106 million for those programs. This case is pending. |
|
|
The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In June 2014, Virginia Power proposed an approximately $84 million
revenue requirement for the rate year beginning April 1, 2015. This case is pending. |
|
|
Virginia legislation which provides for the recovery of costs to move certain electric distribution lines underground became effective in July 2014. In
October 2014, Virginia Power filed for approval of Rider U, which proposes a revenue requirement of approximately $28 million during the initial rate year beginning September 1, 2015. This case is pending. |
|
|
The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2014, Virginia Power
proposed an approximately $13 million revenue requirement for the rate year beginning April 1, 2015. This case is pending. |
|
|
In January 2015, Virginia Power applied for a CPCN to construct and operate a new 20 MW utility-scale solar facility near its existing Remington Power
Station in Fauquier County, Virginia. Virginia Power also applied for approval of
|
Combined Notes to Consolidated Financial Statements, Continued
|
Rider US-1 to recover the costs of the facility. The total cost of the Remington Solar Facility is approximately $47 million (excluding financing costs). This case is pending.
|
Brunswick County
In August 2013, three motions for reconsideration were filed with the Virginia Commission, asking that it reconsider its August 2013 final order approving a CPCN for construction of Brunswick County. In
November 2013, the Virginia Commission denied reconsideration. Three appeals were filed with the Supreme Court of Virginia, but two were withdrawn. In September 2014, the Supreme Court of Virginia issued an opinion affirming the Virginia
Commissions decision in the remaining appeal.
Electric Transmission Project
In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV
transmission line from the existing Surry Switching Station in Surry County to a new Skiffes Creek Switching Station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of
Newport News from the proposed new Skiffes Creek Switching Station to Virginia Powers existing Whealton Substation in the City of Hampton. In February 2014, the Virginia Commission granted reconsideration requested by Virginia Power and issued
an Order Amending Certificate. Several appeals were filed with the Supreme Court of Virginia and oral arguments were heard in January 2015. The appeals are pending.
North Anna
Virginia Power is considering the construction of a third nuclear unit at a
site located at North Anna. If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In April 2013, Virginia Power decided to
replace the reactor design previously selected for a potential unit with ESBWR technology. Virginia Power filed the first of its two-part amendment to the COL application with the NRC in July 2013 to reflect the ESBWR technology and filed the second
part of the amendment in December 2013. The COL is expected in 2016. Virginia Power has not yet committed to building a new nuclear unit at North Anna.
In June 2012, the U.S. Court of Appeals for the D.C. Circuit vacated and remanded a 2010 NRC decision and related rulemaking that generically assessed the environmental impacts of spent fuel storage after
expiration of a reactors license until a repository became available. In August 2012, the NRC partially granted a petition filed by BREDL and other petitioners in a number of ongoing licensing proceedings, including the North Anna COL
proceedings, to withhold issuance of licenses until completion of action on the remand, and held proposed contentions accompanying the petition in abeyance. In August 2014, the NRC approved a new final rule codifying the NRCs further generic
assessment of environmental impacts of continued storage of spent fuel and lifted the suspension of final licensing decisions in pending cases and dismissed pending contentions on the subject, including the proposed contention filed by BREDL.
In September 2014, BREDL filed a new petition with the NRC again seeking suspension of
final decision making in the COL proceeding, along with motions to reopen and file a new contention. The new filings assert that the NRC must make a safety finding on the feasibility and capacity of geologic disposal of spent fuel as a prerequisite
to issuance of a license. The filings alleged that because these safety findings are no longer made as part of the NRCs new continued storage rule, such findings must now be made in individual licensing proceedings. In January 2015, BREDL
filed another petition in the COL proceeding asking the NRC to order supplementation of the final environmental impact statement for North Anna 3 to incorporate the NRCs generic assessment of the impacts of continued spent fuel storage, so
that BREDL could then challenge that assessment. BREDLs September 2014 filings and January 2015 petition are substantially the same as filings made by various other intervenor groups in other licensing proceedings pending before the NRC.
Resolution of these filings is not expected to affect the schedule for issuance of the COL.
North Anna and Offshore Wind Legislation
In April 2014, legislation was enacted in Virginia that permits Virginia Power to recover 70% of the costs previously deferred or
capitalized related to the development of a third nuclear unit located at North Anna and offshore wind facilities through December 31, 2013 as part of the 2013 and 2014 base rates. Virginia Power had deferred or capitalized costs totaling
approximately $577 million for these projects as of December 31, 2013, substantially all of which relate to North Anna. For the 70% portion of these previously deferred or capitalized costs allocable to customers in Virginia, Virginia Power
recognized such amounts that are now recoverable in 2013 and 2014 base rates as charges against net income beginning in the second quarter of 2014 and for the remainder of the year. During 2014, Virginia Power recognized $374 million ($248 million
after-tax) in charges against income representing the cumulative recovery of costs from January 2013 through December 2014, which are primarily included in other operations and maintenance expense in the Consolidated Statements of Income. The
remaining deferred or capitalized costs, as well as costs incurred after December 31, 2013, continue to be eligible for inclusion in a future rate adjustment clause.
Regulation Act Legislation
In February 2015, the Virginia Governor signed
legislation into law which will keep Virginia Powers base rates unchanged until at least December 1, 2022. In addition, no biennial reviews will be conducted by the Virginia Commission for the five successive 12-month test periods beginning
January 1, 2015, and ending December 31, 2019. Virginia Power is scheduled to file its next biennial review, covering 2013 and 2014, in March 2015. The legislation allows this review to proceed for the sole purpose of determining whether any refunds
are due to customers based on earnings performance during the 2013 and 2014 test periods. In addition the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utilitys ROE for use in connection
with rate adjustment clauses and requires utilities to file integrated resource plans annually rather
than biennially. The legislation requires Virginia Power to write-off $85 million of prior-period deferred fuel costs during the first quarter of 2015. In addition, the legislation requires the
Virginia Commission to implement a fuel rate reduction for Virginia Power as soon as practicable based on this non-recovery as well as any over-recovery for the 2014-2015 fuel year and projected fuel expense for the 2015-2016 fuel year. The
legislation also deems the construction or purchase of one or more utility-scale solar facilities located in Virginia up to 500 MW in total to be in the public interest.
NORTH CAROLINA REGULATION
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 were appealed to the North Carolina Supreme Court by multiple parties. In June 2014, the Supreme Court of North Carolina issued an opinion reversing the portion
of the North Carolina Commissions December 2012 order from Virginia Powers 2012 base rate case approving a 10.2% ROE for Virginia Power, and remanding the case to the North Carolina Commission for additional findings of fact in light of
a 2013 opinion issued after the North Carolina Commissions order. This case is pending.
In December 2014, the North
Carolina Commission issued an order approving an approximately $17 million increase to the fuel component of Virginia Powers electric rates for the rate year beginning January 1, 2015. This increase includes the approval of Virginia
Powers mitigation proposal to defer recovering 50% of its estimated $17 million jurisdictional deferred fuel balance to the 2016 fuel year, without interest.
OHIO REGULATION
PIR Program
In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In February 2014, East Ohio filed an application requesting
approval to adjust the PIR cost recovery rates for 2013 costs. The filing reflects gross plant investment for 2013 of $164 million, cumulative gross plant investment of $674 million and an estimated revenue requirement of $89 million. This
application was approved by the Ohio Commission in April 2014.
In February 2015, East Ohio filed an application to adjust the
PIR cost recovery for 2014 costs. The filing reflects gross plant investment for 2014 of $155 million, cumulative gross plant investment of $829 million and a revenue requirement of $108 million. This case is pending.
AMR Program
In 2007, East Ohio began
installing automated meter reading technology for its 1.2 million customers in Ohio. In May 2014, AMR cost recovery rates became effective as approved by the Ohio Commission in April 2014. The approval includes a revenue requirement of $8
million, which represents an approximately $3 million increase over the previous year.
In January 2013, East Ohio filed with the Ohio Supreme Court an appeal of a rate reduction
ordered by the Ohio Commission in October 2012 and a motion seeking a stay of the AMR cost recovery rate imposed. The Ohio Supreme Court granted the stay in March 2013 and East Ohio put the higher AMR cost recovery rate filed by East Ohio into
effect. In July 2014, the Ohio Supreme Court ruled in East Ohios favor by agreeing that the rate reduction imposed by the Ohio Commission was unreasonable.
In February 2015, East Ohio filed its application with the Ohio Commission to adjust its AMR cost recovery charge to recover costs for calendar year 2014 associated with AMR deployment, which was
completed in 2012. The filing reflects a projected revenue requirement of approximately $8 million. This case is pending.
The
AMR program approved by the Ohio Commission is now complete. Although no further capital investment will be added, East Ohio is approved to recover depreciation, property taxes, carrying charges and a return until East Ohio has another rate
case.
PIPP Plus Program
Under the Ohio PIPP Plus Program, eligible customers can make reduced payments based on their ability to pay their bill. The difference between the
customers total bill and the PIPP payment plan amount is deferred and collected under the PIPP Rider in accordance with the rules of the Ohio Commission. In July 2014, East Ohios annual update of the PIPP Rider was automatically approved
by the Ohio Commission after a 45-day waiting period from the date of the filing. The increased rider rate reflects the refund over the next year of an over-recovery of accumulated arrearages of approximately $82 million as of March 31,
2014, net of projected deferred program costs of approximately $96 million for the period from April 2014 through June 2015.
UEX Rider
East Ohio has approval for a UEX Rider through which it recovers 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 uncollectible amounts. In July 2014, the Ohio Commission approved a decrease to East Ohios UEX Rider, which reflects the
elimination of the over-recovered balance of accumulated bad debt expense of approximately $8 million as of March 31, 2014, and recovery of prospective bad debt expense projected to total approximately $25 million for the twelve-month period
from April 2014 to March 2015.
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 July 2014, the Ohio Commission approved East Ohios application requesting authority to
Combined Notes to Consolidated Financial Statements, Continued
implement a capital expenditure program for 2014 capital expenditures totaling $110 million.
FERC REGULATION
DTI Fuel Settlement
In mid-2013, DTI received concerns about its fuel retainage percentages and apparent over-recovery of fuel costs during certain time periods reflected in
its annual fuel reports. In December 2013, DTI submitted for FERC approval a stipulation and agreement addressing, among other things, reductions in its fuel retainage percentages and a rate moratorium through 2016. In February 2014, FERC approved
the stipulation and agreement.
The revised fuel retainage percentages became effective January 1, 2014. DTI began
assessing the reduced fuel retainage percentages on March 1, 2014, and as a result provided refunds totaling nearly $10 million. The refunds reflect, with interest, the value of the difference between the actual quantities of fuel retained for
the months of January and February and the quantities that would have been retained using the reduced percentages.
NOTE 14. ASSET RETIREMENT OBLIGATIONS
AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of
the Companies long-lived assets. Dominions and Virginia Powers AROs are primarily associated with the decommissioning of their nuclear generation facilities and also include those for the future abatement of asbestos expected to be
disturbed in their generation facilities. Dominion Gas AROs primarily include plugging and abandonment of gas and oil wells and the interim retirement of natural gas gathering, transmission, distribution and storage pipeline components.
The Companies have also identified, but not recognized, AROs related to retirement of Dominions LNG facility, Dominion
Gas 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 Dominions and Virginia Powers 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 2013 and 2014 were as follows:
|
|
|
|
|
|
|
Amount |
|
(millions) |
|
|
|
Dominion |
|
|
|
|
AROs at December 31, 2012(1) |
|
$ |
1,705 |
|
Obligations incurred during the period |
|
|
13 |
|
Obligations settled during the period |
|
|
(68 |
) |
Revisions in estimated cash flows(2) |
|
|
(129 |
) |
Accretion |
|
|
86 |
|
Other |
|
|
(29 |
) |
AROs at December 31,
2013(1) |
|
$ |
1,578 |
|
Obligations incurred during the period |
|
|
40 |
|
Obligations settled during the period |
|
|
(82 |
) |
Revisions in estimated cash flows(3) |
|
|
102 |
|
Accretion |
|
|
81 |
|
Other |
|
|
(5 |
) |
AROs at December 31,
2014(1) |
|
$ |
1,714 |
|
Virginia Power |
|
|
|
|
AROs at December 31, 2012 |
|
$ |
705 |
|
Obligations incurred during the period |
|
|
2 |
|
Obligations settled during the period |
|
|
(2 |
) |
Revisions in estimated cash flows(2) |
|
|
(52 |
) |
Accretion |
|
|
38 |
|
Other |
|
|
(2 |
) |
AROs at December 31, 2013 |
|
$ |
689 |
|
Obligations incurred during the period |
|
|
28 |
|
Obligations settled during the period |
|
|
(1 |
) |
Revisions in estimated cash flows(3) |
|
|
108 |
|
Accretion |
|
|
37 |
|
Other |
|
|
(6 |
) |
AROs at December 31,
2014(4) |
|
$ |
855 |
|
Dominion Gas |
|
|
|
|
AROs at December 31, 2012 |
|
$ |
133 |
|
Obligations incurred during the period |
|
|
8 |
|
Obligations settled during the period |
|
|
(13 |
) |
Accretion |
|
|
8 |
|
Other |
|
|
1 |
|
AROs at December 31,
2013(5)(6) |
|
$ |
137 |
|
Obligations incurred during the period |
|
|
2 |
|
Obligations settled during the period |
|
|
(8 |
) |
Accretion |
|
|
8 |
|
Other |
|
|
8 |
|
AROs at December 31,
2014(5)(6) |
|
$ |
147 |
|
(1) |
Includes $64 million, $94 million and $81 million reported in other current liabilities at December 31, 2012, 2013, and 2014, respectively.
|
(2) |
Primarily reflects lower anticipated nuclear decommissioning costs. |
(3) |
Relates primarily to a shift of the delayed planned date on which the DOE is expected to begin accepting spent nuclear fuel. |
(4) |
Includes $7 million reported in other current liabilities at December 31, 2014. |
(5) |
Includes $2 million and $7 million reported in other current liabilities at December 31, 2013 and 2014, respectively. |
(6) |
Includes $135 million and $140 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at
December 31, 2013 and 2014, respectively. |
Dominion and Virginia Power have established trusts dedicated to
funding the future decommissioning of their nuclear plants. At December 31, 2014 and 2013, the aggregate fair value of Dominions trusts, consisting primarily of equity and debt securities, totaled $4.2 billion and $3.9 billion,
respectively. At
December 31, 2014 and 2013, the aggregate fair value of Virginia Powers trusts, consisting primarily of debt and equity securities, totaled $1.9 billion and $1.8 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.
Dominion
Through August 2013, Dominion leased the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. In August 2013, the lease expired and
Dominion purchased Fairless for $923 million from Juniper per the terms of the lease agreement. However, as Dominion had previously consolidated Juniper, the purchase was accounted for as an equity transaction to acquire the noncontrolling interests
from Juniper for $923 million, while Dominion retained control of Fairless. The acquisition resulted in the removal of securities due within one year-VIE and noncontrolling interests from Dominions Consolidated Balance Sheet during 2013.
Dominion has an initial 45% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the nature
of this entity. Dominion concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion has concluded that it is not the primary beneficiary of
Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. Dominion is
obligated to provide capital contributions based on its ownership percentage. Dominions maximum exposure to loss is limited to its current and future investment.
Dominion Gas
DTI has been engaged to oversee the construction of, and to subsequently operate and
maintain, the projects undertaken by Atlantic Coast Pipeline based on the overall direction and oversight of Atlantic Coast Pipelines members. An affiliate of DTI holds a membership interest in Atlantic Coast Pipeline, therefore DTI is
considered to have a variable interest in Atlantic Coast Pipeline. The members of Atlantic Coast Pipeline hold the power to direct the construction, operations and maintenance activities of the entity. DTI has concluded it is not the primary
beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance. DTI has no obligation to absorb any losses of the VIE. See Note 24 for
information about associated related party receivable balances.
Virginia Power
Virginia Power has long-term power and capacity contracts with five 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 $639 million as of December 31, 2014. Virginia Power paid $223 million, $217 million, and $214 million for electric capacity and $138 million, $98 million, and $83 million for electric energy to
these entities for the years ended December 31, 2014, 2013 and 2012, respectively.
Virginia Power and Dominion Gas
Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of approximately $335 million and $106 million, $331 million and
$115 million, and $328 million and $107 million for the years ended December 31, 2014, 2013 and 2012, respectively. Virginia Power and Dominion Gas determined that each is not the most closely associated entity with DRS and therefore neither is
the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power and Dominion Gas. Virginia Power and Dominion Gas have no obligation to absorb
more than their allocated shares of DRS costs.
NOTE 16. SHORT-TERM DEBT AND CREDIT
AGREEMENTS
The Companies 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Facility Limit |
|
|
Outstanding Commercial Paper |
|
|
Outstanding Letters of Credit |
|
|
Facility Capacity Available |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(1) |
|
$ |
4,000 |
|
|
$ |
2,664 |
|
|
$ |
|
|
|
$ |
1,336 |
|
Joint revolving credit
facility(2) |
|
|
500 |
|
|
|
111 |
|
|
|
48 |
|
|
|
341 |
|
Total |
|
$ |
4,500 |
|
|
$ |
2,775 |
(3) |
|
$ |
48 |
|
|
$ |
1,677 |
|
At December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(1) |
|
$ |
3,000 |
|
|
$ |
1,927 |
|
|
$ |
|
|
|
$ |
1,073 |
|
Joint revolving credit
facility(2) |
|
|
500 |
|
|
|
|
|
|
|
11 |
|
|
|
489 |
|
Total |
|
$ |
3,500 |
|
|
$ |
1,927 |
(3) |
|
$ |
11 |
|
|
$ |
1,562 |
|
(1) |
In May 2014, this credit facility was amended and restated. The facility limit was increased from $3 billion to $4 billion and the maturity date was extended from
September 2018 to April 2019. 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) |
In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. 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 0.38% and 0.33% at December 31, 2014
and 2013, respectively. |
Virginia Power
Virginia Powers short-term financing is supported by two joint revolving credit facilities with Dominion and Dominion Gas. These credit facilities are being used for working capital, as support for
the combined commercial paper programs of the Companies 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 and Dominion Gas were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Facility Sub-limit |
|
|
Outstanding Commercial Paper |
|
|
Outstanding Letters of Credit |
|
|
Facility Sub-limit Capacity Available
|
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(1) |
|
$ |
1,250 |
|
|
$ |
1,250 |
|
|
$ |
|
|
|
$ |
|
|
Joint revolving credit
facility(2) |
|
|
250 |
|
|
|
111 |
|
|
|
|
|
|
|
139 |
|
Total |
|
$ |
1,500 |
|
|
$ |
1,361 |
(3) |
|
$ |
|
|
|
$ |
139 |
|
At December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(1) |
|
$ |
1,000 |
|
|
$ |
842 |
|
|
$ |
|
|
|
$ |
158 |
|
Joint revolving credit
facility(2) |
|
|
250 |
|
|
|
|
|
|
|
1 |
|
|
|
249 |
|
Total |
|
$ |
1,250 |
|
|
$ |
842 |
(3) |
|
$ |
1 |
|
|
$ |
407 |
|
(1) |
In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. 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. In July 2014, Virginia Power increased its sub-limit from $1.0 billion to $1.25 billion. In January 2015, Virginia Power
increased its sub-limit on this facility from $1.25 billion to $1.5 billion. |
(2) |
In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. 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 0.36% and 0.33% at December 31, 2014 and 2013,
respectively. |
In addition to the credit facility commitments mentioned above, Virginia Power also has a $120
million credit facility. In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. As of December 31, 2014, this facility supports approximately $119 million of certain
variable rate tax-exempt financings of Virginia Power.
Dominion Gas
Dominion Gass short-term financing is supported by the two joint revolving credit facilities discussed above with Dominion and Virginia Power, to which Dominion Gas was added as a borrower in May
2014. Dominion Gas current sub-limit under the $4 billion credit facility is $500 million, all of which was available at December 31, 2014, and can be increased or decreased multiple times per year, up to a maximum of $1 billion. Dominion
Gas current sub-limit under the $500 million credit facility is $0 and can also be increased or decreased multiple times per year. The maturity date for both facilities is April 2019. In December 2014, Dominion Gas entered into a commercial
paper program pursuant to which it began accessing the commercial paper markets in January 2015. Dominion Gas current sub-limit under the $4 billion credit facility of $500 million is being used to support these commercial paper issuances.
NOTE 17. LONG-TERM DEBT
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 Weighted-
average Coupon(1) |
|
|
2014 |
|
|
2013 |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
Dominion Gas Holdings, LLC: |
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
1.05% and 2.5%, due 2016 and 2019 |
|
|
1.82 |
% |
|
$ |
850 |
|
|
$ |
400 |
|
3.55% to 4.8%, due 2023 to 2044 |
|
|
4.15 |
% |
|
|
1,750 |
|
|
|
800 |
|
Dominion Gas Holdings, LLC total principal |
|
|
|
|
|
$ |
2,600 |
|
|
$ |
1,200 |
|
Unamortized discount |
|
|
|
|
|
|
(6 |
) |
|
|
(2 |
) |
Dominion Gas Holdings, LLC total long-term debt |
|
|
|
|
|
$ |
2,594 |
|
|
$ |
1,198 |
|
Virginia Electric and Power Company: |
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
1.2% to 8.625%, due 2015 to 2019 |
|
|
5.06 |
% |
|
$ |
2,471 |
|
|
$ |
2,488 |
|
2.75% to 8.875%, due 2022 to 2044 |
|
|
5.07 |
% |
|
|
5,592 |
|
|
|
4,643 |
|
Tax-Exempt Financings(2): |
|
|
|
|
|
|
|
|
|
|
|
|
Variable rates, due 2016 to 2041 |
|
|
0.93 |
% |
|
|
606 |
|
|
|
606 |
|
0.70% to 5.6%, due 2022 to 2040 |
|
|
2.86 |
% |
|
|
266 |
|
|
|
306 |
|
Virginia Electric and Power Company total principal |
|
|
|
|
|
$ |
8,935 |
|
|
$ |
8,043 |
|
Securities due within one year |
|
|
5.39 |
% |
|
|
(211 |
) |
|
|
(58 |
) |
Unamortized discount and premium, net |
|
|
|
|
|
|
2 |
|
|
|
(11 |
) |
Virginia Electric and Power Company total long-term debt |
|
|
|
|
|
$ |
8,726 |
|
|
$ |
7,974 |
|
Dominion Resources, Inc.: |
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
Variable rates, due 2014 and 2015 |
|
|
0.36 |
% |
|
$ |
400 |
|
|
$ |
400 |
|
1.25% to 8.875%, due 2014 to 2019 |
|
|
3.17 |
% |
|
|
3,150 |
|
|
|
4,391 |
|
2.75% to 7.0%, due 2021 to 2044(3) |
|
|
4.93 |
% |
|
|
4,449 |
|
|
|
3,499 |
|
Unsecured Convertible Senior Notes, 2.125%, due 2023 |
|
|
|
|
|
|
|
|
|
|
43 |
|
Tax-Exempt Financing, variable rate, due 2041 |
|
|
1.10 |
% |
|
|
75 |
|
|
|
75 |
|
Unsecured Junior Subordinated Notes Payable to Affiliated Trust, 8.4%, due 2031 |
|
|
8.40 |
% |
|
|
10 |
|
|
|
10 |
|
Enhanced Junior Subordinated Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
5.75% to 8.375%, due 2054 to 2066 |
|
|
6.28 |
% |
|
|
985 |
|
|
|
985 |
|
Variable rate, due 2066 |
|
|
2.54 |
% |
|
|
380 |
|
|
|
380 |
|
Remarketable Subordinated Notes, 1.07% to 1.50%, due 2019 to 2021 |
|
|
1.30 |
% |
|
|
2,100 |
|
|
|
1,100 |
|
Unsecured Debentures and Senior Notes(4): |
|
|
|
|
|
|
|
|
|
|
|
|
5.0% due 2014 |
|
|
|
|
|
|
|
|
|
|
600 |
|
6.8% and 6.875%, due 2026 and 2027 |
|
|
6.81 |
% |
|
|
89 |
|
|
|
89 |
|
Dominion Energy, Inc.: |
|
|
|
|
|
|
|
|
|
|
|
|
Tax-Exempt Financing, 2.375%, due 2033 |
|
|
2.38 |
% |
|
|
27 |
|
|
|
27 |
|
Dominion Gas Holdings, LLC total principal (from above) |
|
|
|
|
|
|
2,600 |
|
|
|
1,200 |
|
Virginia Electric and Power Company total principal (from above) |
|
|
|
|
|
|
8,935 |
|
|
|
8,043 |
|
Dominion Resources, Inc. total principal |
|
|
|
|
|
$ |
23,200 |
|
|
$ |
20,842 |
|
Fair value hedge valuation(5) |
|
|
|
|
|
|
19 |
|
|
|
55 |
|
Securities due within one year(6) |
|
|
3.30 |
% |
|
|
(1,375 |
) |
|
|
(1,519 |
) |
Unamortized discount and premium, net |
|
|
|
|
|
|
(39 |
) |
|
|
(48 |
) |
Dominion Resources, Inc. total long-term debt |
|
|
|
|
|
$ |
21,805 |
|
|
$ |
19,330 |
|
(1) |
Represents weighted-average coupon rates for debt outstanding as of December 31, 2014. |
(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 April 2019. |
(3) |
At the option of holders, $510 million of Dominions 5.25% senior notes due 2033 are subject to redemption at 100% of the principal amount plus accrued interest
in August 2015. As a result, at December 31, 2014, the notes were included in Securities due within one year in the Consolidated Balance Sheets. |
(4) |
Represents debt assumed by Dominion from the merger of its former CNG subsidiary. |
(5) |
Represents the valuation of certain fair value hedges associated with Dominions fixed rate debt. |
(6) |
Includes $4 million fair value hedge valuation in 2014 and $14 million of fair value hedge valuation in 2013. |
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, 2014, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Gas |
|
$ |
|
|
|
$ |
400 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
450 |
|
|
$ |
1,750 |
|
|
$ |
2,600 |
|
Weighted-average Coupon |
|
|
|
|
|
|
1.05 |
% |
|
|
|
|
|
|
|
|
|
|
2.50 |
% |
|
|
4.15 |
% |
|
|
|
|
Virginia Power |
|
$ |
211 |
|
|
$ |
476 |
|
|
$ |
679 |
|
|
$ |
850 |
|
|
$ |
350 |
|
|
$ |
6,369 |
|
|
$ |
8,935 |
|
Weighted-average Coupon |
|
|
5.39 |
% |
|
|
5.24 |
% |
|
|
5.43 |
% |
|
|
4.17 |
% |
|
|
5.00 |
% |
|
|
4.64 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured Senior Notes(1) |
|
$ |
861 |
|
|
$ |
1,308 |
|
|
$ |
1,354 |
|
|
$ |
1,350 |
|
|
$ |
2,000 |
|
|
$ |
11,878 |
|
|
$ |
18,751 |
|
Tax-Exempt Financings |
|
|
|
|
|
|
19 |
|
|
|
75 |
|
|
|
|
|
|
|
|
|
|
|
880 |
|
|
|
974 |
|
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
10 |
|
Enhanced Junior Subordinated Notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,365 |
|
|
|
1,365 |
|
Remarketable Subordinated Notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
550 |
|
|
|
1,550 |
|
|
|
2,100 |
|
Total |
|
$ |
861 |
|
|
$ |
1,327 |
|
|
$ |
1,429 |
|
|
$ |
1,350 |
|
|
$ |
2,550 |
|
|
$ |
15,683 |
|
|
$ |
23,200 |
|
Weighted-average Coupon |
|
|
2.14 |
% |
|
|
2.86 |
% |
|
|
3.27 |
% |
|
|
4.99 |
% |
|
|
3.09 |
% |
|
|
4.39 |
% |
|
|
|
|
(1) |
At the option of holders, $510 million of Dominions 5.25% senior notes due 2033 are subject to redemption at 100% of the principal amount plus accrued interest
in August 2015. As a result, at December 31, 2014, the notes were included in Securities due within one year in the Consolidated Balance Sheets. |
The Companies short-term credit facilities and long-term debt agreements contain
customary covenants and default provisions. As of December 31, 2014, there were no events of default under these covenants.
Senior Note
Redemptions
As part of Dominions Liability Management Exercise, in December 2014, Dominion redeemed the following outstanding series
of senior notes: 2005 Series C 5.15% Senior Notes due 2015, 2004 Series A 5.20% Senior Notes due 2016, 2006 Series A 5.60% Senior Notes due 2016, 2007 Series A 6.0% Senior Notes due 2017, and 2008 Series D 8.875% Senior Notes due 2019 with an
aggregate outstanding principal of approximately $1.9 billion. The aggregate redemption price paid in December 2014 was approximately $2.2 billion and represents the principal amount outstanding, accrued and unpaid interest and the applicable
make-whole premium of $263 million. Total charges for the Liability Management Exercise of $284 million, including the make-whole premium, were recognized and recorded in interest expense in Dominions Consolidated Statements of Income.
Proceeds from Dominions issuance of senior notes in November 2014 were used to offset the payment of the redemption price. Also see Convertible Securities called for redemption below.
Convertible Securities
As part of Dominions Liability Management Exercise, in November 2014,
Dominion provided notice to redeem all $22 million of outstanding contingent convertible senior notes. The senior notes were eligible for conversion during any calendar quarter when the closing price of Dominions common stock was equal to or
higher than 120% of the conversion price for at least 20 out of the last 30 consecutive trading days of the preceding quarter, when the notes were called for redemption by Dominion and upon the occurrence of certain other conditions. During 2014,
the senior notes were eligible for conversion. During the first, second and third quarters of 2014, approximately $21 million of the notes were converted by holders into $23 million of common stock. In lieu of redemption, holders elected to convert
the remaining $22 million of notes in December 2014 into $26 million of common stock. Proceeds from Dominions issuance of senior notes in November 2014 were used to offset the portion of
the conversions paid in cash. At December 31, 2014, all of the senior notes have been converted and none remain outstanding.
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 January 2013, Dominion repaid its $258 million 7.83% unsecured junior subordinated debentures and redeemed all 250 thousand
units of the $250 million 7.83% Dominion Resources Capital Trust I capital securities due December 1, 2027. The securities were redeemed at a price of $1,019.58 per capital security plus accrued and unpaid distributions.
Interest charges related to Dominions junior subordinated notes payable to affiliated trusts were $1 million for the years ended
December 31, 2014 and 2013 and $21 million for the year ended December 31, 2012.
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 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. The September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset
quarterly.
In June 2009, Dominion issued $685 million of 8.375% June 2009 hybrids. The June
2009 hybrids were listed on the NYSE under the symbol DRU.
In October 2014, Dominion issued $685 million of October 2014
hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly.
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 the June 2006 hybrids, the September 2006 hybrids, and the June 2009 hybrids. 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. In July 2014, Dominion amended the RCC of the June 2009 hybrids to expand the measurement period for consideration of proceeds from the sale of
common stock or other equity-like 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 2012, Dominion launched a tender offer to purchase up to $150 million of September 2006 hybrids. Dominion purchased and canceled
approximately $88 million of the September 2006 hybrids primarily as a result of this tender offer, which expired in
2012. As part of Dominions Liability Management Exercise, in October 2014, Dominion redeemed all $685 million of the June 2009 hybrids plus accrued interest with the net proceeds from the
issuance of the October 2014 hybrids. The redemption and all purchases were conducted in compliance with the RCCs.
Remarketable Subordinated Notes
In June 2013, Dominion issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B 6% Equity Units,
initially in the form of Corporate Units. In July 2014, Dominion issued $1 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbols DCUA, DCUB and DCUC,
respectively.
Each Corporate Unit consists of a stock purchase contract and 1/20 interest in a RSN issued by Dominion. The
stock purchase contracts obligate the holders to purchase shares of Dominion common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is $50 per Corporate Unit
and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion common stock near the settlement date. The RSNs are pledged as collateral to secure the purchase of common stock under the
related stock purchase contracts.
Dominion makes quarterly interest payments on the RSNs and quarterly contract adjustment
payments on the stock purchase contracts, at the rates described below. Dominion may defer payments on the stock purchase contracts and the RSNs for one or more consecutive periods but generally not beyond the purchase contract settlement date. If
payments are deferred, Dominion may not make any cash distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. 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 RSNs.
Dominion has recorded the present value of the stock purchase contract payments as a liability offset by a charge to equity. Interest
payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS,
Dominion applies the treasury stock method to the Equity Units.
Under the terms of the
stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion will issue between 8.4 million and 9.9 million shares of its common stock in both April 2016 and July 2016 and between 11.5 million and
14.3 million shares in July 2017. A total of 40.3 million shares of Dominions common stock has been reserved for issuance in connection with the stock purchase contracts.
Selected information about Dominions Equity Units is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance Date |
|
Units Issued |
|
|
Total Net Proceeds |
|
|
Total Long-term Debt |
|
|
RSN Annual Interest Rate |
|
|
Stock Purchase Contract Annual Rate |
|
|
Stock Purchase Contract Liability(1) |
|
|
Stock Purchase Settlement Date |
|
|
RSN Maturity Date |
|
(millions, except interest rates) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6/7/2013 |
|
|
11 |
|
|
$ |
533.5 |
|
|
$ |
550.0 |
|
|
|
1.070 |
% |
|
|
5.055 |
% |
|
$ |
76.7 |
|
|
|
4/1/2016 |
|
|
|
4/1/2021 |
|
6/7/2013 |
|
|
11 |
|
|
$ |
553.5 |
|
|
$ |
550.0 |
|
|
|
1.180 |
% |
|
|
4.820 |
% |
|
$ |
79.3 |
|
|
|
7/1/2016 |
|
|
|
7/1/2019 |
|
7/1/2014 |
|
|
20 |
|
|
$ |
982.0 |
|
|
$ |
1,000.0 |
|
|
|
1.500 |
% |
|
|
4.875 |
% |
|
$ |
142.8 |
|
|
|
7/1/2017 |
|
|
|
7/1/2020 |
|
(1) |
Payments of $66 million and $17 million were made in 2014 and 2013, respectively. The stock purchase contract liability was $216 million and $139 million at
December 31, 2014 and 2013, respectively. |
Combined Notes to Consolidated Financial Statements, Continued
Dominion Gas Financing
In June 2014, Dominion Gas commenced an offer to exchange $1.2 billion principal amount of unsecured senior notes that were issued in a private placement in October 2013. The exchange offer satisfied
Dominion Gas obligations under a registration rights agreement entered into in connection with the issuance of the Dominion Gas 2013 Senior Notes. The exchange offer did not represent a new financing transaction and there were no proceeds to
Dominion Gas when the offer settled in August 2014.
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, 2014 or 2013.
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, 2013.
During 2014, Virginia Power redeemed all outstanding series of its preferred stock. Upon redemption, each series was no longer
outstanding for any purpose and dividends ceased to accumulate. Presented below is a summary of the preferred stock redemptions:
|
|
|
|
|
|
|
|
|
Dividend |
|
Total Shares |
|
|
Redemption Price
per Share |
|
|
|
(thousands) |
|
$5.00 |
|
|
107 |
|
|
$ |
112.50 |
(1) |
4.04 |
|
|
13 |
|
|
|
102.27 |
(1) |
4.20 |
|
|
15 |
|
|
|
102.50 |
(1) |
4.12 |
|
|
32 |
|
|
|
103.73 |
(1) |
4.80 |
|
|
73 |
|
|
|
101.00 |
(1) |
7.05 |
|
|
500 |
|
|
|
100.00 |
(1) |
6.98 |
|
|
600 |
|
|
|
100.00 |
(1) |
Flex Money Market Preferred 12/02, Series A |
|
|
1,250 |
|
|
|
100.00 |
(2) |
Total |
|
|
2,590 |
|
|
|
|
|
(1) |
As part of Dominions Liability Management Exercise, in September 2014, Virginia Power provided irrevocable notice to redeem all shares outstanding for each
series of preferred stock. In October 2014, the stock was redeemed at the applicable price per share plus accumulated and unpaid dividends. |
(2) |
In February 2014, Virginia Power provided irrevocable notice to redeem the stock. In March 2014, the stock was redeemed at the applicable price per share plus
accumulated and unpaid dividends at a rate reset in March 2011 of 6.12%. Dividends ceased accumulating on the stock upon payment of the redemption price, thus the rate was not reset in March 2014. |
NOTE 19. 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 2014, Dominion began purchasing its common stock on the open market for these plans. In April 2014, Dominion began issuing new common shares for these direct stock
purchase plans.
During 2014, Dominion issued approximately 3.8 million shares of common stock
through various programs. Dominion received cash proceeds of $205 million from the issuance of 2.9 million of such shares through Dominion Direct and employee savings plans.
In December 2014, Dominion filed an SEC shelf registration for the sale of debt and equity securities including the ability to sell
common stock through an at-the-market program. Also in December 2014, Dominion entered into four separate sales agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate
amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion and the sales agents and in
conformance with applicable securities laws. At December 31, 2014, a total of 7 million shares of Dominions common stock was reserved for issuance in connection with this program. In 2015, Dominion provided sales instructions to one
of the sales agents and has issued 2.7 million shares through at-the-market issuances and received cash proceeds of $207 million, net of fees and commissions paid of $2 million. Following these issuances, Dominion has the ability to issue up to $291
million of stock under the 2014 sales agency agreements.
VIRGINIA POWER
In 2014, 2013 and 2012, Virginia Power did not issue any shares of its common stock to Dominion.
DOMINION GAS
On September 30, 2013, Dominion contributed its
wholly-owned subsidiaries DTI, East Ohio and Dominion Iroquois to Dominion Gas in exchange for 100% of its limited liability company membership interests.
Shares Reserved for Issuance
At December 31, 2014, Dominion had approximately 56 million shares reserved and available for issuance for Dominion
Direct®, employee stock awards, employee savings plans, director stock compensation plans, an at-the-market
program and issuance in connection with stock purchase contracts. See Note 17 for more information.
Repurchase of Common Stock
Dominion did not repurchase any shares in 2014 or 2013 and does not plan to repurchase shares during 2015, except for shares tendered by employees to
satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization.
Combined Notes to Consolidated Financial Statements, Continued
Accumulated Other Comprehensive Income (Loss)
Presented in the table below is a summary of AOCI by component:
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
Dominion |
|
|
|
|
|
|
|
|
Net deferred losses on derivatives-hedging activities, net of tax of $116 and $196 |
|
$ |
(178 |
) |
|
$ |
(288 |
) |
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(333) and $(307) |
|
|
548 |
|
|
|
474 |
|
Net unrecognized pension and other postretirement benefit costs, net of tax of $530 and $365 |
|
|
(782 |
) |
|
|
(510 |
) |
Other comprehensive loss from equity method investees, net of tax of $3 and $ |
|
|
(4 |
) |
|
|
|
|
Total AOCI |
|
$ |
(416 |
) |
|
$ |
(324 |
) |
Virginia Power |
|
|
|
|
|
|
|
|
Net deferred losses on derivatives-hedging activities, net of tax of $4 and $ |
|
$ |
(7 |
) |
|
$ |
|
|
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(35) and
$(30) |
|
|
57 |
|
|
|
48 |
|
Total AOCI |
|
$ |
50 |
|
|
$ |
48 |
|
Dominion Gas |
|
|
|
|
|
|
|
|
Net deferred gains (losses) on derivatives-hedging activities, net of tax of $11 and $(1) |
|
$ |
(20 |
) |
|
$ |
3 |
|
Net unrecognized pension and other postretirement benefit costs, net of tax of $46 and
$43 |
|
|
(66 |
) |
|
|
(61 |
) |
Total AOCI |
|
$ |
(86 |
) |
|
$ |
(58 |
) |
DOMINION
The following table presents Dominions changes in AOCI by component, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred gains and losses on derivatives- hedging activities |
|
|
Unrealized
gains and losses on investment securities |
|
|
Unrecognized pension and other postretirement benefit costs |
|
|
Other comprehensive loss from
equity method investees |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
|
$ |
(288 |
) |
|
$ |
474 |
|
|
$ |
(510 |
) |
|
$ |
|
|
|
$ |
(324 |
) |
Other comprehensive income before reclassifications: gains (losses) |
|
|
17 |
|
|
|
128 |
|
|
|
(305 |
) |
|
|
(4 |
) |
|
|
(164 |
) |
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) |
|
|
93 |
|
|
|
(54 |
) |
|
|
33 |
|
|
|
|
|
|
|
72 |
|
Net current period other comprehensive income (loss) |
|
|
110 |
|
|
|
74 |
|
|
|
(272 |
) |
|
|
(4 |
) |
|
|
(92 |
) |
Ending balance |
|
$ |
(178 |
) |
|
$ |
548 |
|
|
$ |
(782 |
) |
|
$ |
(4 |
) |
|
$ |
(416 |
) |
Year Ended December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
|
$ |
(122 |
) |
|
$ |
326 |
|
|
$ |
(1,081 |
) |
|
$ |
|
|
|
$ |
(877 |
) |
Other comprehensive income before reclassifications: gains (losses) |
|
|
(243 |
) |
|
|
203 |
|
|
|
516 |
|
|
|
|
|
|
|
476 |
|
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) |
|
|
77 |
|
|
|
(55 |
) |
|
|
55 |
|
|
|
|
|
|
|
77 |
|
Net current period other comprehensive income (loss) |
|
|
(166 |
) |
|
|
148 |
|
|
|
571 |
|
|
|
|
|
|
|
553 |
|
Ending balance |
|
$ |
(288 |
) |
|
$ |
474 |
|
|
$ |
(510 |
) |
|
$ |
|
|
|
$ |
(324 |
) |
(1) |
See table below for details about these reclassifications.
|
The following table presents Dominions reclassifications out of AOCI by component:
|
|
|
|
|
|
|
Details about AOCI components |
|
Amounts reclassified from AOCI |
|
|
Affected line item in the Consolidated Statements of Income |
(millions) |
|
|
|
|
|
Year Ended December 31, 2014 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
|
$ |
130 |
|
|
Operating revenue |
|
|
|
13 |
|
|
Purchased gas |
|
|
|
(7 |
) |
|
Electric fuel and other energy-related purchases |
Interest rate contracts |
|
|
16 |
|
|
Interest and related charges |
Total |
|
|
152 |
|
|
|
Tax |
|
|
(59 |
) |
|
Income tax expense |
Total, net of tax |
|
$ |
93 |
|
|
|
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
|
Realized (gain) loss on sale of securities |
|
$ |
(100 |
) |
|
Other income |
Impairment |
|
|
13 |
|
|
Other income |
Total |
|
|
(87 |
) |
|
|
Tax |
|
|
33 |
|
|
Income tax expense |
Total, net of tax |
|
$ |
(54 |
) |
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Prior-service costs (credits) |
|
$ |
(12 |
) |
|
Other operations and maintenance |
Actuarial losses |
|
|
69 |
|
|
Other operations and maintenance |
Total |
|
|
57 |
|
|
|
Tax |
|
|
(24 |
) |
|
Income tax expense |
Total, net of tax |
|
$ |
33 |
|
|
|
Year Ended December 31, 2013 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
|
$ |
58 |
|
|
Operating revenue |
|
|
|
47 |
|
|
Purchased gas |
|
|
|
10 |
|
|
Electric fuel and other energy-related purchases |
Interest rate contracts |
|
|
15 |
|
|
Interest and related charges |
Total |
|
|
130 |
|
|
|
Tax |
|
|
(53 |
) |
|
Income tax expense |
Total, net of tax |
|
$ |
77 |
|
|
|
|
|
|
|
|
|
|
Details about AOCI components |
|
Amounts reclassified from AOCI |
|
|
Affected line item in the Consolidated Statements of Income |
(millions) |
|
|
|
|
|
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
|
Realized (gain) loss on sale of securities |
|
$ |
(98 |
) |
|
Other income |
Impairment |
|
|
8 |
|
|
Other income |
Total |
|
|
(90 |
) |
|
|
Tax |
|
|
35 |
|
|
Income tax expense |
Total, net of tax |
|
$ |
(55 |
) |
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Prior-service costs (credits) |
|
$ |
(8 |
) |
|
Other operations and maintenance |
Actuarial losses |
|
|
102 |
|
|
Other operations and maintenance |
Total |
|
|
94 |
|
|
|
Tax |
|
|
(39 |
) |
|
Income tax expense |
Total, net of tax |
|
$ |
55 |
|
|
|
Combined Notes to Consolidated Financial Statements, Continued
VIRGINIA POWER
The following table presents Virginia Powers changes in AOCI by component, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred gains and losses
on derivatives- hedging activities |
|
|
Unrealized gains and losses on investment securities |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
|
$ |
|
|
|
$ |
48 |
|
|
$ |
48 |
|
Other comprehensive income before reclassifications: gains (losses) |
|
|
(4 |
) |
|
|
15 |
|
|
|
11 |
|
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) |
|
|
(3 |
) |
|
|
(6 |
) |
|
|
(9 |
) |
Net current period other comprehensive income (loss) |
|
|
(7 |
) |
|
|
9 |
|
|
|
2 |
|
Ending balance |
|
$ |
(7 |
) |
|
$ |
57 |
|
|
$ |
50 |
|
Year Ended December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
|
$ |
(6 |
) |
|
$ |
31 |
|
|
$ |
25 |
|
Other comprehensive income before reclassifications: gains (losses) |
|
|
6 |
|
|
|
20 |
|
|
|
26 |
|
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) |
|
|
|
|
|
|
(3 |
) |
|
|
(3 |
) |
Net current period other comprehensive income (loss) |
|
|
6 |
|
|
|
17 |
|
|
|
23 |
|
Ending balance |
|
$ |
|
|
|
$ |
48 |
|
|
$ |
48 |
|
(1) |
See table below for details about these reclassifications.
|
The following table presents Virginia Powers reclassifications out of AOCI by
component:
|
|
|
|
|
|
|
Details about AOCI components |
|
Amounts
reclassified from AOCI |
|
|
Affected line item in the Consolidated Statements
of Income |
(millions) |
|
|
|
|
|
Year Ended December 31, 2014 |
|
|
|
|
|
|
(Gains) losses on cash flow hedges: |
|
|
|
|
|
|
Commodity contracts |
|
$ |
(5 |
) |
|
Electric fuel and other energy related purchases |
Total |
|
|
(5 |
) |
|
|
Tax |
|
|
2 |
|
|
Income tax expense |
Total, net of tax |
|
$ |
(3 |
) |
|
|
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
|
Realized (gain) loss on sale of securities |
|
$ |
(10 |
) |
|
Other income |
Total |
|
|
(10 |
) |
|
|
Tax |
|
|
4 |
|
|
Income tax expense |
Total, net of tax |
|
$ |
(6 |
) |
|
|
Year Ended December 31, 2013 |
|
|
|
|
|
|
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
|
Realized (gain) loss on sale of securities |
|
$ |
(6 |
) |
|
Other income |
Impairment |
|
|
1 |
|
|
Other income |
Total |
|
|
(5 |
) |
|
|
Tax |
|
|
2 |
|
|
Income tax expense |
Total, net of tax |
|
$ |
(3 |
) |
|
|
DOMINION GAS
The following table presents Dominion Gas changes in AOCI by component, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred gains and losses on derivatives- hedging activities |
|
|
Unrecognized
pension and other postretirement benefit costs |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
|
$ |
3 |
|
|
$ |
(61 |
) |
|
$ |
(58 |
) |
Other comprehensive income before reclassifications: gains (losses) |
|
|
(31 |
) |
|
|
(10 |
) |
|
|
(41 |
) |
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) |
|
|
8 |
|
|
|
5 |
|
|
|
13 |
|
Net current period other comprehensive income (loss) |
|
|
(23 |
) |
|
|
(5 |
) |
|
|
(28 |
) |
Ending balance |
|
$ |
(20 |
) |
|
$ |
(66 |
) |
|
$ |
(86 |
) |
Year Ended December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
|
$ |
(47 |
) |
|
$ |
(93 |
) |
|
$ |
(140 |
) |
Other comprehensive income before reclassifications: gains (losses) |
|
|
39 |
|
|
|
26 |
|
|
|
65 |
|
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1) |
|
|
11 |
|
|
|
6 |
|
|
|
17 |
|
Net current period other comprehensive income (loss) |
|
|
50 |
|
|
|
32 |
|
|
|
82 |
|
Ending balance |
|
$ |
3 |
|
|
$ |
(61 |
) |
|
$ |
(58 |
) |
(1) |
See table below for details about these reclassifications.
|
The following table presents Dominion Gas reclassifications out of AOCI by component:
|
|
|
|
|
|
|
Details about AOCI components |
|
Amounts reclassified from AOCI |
|
|
Affected line item in the Consolidated Statements of
Income |
(millions) |
|
|
|
|
|
Year Ended December 31, 2014 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
|
$ |
(2 |
) |
|
Operating revenue |
|
|
|
14 |
|
|
Purchased gas |
|
|
|
1 |
|
|
Interest and related charges |
Total |
|
|
13 |
|
|
|
Tax |
|
|
(5 |
) |
|
Income tax expense |
Total, net of tax |
|
$ |
8 |
|
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Prior service costs |
|
$ |
1 |
|
|
Other operations and maintenance |
Actuarial losses |
|
|
7 |
|
|
Other operations and maintenance |
Total |
|
|
8 |
|
|
|
Tax |
|
|
(3 |
) |
|
Income tax expense |
Total, net of tax |
|
$ |
5 |
|
|
|
Year Ended December 31, 2013 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: Commodity contracts |
|
$ |
2 |
|
|
Operating revenue |
|
|
|
14 |
|
|
Purchased gas |
Total |
|
|
16 |
|
|
|
Tax |
|
|
(5 |
) |
|
Income tax expense |
Total, net of tax |
|
$ |
11 |
|
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Prior service costs |
|
$ |
1 |
|
|
Other operations and maintenance |
Actuarial losses |
|
|
9 |
|
|
Other operations and maintenance |
Total |
|
|
10 |
|
|
|
Tax |
|
|
(4 |
) |
|
Income tax expense |
Total, net of tax |
|
$ |
6 |
|
|
|
Combined Notes to Consolidated Financial Statements, Continued
Stock-Based Awards
The 2005 and 2014 Incentive Compensation Plans permit 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 these 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, 2014, approximately
31 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, 2014, 2013 and 2012 include $39
million, $31 million, and $25 million, respectively, of compensation costs and $14 million, $11 million, and $8 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, 2014, 2013, and 2012, Dominion
realized less than $1 million, less than $1 million and $10 million, respectively, of excess tax benefits from the vesting of restricted stock awards and exercise of stock options.
RESTRICTED STOCK
Restricted stock grants are made to officers under
Dominions LTIP and may also be granted to certain key non-officer employees from time to time. The fair value of Dominions restricted stock awards is equal to the closing 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, 2014, 2013 and 2012:
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
Weighted
- average Grant Date
Fair Value |
|
|
|
(thousands) |
|
|
|
|
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 |
|
Granted |
|
|
312 |
|
|
|
54.70 |
|
Vested |
|
|
(356 |
) |
|
|
39.00 |
|
Cancelled and forfeited |
|
|
(34 |
) |
|
|
51.11 |
|
Nonvested at December 31, 2013 |
|
|
1,007 |
|
|
$ |
49.35 |
|
Granted |
|
|
354 |
|
|
|
67.98 |
|
Vested |
|
|
(278 |
) |
|
|
44.50 |
|
Cancelled and forfeited |
|
|
(18 |
) |
|
|
53.61 |
|
Nonvested at December 31, 2014 |
|
|
1,065 |
|
|
$ |
56.74 |
|
As of December 31, 2014, unrecognized compensation cost related to nonvested
restricted stock awards totaled $27 million and is expected to be recognized over a weighted-average period of 1.8 years. The fair value of restricted stock awards that vested was $19 million, $20 million, and $30 million in 2014, 2013 and 2012,
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 2013 and
February 2014.
The issuance of awards is based on the achievement of two performance metrics during a two-year period: TSR
relative to that of companies listed as members of the Philadelphia 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 closing 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 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.
The following table provides a summary of goal-based stock activity for the years ended December 31, 2014, 2013 and 2012:
|
|
|
|
|
|
|
|
|
|
|
Targeted
Number of Shares |
|
|
Weighted
- average Grant
Date Fair Value |
|
|
|
(thousands) |
|
|
|
|
Nonvested at December 31, 2011 |
|
|
12 |
|
|
$ |
39.19 |
|
Granted |
|
|
1 |
|
|
|
52.48 |
|
Vested |
|
|
(9 |
) |
|
|
37.46 |
|
Nonvested at December 31, 2012 |
|
|
4 |
|
|
$ |
45.60 |
|
Granted |
|
|
4 |
|
|
|
54.17 |
|
Vested |
|
|
(2 |
) |
|
|
43.54 |
|
Cancelled and forfeited |
|
|
(1 |
) |
|
|
43.54 |
|
Nonvested at December 31, 2013 |
|
|
5 |
|
|
$ |
53.85 |
|
Granted |
|
|
13 |
|
|
|
68.83 |
|
Vested |
|
|
(1 |
) |
|
|
52.48 |
|
Nonvested at December 31, 2014 |
|
|
17 |
|
|
$ |
65.15 |
|
At December 31, 2014, the targeted number of shares expected to be issued under the February 2013 and
February 2014 awards was approximately 17 thousand. In January 2015, the CGN Committee determined the actual performance against metrics established for the February 2013 awards with a performance period that ended December 31, 2014. Based on
that determination, the total number of shares to be issued under the February 2013 goal-based stock awards was approximately 7 thousand.
As of December 31, 2014, 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.
In February 2011, a
cash-based performance grant was made to officers. A portion of the grant, representing $6 million was paid in December 2012, based on the achievement of two performance metrics during 2011 and 2012: ROIC and TSR relative to that of a peer group of
companies. The total amount of the award under the grant was $8 million and the remaining $2 million of the grant was paid in February 2013.
In February 2012, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $8 million was paid in December 2013, based on the achievement of two
performance metrics during 2012 and 2013: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total amount of the award under the grant was $12 million and the
remaining portion of the grant was paid in January 2014.
In February 2013, a cash-based performance grant was made to
officers. A portion of the grant, representing the initial payout of $14 million was paid in December 2014, based on the achievement of two performance metrics during 2013 and 2014: TSR relative to that of companies listed as members of the
Philadelphia Utility Index as of the end of the performance period and ROIC. The total expected award under the grant is $21 million and the remaining portion of the grant is expected to be paid by March 15, 2015. At December 31, 2014, a
liability of $7 million had been accrued for the remaining portion of the award.
In February 2014, a cash-based performance
grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2016 based on the achievement of two performance metrics during 2014 and 2015: TSR relative to that of companies listed as members of the Philadelphia
Utility Index as of the end of the performance period and ROIC. At December 31, 2014, the targeted amount of the grant was $13 million and a liability of $3 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, 2014, the Virginia Commission had not restricted the payment of dividends by Virginia Power.
The Ohio Commission may prohibit any public service company, including East Ohio, from declaring or paying a dividend to an affiliate if
found to be detrimental to the public interest. At December 31, 2014, the Ohio Commission had not restricted the payment of dividends by East Ohio.
Certain agreements associated with the Companies credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Companies ability
to pay dividends or receive dividends from their subsidiaries at December 31, 2014.
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 and equity units, initially in the form of corporate units.
NOTE 21. EMPLOYEE BENEFIT PLANS
Dominion and Dominion Gas - Defined Benefit Plans
Dominion provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Gas participates in a number of the Dominion-sponsored retirement plans. 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 benefits for Dominion Gas
employees not represented by collective bargaining units are covered by the Dominion Pension Plan, a defined benefit pension plan sponsored by Dominion that provides benefits to multiple Dominion subsidiaries. Pension benefits for Dominion Gas
employees represented by collective bargaining units are covered by separate pension plans for East Ohio and, for DTI, a plan that provides benefits to employees of both DTI and Hope. Employee compensation is the basis for allocating pension costs
and obligations between DTI and Hope and determining East Ohios share of total pension costs.
Retiree healthcare and
life insurance benefits for Dominion Gas employees not represented by collective bargaining units are covered by 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. Retiree healthcare and life insurance benefits for Dominion Gas employees represented by collective bargaining units are covered by separate other postretirement benefit plans for East Ohio and, for DTI, a
plan that provides benefits to both DTI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DTI and Hope and determining East Ohios share of total other postretirement benefit
costs.
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, mortality rates and the rate of compensation increases.
Combined Notes to Consolidated Financial Statements, Continued
Dominion uses December 31 as the measurement date for all of its employee benefit
plans, including those in which Dominion Gas participates. 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, for all pension plans, including
those in which Dominion Gas participates. 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 $706 million in 2014 and $959 million in
2013, versus expected returns of $610 million and $554 million, respectively. Aggregate actual returns for pension and other postretirement benefit plan assets for Dominion Gas employees represented by collective bargaining units were $157 million
in 2014 and $214 million in 2013, versus expected returns of $138 million and $125 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 net 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.
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 $4 million and $5 million for 2014 and 2013, respectively. Dominion Gas received a federal subsidy of $1 million for each of 2014 and 2013. Effective January 1, 2013, Dominion changed 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 reduced other postretirement benefit costs by approximately $20 million annually beginning in 2012. As a result
of the adoption of the EGWP, Dominion will begin to receive an increased level of Medicare Part D subsidies, in the form of reduced costs rather than a direct reimbursement, over the next few years.
In October 2014, the Society of Actuaries published new mortality tables and mortality improvement scales. Such tables and scales are used
to develop mortality assumptions for use in determining pension and other postretirement benefit liabilities and expense. Following evaluation of the new tables, Dominion changed its assumption for mortality rates to reflect a generational
improvement scale. As a result of this change in assumption, at December 31, 2014 Dominion and Dominion Gas (for
employ-
ees represented by collective bargaining units) increased their pension benefit obligations by $131 million and $10 million, respectively, and increased their accumulated postretirement benefit
obligations by $32 million and $7 million, respectively. This change is expected to increase net periodic benefit cost for Dominion and Dominion Gas (for employees represented by collective bargaining units) by approximately $25 million and $3
million, respectively, for 2015.
Dominion remeasured all of its pension and other postretirement benefit plans in the second
quarter of 2013. The remeasurement resulted in a reduction in the pension benefit obligation of approximately $354 million and a reduction in the accumulated postretirement benefit obligation of approximately $78 million. For Dominion Gas employees
represented by collective bargaining units, the remeasurement resulted in a reduction in the pension benefit obligation of approximately $28 million and a reduction in the accumulated postretirement benefit obligation of approximately $9 million.
The impact of the remeasurement on net periodic benefit (credit) cost was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by approximately $36 million, excluding the impacts of curtailments, and
for Dominion Gas employees represented by collective bargaining units by approximately $2 million. The discount rate used for the remeasurement was 4.80% for the pension plans and 4.70% for the other postretirement benefit plans. All other
assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.
In the fourth
quarter of 2013, Dominion remeasured its other postretirement benefit plans as a result of a plan amendment that changed medical coverage for certain Medicare-eligible retirees effective April 2014. The remeasurement resulted in a reduction in the
accumulated postretirement benefit obligation of approximately $220 million. The impact of the remeasurement on net periodic benefit (credit) cost was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for
2013 by approximately $8 million. The amendment is expected to reduce net periodic benefit cost by $40 million to $60 million for each of the next five years. The discount rate used for the remeasurement was 4.80%. All other assumptions used for the
remeasurement were consistent with the measurement as of December 31, 2012.
In the third quarter of 2014, East Ohio
remeasured its other postretirement benefit plan as a result of an amendment that changed medical coverage upon the attainment of age 65 for certain future retirees effective January 1, 2016. For employees represented by collective bargaining
units, the remeasurement resulted in an increase in the accumulated postretirement benefit obligation of approximately $22 million. The impact of the remeasurement on net periodic benefit credit was recognized prospectively from the remeasurement
date and reduced net periodic benefit credit for 2014, for employees represented by collective bargaining units, by less than $1 million. The discount rate used for the remeasurement was 4.20% and the expected long-term rate of return used was
8.50%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2013.
Funded Status
The
following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans funded status for Dominion and Dominion Gas (for employees represented by collective
bargaining units):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
DOMINION |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
|
$ |
5,625 |
|
|
$ |
6,125 |
|
|
$ |
1,360 |
|
|
$ |
1,719 |
|
Service cost |
|
|
114 |
|
|
|
131 |
|
|
|
32 |
|
|
|
43 |
|
Interest cost |
|
|
290 |
|
|
|
271 |
|
|
|
67 |
|
|
|
73 |
|
Benefits paid |
|
|
(236 |
) |
|
|
(229 |
) |
|
|
(78 |
) |
|
|
(75 |
) |
Actuarial (gains) losses during the year |
|
|
887 |
|
|
|
(650 |
) |
|
|
177 |
|
|
|
(170 |
) |
Plan amendments(1) |
|
|
|
|
|
|
1 |
|
|
|
9 |
|
|
|
(220 |
) |
Settlements and curtailments(2) |
|
|
(13 |
) |
|
|
(24 |
) |
|
|
|
|
|
|
(16 |
) |
Special termination benefits |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Medicare Part D reimbursement |
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
5 |
|
Benefit obligation at end of year |
|
$ |
6,667 |
|
|
$ |
5,625 |
|
|
$ |
1,571 |
|
|
$ |
1,360 |
|
Changes in fair value of plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
$ |
6,113 |
|
|
$ |
5,553 |
|
|
$ |
1,315 |
|
|
$ |
1,156 |
|
Actual return on plan assets |
|
|
601 |
|
|
|
781 |
|
|
|
105 |
|
|
|
178 |
|
Employer contributions |
|
|
15 |
|
|
|
8 |
|
|
|
12 |
|
|
|
12 |
|
Benefits paid |
|
|
(236 |
) |
|
|
(229 |
) |
|
|
(30 |
) |
|
|
(31 |
) |
Settlements(2) |
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year |
|
$ |
6,480 |
|
|
$ |
6,113 |
|
|
$ |
1,402 |
|
|
$ |
1,315 |
|
Funded status at end of year |
|
$ |
(187 |
) |
|
$ |
488 |
|
|
$ |
(169 |
) |
|
$ |
(45 |
) |
Amounts recognized in the Consolidated Balance Sheets at December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent pension and other postretirement benefit assets |
|
$ |
946 |
|
|
$ |
913 |
|
|
$ |
10 |
|
|
$ |
29 |
|
Other current liabilities |
|
|
(13 |
) |
|
|
(15 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
Noncurrent pension and other postretirement benefit liabilities |
|
|
(1,120 |
) |
|
|
(410 |
) |
|
|
(176 |
) |
|
|
(71 |
) |
Net amount recognized |
|
$ |
(187 |
) |
|
$ |
488 |
|
|
$ |
(169 |
) |
|
$ |
(45 |
) |
Significant assumptions used to determine benefit obligations as of December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate(3) |
|
|
4.40% |
|
|
|
5.20%/5.30% |
|
|
|
4.40% |
|
|
|
5.00%/5.10% |
|
Weighted average rate of increase for compensation |
|
|
4.22% |
|
|
|
4.21% |
|
|
|
4.22% |
|
|
|
4.22% |
|
Expected long-term rate of return on plan assets |
|
|
8.75% |
|
|
|
8.50% |
|
|
|
8.50% |
|
|
|
7.75% |
|
DOMINION GAS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
|
$ |
563 |
|
|
$ |
607 |
|
|
$ |
269 |
|
|
$ |
287 |
|
Service cost |
|
|
12 |
|
|
|
13 |
|
|
|
6 |
|
|
|
7 |
|
Interest cost |
|
|
28 |
|
|
|
27 |
|
|
|
13 |
|
|
|
12 |
|
Benefits paid |
|
|
(29 |
) |
|
|
(27 |
) |
|
|
(16 |
) |
|
|
(17 |
) |
Actuarial (gains) losses during the year |
|
|
64 |
|
|
|
(57 |
) |
|
|
38 |
|
|
|
(21 |
) |
Plan amendments |
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
|
|
Medicare Part D reimbursement |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
Benefit obligation at end of year |
|
$ |
638 |
|
|
$ |
563 |
|
|
$ |
320 |
|
|
$ |
269 |
|
Changes in fair value of plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
$ |
1,403 |
|
|
$ |
1,254 |
|
|
$ |
273 |
|
|
$ |
242 |
|
Actual return on plan assets |
|
|
136 |
|
|
|
176 |
|
|
|
21 |
|
|
|
38 |
|
Employer contributions |
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
10 |
|
Benefits paid |
|
|
(29 |
) |
|
|
(27 |
) |
|
|
(16 |
) |
|
|
(17 |
) |
Fair value of plan assets at end of year |
|
$ |
1,510 |
|
|
$ |
1,403 |
|
|
$ |
288 |
|
|
$ |
273 |
|
Funded status at end of year |
|
$ |
872 |
|
|
$ |
840 |
|
|
$ |
(32 |
) |
|
$ |
4 |
|
Amounts recognized in the Consolidated Balance Sheets at December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent pension and other postretirement benefit assets |
|
$ |
872 |
|
|
$ |
840 |
|
|
$ |
|
|
|
$ |
19 |
|
Noncurrent pension and other postretirement benefit liabilities(4) |
|
|
|
|
|
|
|
|
|
|
(32 |
) |
|
|
(15 |
) |
Net amount recognized |
|
$ |
872 |
|
|
$ |
840 |
|
|
$ |
(32 |
) |
|
$ |
4 |
|
Significant assumptions used to determine benefit obligations as of December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
4.40% |
|
|
|
5.20% |
|
|
|
4.40% |
|
|
|
5.00% |
|
Weighted average rate of increase for compensation |
|
|
3.93% |
|
|
|
3.93% |
|
|
|
3.93% |
|
|
|
3.93% |
|
Expected long-term rate of return on plan assets |
|
|
8.75% |
|
|
|
8.50% |
|
|
|
8.50% |
|
|
|
7.75% |
|
Combined Notes to Consolidated Financial Statements, Continued
(1) |
2013 other postretirement benefits amount relates to a plan amendment that changed medical coverage for certain Medicare-eligible retirees.
|
(2) |
2014 amounts relate primarily to a settlement charge for certain executives. 2013 amounts relate primarily to the decommissioning of Kewaunee.
|
(3) |
2013 pension and other postretirement benefits discount rates: 5.20% and 5.00% for the gas union plans and 5.30% and 5.10% for the nonunion and other union plans,
respectively. |
(4) |
Reflected in other deferred credits and other liabilities in Dominion Gas Consolidated Balance Sheets. |
The ABO for all of Dominions defined benefit pension plans was $6.0 billion and $5.1 billion at December 31, 2014 and 2013,
respectively. The ABO for the defined benefit pension plans covering Dominion Gas employees represented by collective bargaining units was $604 million and $534 million at December 31, 2014 and 2013, 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 2014, Dominion and Dominion Gas made no contributions to
the qualified defined benefit pension plans and no contributions are currently expected in 2015. In July 2012, the MAP 21 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. In 2014, the HATFA of 2014 was signed into law. Similar to the MAP 21 Act, the HATFA of 2014 adjusts the rules for calculating interest rates used in determining funding obligations. It is estimated that
the new interest rates will reduce required pension contributions through 2019. Dominion believes that required pension contributions will rise subsequent to 2019, resulting in an estimated $200 million reduction in net 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, including Dominion Gas, fund other postretirement benefit costs through VEBAs. Dominions remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominions contributions
to VEBAs, all of which pertained to Dominion Gas employees, totaled $12 million for both 2014 and 2013, and Dominion expects to contribute approximately $12 million to the Dominion VEBAs in 2015, all of which pertains to Dominion Gas employees.
Dominion and Dominion Gas do not expect any pension or other postretirement plan assets to be returned during 2015.
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 for Dominion and Dominion Gas (for employees represented by collective bargaining units):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
As of December 31, |
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
DOMINION |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation |
|
$ |
5,970 |
|
|
$ |
4,978 |
|
|
$ |
1,564 |
|
|
$ |
1,233 |
|
Fair value of plan assets |
|
|
4,838 |
|
|
|
4,553 |
|
|
|
1,385 |
|
|
|
1,158 |
|
DOMINION GAS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation |
|
$ |
|
|
|
$ |
|
|
|
$ |
320 |
|
|
$ |
147 |
|
Fair value of plan assets |
|
|
|
|
|
|
|
|
|
|
288 |
|
|
|
132 |
|
The following table provides information on the ABO and fair value of plan assets for Dominions
pension plans with an ABO in excess of plan assets:
|
|
|
|
|
|
|
|
|
As of December 31, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
Accumulated benefit obligation |
|
$ |
5,370 |
|
|
$ |
114 |
|
Fair value of plan assets |
|
|
4,838 |
|
|
|
|
|
The following benefit payments, which reflect expected future service, as appropriate, are expected to be
paid for Dominions and Dominion Gas (for employees represented by collective bargaining units) plans:
|
|
|
|
|
|
|
|
|
|
|
Estimated Future Benefit Payments |
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
(millions) |
|
|
|
|
|
|
DOMINION |
|
|
|
|
|
|
|
|
2015 |
|
$ |
272 |
|
|
$ |
91 |
|
2016 |
|
|
284 |
|
|
|
94 |
|
2017 |
|
|
300 |
|
|
|
98 |
|
2018 |
|
|
320 |
|
|
|
101 |
|
2019 |
|
|
333 |
|
|
|
102 |
|
2020-2024 |
|
1,925 |
|
|
523 |
|
DOMINON GAS |
|
|
|
|
|
|
|
|
2015 |
|
$ |
34 |
|
|
$ |
18 |
|
2016 |
|
|
35 |
|
|
|
19 |
|
2017 |
|
|
37 |
|
|
|
20 |
|
2018 |
|
|
38 |
|
|
|
21 |
|
2019 |
|
|
39 |
|
|
|
22 |
|
2020-2024 |
|
|
204 |
|
|
|
111 |
|
Plan Assets
Dominions overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. As a
participating employer in various pension plans sponsored by Dominion, Dominion Gas is subject to Dominions investment policies for such plans. To minimize risk, funds are broadly diversified among asset classes, investment strategies and
investment advisors. The strategic target asset allocations for Dominions 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.
Dominion also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for
investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment 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.
Combined Notes to Consolidated Financial Statements, Continued
The fair values of Dominions and Dominion Gas (for employees represented by
collective bargaining units) pension plan assets by asset category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements |
|
|
|
Pension Plans |
|
At December 31, |
|
2014 |
|
|
2013 |
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DOMINION |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
|
$ |
13 |
|
|
$ |
25 |
|
|
$ |
|
|
|
$ |
38 |
|
|
$ |
53 |
|
|
$ |
126 |
|
|
$ |
|
|
|
$ |
179 |
|
U.S. equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
1,313 |
|
|
|
|
|
|
|
|
|
|
|
1,313 |
|
|
|
1,220 |
|
|
|
|
|
|
|
|
|
|
|
1,220 |
|
Other |
|
|
530 |
|
|
|
|
|
|
|
|
|
|
|
530 |
|
|
|
514 |
|
|
|
|
|
|
|
|
|
|
|
514 |
|
Non-U.S. equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
234 |
|
|
|
|
|
|
|
|
|
|
|
234 |
|
|
|
308 |
|
|
|
|
|
|
|
|
|
|
|
308 |
|
Other |
|
|
403 |
|
|
|
|
|
|
|
|
|
|
|
403 |
|
|
|
391 |
|
|
|
|
|
|
|
|
|
|
|
391 |
|
Common/collective trust funds(1) |
|
|
|
|
|
|
1,595 |
|
|
|
|
|
|
|
1,595 |
|
|
|
|
|
|
|
1,387 |
|
|
|
|
|
|
|
1,387 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
45 |
|
|
|
666 |
|
|
|
|
|
|
|
711 |
|
|
|
43 |
|
|
|
451 |
|
|
|
|
|
|
|
494 |
|
U.S. Treasury securities and agency debentures |
|
|
74 |
|
|
|
342 |
|
|
|
|
|
|
|
416 |
|
|
|
2 |
|
|
|
229 |
|
|
|
|
|
|
|
231 |
|
State and municipal |
|
|
10 |
|
|
|
60 |
|
|
|
|
|
|
|
70 |
|
|
|
69 |
|
|
|
107 |
|
|
|
|
|
|
|
176 |
|
Other securities |
|
|
6 |
|
|
|
80 |
|
|
|
|
|
|
|
86 |
|
|
|
7 |
|
|
|
50 |
|
|
|
|
|
|
|
57 |
|
Real estate: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REITs |
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
40 |
|
|
|
32 |
|
|
|
|
|
|
|
|
|
|
|
32 |
|
Partnerships |
|
|
|
|
|
|
|
|
|
|
209 |
|
|
|
209 |
|
|
|
|
|
|
|
|
|
|
|
227 |
|
|
|
227 |
|
Other alternative investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Private equity |
|
|
|
|
|
|
|
|
|
|
518 |
|
|
|
518 |
|
|
|
|
|
|
|
|
|
|
|
530 |
|
|
|
530 |
|
Debt |
|
|
|
|
|
|
|
|
|
|
144 |
|
|
|
144 |
|
|
|
|
|
|
|
|
|
|
|
180 |
|
|
|
180 |
|
Hedge funds |
|
|
|
|
|
|
|
|
|
|
162 |
|
|
|
162 |
|
|
|
|
|
|
|
|
|
|
|
187 |
|
|
|
187 |
|
Total(2) |
|
$ |
2,668 |
|
|
$ |
2,768 |
|
|
$ |
1,033 |
|
|
$ |
6,469 |
|
|
$ |
2,639 |
|
|
$ |
2,350 |
|
|
$ |
1,124 |
|
|
$ |
6,113 |
|
DOMINION GAS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
|
$ |
3 |
|
|
$ |
6 |
|
|
$ |
|
|
|
$ |
9 |
|
|
$ |
12 |
|
|
$ |
29 |
|
|
$ |
|
|
|
$ |
41 |
|
U.S. equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
306 |
|
|
|
|
|
|
|
|
|
|
|
306 |
|
|
|
280 |
|
|
|
|
|
|
|
|
|
|
|
280 |
|
Other |
|
|
124 |
|
|
|
|
|
|
|
|
|
|
|
124 |
|
|
|
118 |
|
|
|
|
|
|
|
|
|
|
|
118 |
|
Non-U.S. equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
54 |
|
|
|
|
|
|
|
|
|
|
|
54 |
|
|
|
72 |
|
|
|
|
|
|
|
|
|
|
|
72 |
|
Other |
|
|
94 |
|
|
|
|
|
|
|
|
|
|
|
94 |
|
|
|
90 |
|
|
|
|
|
|
|
|
|
|
|
90 |
|
Common/collective trust funds(3) |
|
|
|
|
|
|
372 |
|
|
|
|
|
|
|
372 |
|
|
|
|
|
|
|
318 |
|
|
|
|
|
|
|
318 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
11 |
|
|
|
155 |
|
|
|
|
|
|
|
166 |
|
|
|
10 |
|
|
|
103 |
|
|
|
|
|
|
|
113 |
|
U.S. Treasury securities and agency debentures |
|
|
17 |
|
|
|
80 |
|
|
|
|
|
|
|
97 |
|
|
|
1 |
|
|
|
52 |
|
|
|
|
|
|
|
53 |
|
State and municipal |
|
|
2 |
|
|
|
14 |
|
|
|
|
|
|
|
16 |
|
|
|
16 |
|
|
|
24 |
|
|
|
|
|
|
|
40 |
|
Other securities |
|
|
1 |
|
|
|
19 |
|
|
|
|
|
|
|
20 |
|
|
|
2 |
|
|
|
11 |
|
|
|
|
|
|
|
13 |
|
Real estate: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REITs |
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
7 |
|
Partnerships |
|
|
|
|
|
|
|
|
|
|
48 |
|
|
|
48 |
|
|
|
|
|
|
|
|
|
|
|
52 |
|
|
|
52 |
|
Other alternative investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Private equity |
|
|
|
|
|
|
|
|
|
|
121 |
|
|
|
121 |
|
|
|
|
|
|
|
|
|
|
|
122 |
|
|
|
122 |
|
Debt |
|
|
|
|
|
|
|
|
|
|
34 |
|
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
41 |
|
|
|
41 |
|
Hedge funds |
|
|
|
|
|
|
|
|
|
|
38 |
|
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
43 |
|
|
|
43 |
|
Total(4) |
|
$ |
621 |
|
|
$ |
646 |
|
|
$ |
241 |
|
|
$ |
1,508 |
|
|
$ |
608 |
|
|
$ |
537 |
|
|
$ |
258 |
|
|
$ |
1,403 |
|
(1) |
Common/Collective Trust Funds include $360 million and $560 million of John Hancock insurance contracts held at December 31, 2014 and 2013, respectively. See
below for a description of the individual investments included within this line item, and the nature and risk of each respective fund. |
(2) |
Includes net assets related to pending sales of securities of $31 million, net accrued income of $18 million, and excludes net assets related to pending purchases of
securities of $38 million at December 31, 2014. |
(3) |
See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund.
|
(4) |
Includes net assets related to pending sales of securities of $7 million, net accrued income of $4 million, and excludes net assets related to pending purchases of
securities of $9 million at December 31, 2014. |
The fair values of Dominions and Dominion Gas (for employees represented by collective bargaining units) other postretirement
plan assets by asset category are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements |
|
|
|
Other Postretirement Plans |
|
At December 31, |
|
2014 |
|
|
2013 |
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DOMINION |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
|
$ |
1 |
|
|
$ |
7 |
|
|
$ |
|
|
|
$ |
8 |
|
|
$ |
3 |
|
|
$ |
14 |
|
|
$ |
|
|
|
$ |
17 |
|
U.S. equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
514 |
|
|
|
|
|
|
|
|
|
|
|
514 |
|
|
|
472 |
|
|
|
|
|
|
|
|
|
|
|
472 |
|
Other |
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
28 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
26 |
|
Non-U.S. equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large Cap |
|
|
102 |
|
|
|
|
|
|
|
|
|
|
|
102 |
|
|
|
111 |
|
|
|
|
|
|
|
|
|
|
|
111 |
|
Other |
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
21 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
20 |
|
Common/collective trust funds(1) |
|
|
|
|
|
|
555 |
|
|
|
|
|
|
|
555 |
|
|
|
|
|
|
|
502 |
|
|
|
|
|
|
|
502 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
|
3 |
|
|
|
35 |
|
|
|
|
|
|
|
38 |
|
|
|
2 |
|
|
|
23 |
|
|
|
|
|
|
|
25 |
|
U.S. Treasury securities and agency debentures |
|
|
4 |
|
|
|
18 |
|
|
|
|
|
|
|
22 |
|
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
12 |
|
State and municipal |
|
|
1 |
|
|
|
3 |
|
|
|
|
|
|
|
4 |
|
|
|
4 |
|
|
|
5 |
|
|
|
|
|
|
|
9 |
|
Other securities |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
3 |
|
Real estate: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REITs |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
Partnerships |
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
19 |
|
Other alternative investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Private equity |
|
|
|
|
|
|
|
|
|
|
58 |
|
|
|
58 |
|
|
|
|
|
|
|
|
|
|
|
60 |
|
|
|
60 |
|
Debt |
|
|
|
|
|
|
|
|
|
|
18 |
|
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
27 |
|
|
|
27 |
|
Hedge funds |
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
10 |
|
Total |
|
$ |
676 |
|
|
$ |
622 |
|
|
$ |
104 |
|
|
$ |
1,402 |
|
|
$ |
640 |
|
|
$ |
559 |
|
|
$ |
116 |
|
|
$ |
1,315 |
|
DOMINION GAS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
|
$ |
|
|
|
$ |
2 |
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
|
|
|
$ |
3 |
|
|
$ |
|
|
|
$ |
3 |
|
U.S. equity-Large Cap |
|
|
113 |
|
|
|
|
|
|
|
|
|
|
|
113 |
|
|
|
104 |
|
|
|
|
|
|
|
|
|
|
|
104 |
|
Non-U.S. equity-Large Cap |
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
26 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
26 |
|
Common/collective trust funds(2) |
|
|
|
|
|
|
129 |
|
|
|
|
|
|
|
129 |
|
|
|
|
|
|
|
119 |
|
|
|
|
|
|
|
119 |
|
Real estate-partnerships |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
Other alternative investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Private equity |
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
12 |
|
Debt |
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
7 |
|
Total |
|
$ |
139 |
|
|
$ |
131 |
|
|
$ |
18 |
|
|
$ |
288 |
|
|
$ |
130 |
|
|
$ |
122 |
|
|
$ |
21 |
|
|
$ |
273 |
|
(1) |
Common/Collective Trust Funds include $19 million and $29 million of John Hancock insurance contracts held at December 31, 2014 and 2013, respectively. See below for
a description of the individual investments included within this line item, and the nature and risk of each respective fund. |
(2) |
See below for a description of the individual investments included within this line item, and the nature and risk of each respective fund.
|
Combined Notes to Consolidated Financial Statements, Continued
The following table presents the changes in pension and other postretirement plan assets
that are measured at fair value and included in the Level 3 fair value category for Dominion and Dominion Gas (for employees represented by collective bargaining units):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DOMINION |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
Actual return on plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Relating to assets still held at the reporting date |
|
|
15 |
|
|
|
98 |
|
|
|
32 |
|
|
|
21 |
|
|
|
166 |
|
|
|
(2 |
) |
|
|
6 |
|
|
|
3 |
|
|
|
1 |
|
|
|
8 |
|
Relating to assets sold during the period |
|
|
(36 |
) |
|
|
(48 |
) |
|
|
(34 |
) |
|
|
(4 |
) |
|
|
(122 |
) |
|
|
1 |
|
|
|
3 |
|
|
|
|
|
|
|
1 |
|
|
|
5 |
|
Purchases |
|
|
6 |
|
|
|
115 |
|
|
|
32 |
|
|
|
|
|
|
|
153 |
|
|
|
1 |
|
|
|
7 |
|
|
|
2 |
|
|
|
|
|
|
|
10 |
|
Sales |
|
|
(79 |
) |
|
|
(91 |
) |
|
|
(42 |
) |
|
|
(51 |
) |
|
|
(263 |
) |
|
|
(5 |
) |
|
|
(14 |
) |
|
|
(9 |
) |
|
|
(3 |
) |
|
|
(31 |
) |
Balance at December 31, 2013 |
|
$ |
227 |
|
|
$ |
530 |
|
|
$ |
180 |
|
|
$ |
187 |
|
|
$ |
1,124 |
|
|
$ |
19 |
|
|
$ |
60 |
|
|
$ |
27 |
|
|
$ |
10 |
|
|
$ |
116 |
|
Actual return on plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Relating to assets still held at the reporting date |
|
|
40 |
|
|
|
70 |
|
|
|
12 |
|
|
|
4 |
|
|
|
126 |
|
|
|
4 |
|
|
|
7 |
|
|
|
2 |
|
|
|
|
|
|
|
13 |
|
Relating to assets sold during the period |
|
|
(18 |
) |
|
|
(67 |
) |
|
|
(26 |
) |
|
|
(4 |
) |
|
|
(115 |
) |
|
|
(1 |
) |
|
|
(7 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
(11 |
) |
Purchases |
|
|
|
|
|
|
135 |
|
|
|
10 |
|
|
|
|
|
|
|
145 |
|
|
|
|
|
|
|
13 |
|
|
|
1 |
|
|
|
|
|
|
|
14 |
|
Sales |
|
|
(40 |
) |
|
|
(150 |
) |
|
|
(32 |
) |
|
|
(25 |
) |
|
|
(247 |
) |
|
|
(3 |
) |
|
|
(15 |
) |
|
|
(9 |
) |
|
|
(1 |
) |
|
|
(28 |
) |
Balance at December 31, 2014 |
|
$ |
209 |
|
|
$ |
518 |
|
|
$ |
144 |
|
|
$ |
162 |
|
|
$ |
1,033 |
|
|
$ |
19 |
|
|
$ |
58 |
|
|
$ |
18 |
|
|
$ |
9 |
|
|
$ |
104 |
|
DOMINION GAS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2011 |
|
$ |
68 |
|
|
$ |
99 |
|
|
$ |
54 |
|
|
$ |
64 |
|
|
$ |
285 |
|
|
$ |
3 |
|
|
$ |
15 |
|
|
$ |
10 |
|
|
$ |
|
|
|
$ |
28 |
|
Actual return on plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Relating to assets still held at the reporting date |
|
|
6 |
|
|
|
12 |
|
|
|
4 |
|
|
|
4 |
|
|
|
26 |
|
|
|
|
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(2 |
) |
Relating to assets sold during the period |
|
|
(2 |
) |
|
|
(9 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
(13 |
) |
|
|
|
|
|
|
2 |
|
|
|
1 |
|
|
|
|
|
|
|
3 |
|
Purchases |
|
|
7 |
|
|
|
17 |
|
|
|
3 |
|
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Sales |
|
|
(7 |
) |
|
|
(16 |
) |
|
|
(16 |
) |
|
|
(18 |
) |
|
|
(57 |
) |
|
|
|
|
|
|
(4 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
(6 |
) |
Balance at December 31, 2012 |
|
$ |
72 |
|
|
$ |
103 |
|
|
$ |
43 |
|
|
$ |
50 |
|
|
$ |
268 |
|
|
$ |
3 |
|
|
$ |
13 |
|
|
$ |
8 |
|
|
$ |
|
|
|
$ |
24 |
|
Actual return on plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Relating to assets still held at the reporting date |
|
|
4 |
|
|
|
24 |
|
|
|
7 |
|
|
|
5 |
|
|
|
40 |
|
|
|
(1 |
) |
|
|
2 |
|
|
|
1 |
|
|
|
|
|
|
|
2 |
|
Relating to assets sold during the period |
|
|
(8 |
) |
|
|
(10 |
) |
|
|
(7 |
) |
|
|
(1 |
) |
|
|
(26 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases |
|
|
1 |
|
|
|
25 |
|
|
|
7 |
|
|
|
|
|
|
|
33 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Sales |
|
|
(17 |
) |
|
|
(20 |
) |
|
|
(9 |
) |
|
|
(11 |
) |
|
|
(57 |
) |
|
|
|
|
|
|
(4 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
(6 |
) |
Balance at December 31, 2013 |
|
$ |
52 |
|
|
$ |
122 |
|
|
$ |
41 |
|
|
$ |
43 |
|
|
$ |
258 |
|
|
$ |
2 |
|
|
$ |
12 |
|
|
$ |
7 |
|
|
$ |
|
|
|
$ |
21 |
|
Actual return on plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Relating to assets still held at the reporting date |
|
|
9 |
|
|
|
17 |
|
|
|
4 |
|
|
|
1 |
|
|
|
31 |
|
|
|
|
|
|
|
2 |
|
|
|
1 |
|
|
|
|
|
|
|
3 |
|
Relating to assets sold during the period |
|
|
(4 |
) |
|
|
(15 |
) |
|
|
(6 |
) |
|
|
(1 |
) |
|
|
(26 |
) |
|
|
|
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(2 |
) |
Purchases |
|
|
|
|
|
|
30 |
|
|
|
2 |
|
|
|
|
|
|
|
32 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
Sales |
|
|
(9 |
) |
|
|
(33 |
) |
|
|
(7 |
) |
|
|
(5 |
) |
|
|
(54 |
) |
|
|
|
|
|
|
(3 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
(6 |
) |
Balance at December 31, 2014 |
|
$ |
48 |
|
|
$ |
121 |
|
|
$ |
34 |
|
|
$ |
38 |
|
|
$ |
241 |
|
|
$ |
2 |
|
|
$ |
12 |
|
|
$ |
4 |
|
|
$ |
|
|
|
$ |
18 |
|
Investments in Common/Collective Trust Funds in Dominions pension and other
postretirement plans, including those in which Dominion Gas participates, are stated at fair value as determined by the issuer of the Common/Collective Trust Funds based on the fair value of the underlying investments. The Common/Collective Trusts
do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the Common/Collective Trust Funds have limited withdrawal or redemption rights during the term of the
investment. Strategies of the Common/Collective Trust Funds are as follows:
Dominion and Dominion Gas
|
|
|
Wells Fargo Closed End Bond Trust-The Fund invests in stocks, bonds or a combination of both. Shares of the Fund are traded on a stock exchange and are
subject to market risk like stocks, bonds and mutual funds. The Fund may invest in a less liquid portfolio of stocks and bonds because the fund does not need to sell securities to meet shareholder redemptions as mutual funds in order to keep a
percentage of its portfolio in cash to pay back investors who withdraw shares. |
|
|
|
JPMorgan Core Bond Trust-The Fund seeks to maximize total return by investing primarily in a diversified portfolio of intermediate- and long-term debt
securities. The Fund invests primarily in investment-grade bonds; it generally maintains an average weighted maturity between four and 12 years. It may shorten its average weighted maturity if deemed appropriate for temporary defensive purposes.
|
|
|
|
SSgA Russell 2000 Value Index Common Trust-The Fund measures the performance of the small-cap value segment of the U.S. equity universe. The Russell
2000 Value Index is constructed to provide a comprehensive and unbiased barometer for the small-cap value segment. The Index is completely reconstituted annually to ensure larger stocks do not distort the performance and characteristics of the true
small-cap opportunity set and that the represented companies continue to reflect value characteristics. |
|
|
|
NT Common Short-Term Investment Fund-The Fund seeks to maximize current income on cash reserves to the extent consistent with principal preservation
and maintenance of liquidity from a portfolio of approved money market instruments with short maturities. Liquidity is emphasized to provide for redemption of units at par on any business day. Principal preservation is a primary objective. Within
quality, maturity, and sector diversification guidelines, investments are made in those securities with the most attractive yields. |
Dominion
|
|
|
SSgA Daily MSCI Emerging Markets Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before
expenses, the performance of the MSCI Emerging Markets Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise
affiliated with the Trustee (State Street Bank and Trust Company).
|
|
|
|
SSgA Daily MSCI ACWI Ex-USA Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses,
the performance of the MSCI ACWI Ex-USA Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the
Trustee (State Street Bank and Trust Company). |
|
|
|
SSgA S&P 400 MidCap Index-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of its
benchmark index (the Index) over the long term. The S&P MidCap 400 is comprised of approximately 400 U.S. mid-cap securities and accounts for approximately 7% coverage of the U.S. stock market capitalization. SSgA will typically attempt to
invest in the equity securities comprising the Index, in approximately the same proportions as they are represented in the Index. |
|
|
|
JPMorgan Chase Bank U.S. Active Core Plus Equity Fund-The Fund seeks to outperform the S&P 500 Index (the Benchmark), gross of fees, over a market
cycle. The Fund invests primarily in a portfolio of long and short positions in equity securities of large and mid capitalization U.S. companies with characteristics similar to those of the Benchmark. |
|
|
|
Mondrian International Small Cap Equity Fund-The Funds investment objective is long-term total return. The Fund primarily invests in equity
securities of non-U.S. small capitalization companies that, in the investment managers opinion, are undervalued at the time of purchase based on fundamental value analysis employed by the investment manager. |
|
|
|
NT Collective Russell 2000 Growth Index-The Fund seeks an investment return that approximates the overall performance of the common stocks included in
the Russell 2000 Growth Index. The Fund primarily invests in common stocks of one or more companies that are deemed to be representative of the industry diversification of the entire Russell 2000 Growth Index. |
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NT Collective Short-Term Investment Fund-The Fund is composed of high-grade money market instruments with short-term maturities. The Funds
objective is to provide an investment vehicle for cash reserves while offering a competitive rate of return. Liquidity is emphasized to provide for redemption of units on any business day. Principal preservation is also a prime objective. Admissions
and withdrawals are made daily. Interest is accrued daily and distributed monthly. |
Investments in Group
Insurance Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate
debt instruments, and state and municipal debt securities.
Combined Notes to Consolidated Financial Statements, Continued
Net Periodic Benefit (Credit) Cost
Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in the Consolidated Statements of Income. The components of
the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominions and Dominion Gas (for employees represented by collective bargaining units)
plans are as follows:
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Pension Benefits |
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Other Postretirement Benefits |
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
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|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions, except percentages) |
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DOMINION |
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|
|
|
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|
Service cost |
|
$ |
114 |
|
|
$ |
131 |
|
|
$ |
116 |
|
|
$ |
32 |
|
|
$ |
43 |
|
|
$ |
44 |
|
Interest cost |
|
|
290 |
|
|
|
271 |
|
|
|
268 |
|
|
|
67 |
|
|
|
73 |
|
|
|
79 |
|
Expected return on plan assets |
|
|
(499 |
) |
|
|
(462 |
) |
|
|
(430 |
) |
|
|
(111 |
) |
|
|
(92 |
) |
|
|
(79 |
) |
Amortization of prior service (credit) cost |
|
|
3 |
|
|
|
3 |
|
|
|
3 |
|
|
|
(28 |
) |
|
|
(15 |
) |
|
|
(13 |
) |
Amortization of net actuarial loss |
|
|
111 |
|
|
|
165 |
|
|
|
132 |
|
|
|
2 |
|
|
|
7 |
|
|
|
6 |
|
Settlements and curtailments(1) |
|
|
1 |
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
(15 |
) |
|
|
(4 |
) |
Special termination benefits |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
Net periodic benefit (credit) cost |
|
$ |
20 |
|
|
$ |
106 |
|
|
$ |
89 |
|
|
$ |
(38 |
) |
|
$ |
2 |
|
|
$ |
33 |
|
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and
liabilities: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current year net actuarial (gain) loss |
|
$ |
784 |
|
|
$ |
(968 |
) |
|
$ |
786 |
|
|
$ |
183 |
|
|
$ |
(255 |
) |
|
$ |
139 |
|
Prior service (credit) cost |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
9 |
|
|
|
(215 |
) |
|
|
1 |
|
Settlements and curtailments(1) |
|
|
(1 |
) |
|
|
(22 |
) |
|
|
|
|
|
|
|
|
|
|
(7 |
) |
|
|
(2 |
) |
Less amounts included in net periodic benefit cost: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial loss |
|
|
(111 |
) |
|
|
(165 |
) |
|
|
(132 |
) |
|
|
(2 |
) |
|
|
(7 |
) |
|
|
(6 |
) |
Amortization of prior service credit (cost) |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
28 |
|
|
|
15 |
|
|
|
13 |
|
Total recognized in other comprehensive income and regulatory assets and
liabilities |
|
$ |
669 |
|
|
$ |
(1,157 |
) |
|
$ |
651 |
|
|
$ |
218 |
|
|
$ |
(469 |
) |
|
$ |
145 |
|
Significant assumptions used to determine periodic cost: |
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|
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|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
Discount rate |
|
|
5.20%-5.30 |
% |
|
|
4.40%-4.80 |
% |
|
|
5.50 |
% |
|
|
4.20%-5.10 |
% |
|
|
4.40%-4.80 |
% |
|
|
5.50 |
% |
Expected long-term rate of return on plan assets |
|
|
8.75 |
% |
|
|
8.50 |
% |
|
|
8.50 |
% |
|
|
8.50 |
% |
|
|
7.75 |
% |
|
|
7.75 |
% |
Weighted average rate of increase for compensation |
|
|
4.21 |
% |
|
|
4.21 |
% |
|
|
4.21 |
% |
|
|
4.22 |
% |
|
|
4.22 |
% |
|
|
4.22 |
% |
Healthcare cost trend rate(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.00 |
% |
|
|
7.00 |
% |
|
|
7.00 |
% |
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.00 |
% |
|
|
4.60 |
% |
|
|
4.60 |
% |
Year that the rate reaches the ultimate trend rate(2)(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018 |
|
|
|
2062 |
|
|
|
2061 |
|
DOMINION GAS |
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|
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|
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|
|
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|
|
|
|
|
|
|
|
Service cost |
|
$ |
12 |
|
|
$ |
13 |
|
|
$ |
11 |
|
|
$ |
6 |
|
|
$ |
7 |
|
|
$ |
7 |
|
Interest cost |
|
|
28 |
|
|
|
27 |
|
|
|
28 |
|
|
|
13 |
|
|
|
12 |
|
|
|
14 |
|
Expected return on plan assets |
|
|
(115 |
) |
|
|
(106 |
) |
|
|
(96 |
) |
|
|
(23 |
) |
|
|
(19 |
) |
|
|
(16 |
) |
Amortization of prior service (credit) cost |
|
|
1 |
|
|
|
1 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
(3 |
) |
|
|
(4 |
) |
Amortization of net actuarial loss |
|
|
19 |
|
|
|
26 |
|
|
|
26 |
|
|
|
|
|
|
|
2 |
|
|
|
1 |
|
Net periodic benefit (credit) cost |
|
$ |
(55 |
) |
|
$ |
(39 |
) |
|
$ |
(30 |
) |
|
$ |
(5 |
) |
|
$ |
(1 |
) |
|
$ |
2 |
|
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and
liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current year net actuarial (gain) loss |
|
$ |
43 |
|
|
$ |
(127 |
) |
|
$ |
35 |
|
|
$ |
40 |
|
|
$ |
(40 |
) |
|
$ |
12 |
|
Prior service cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
|
|
Less amounts included in net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net actuarial loss |
|
|
(19 |
) |
|
|
(26 |
) |
|
|
(26 |
) |
|
|
|
|
|
|
(2 |
) |
|
|
(1 |
) |
Amortization of prior service credit (cost) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
1 |
|
|
|
3 |
|
|
|
4 |
|
Total recognized in other comprehensive income and regulatory assets and
liabilities |
|
$ |
23 |
|
|
$ |
(154 |
) |
|
$ |
8 |
|
|
$ |
51 |
|
|
$ |
(39 |
) |
|
$ |
15 |
|
Significant assumptions used to determine periodic cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.20 |
% |
|
|
4.40%-4.80 |
% |
|
|
5.50 |
% |
|
|
4.20%-5.00 |
% |
|
|
4.40%-4.70 |
% |
|
|
5.50 |
% |
Expected long-term rate of return on plan assets |
|
|
8.75 |
% |
|
|
8.50 |
% |
|
|
8.50 |
% |
|
|
8.50 |
% |
|
|
7.75 |
% |
|
|
7.75 |
% |
Weighted average rate of increase for compensation |
|
|
3.93 |
% |
|
|
3.93 |
% |
|
|
3.93 |
% |
|
|
3.93 |
% |
|
|
3.93 |
% |
|
|
3.93 |
% |
Healthcare cost trend rate(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.00 |
% |
|
|
7.00 |
% |
|
|
7.00 |
% |
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.00 |
% |
|
|
4.60 |
% |
|
|
4.60 |
% |
Year that the rate reaches the ultimate trend rate(2)(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018 |
|
|
|
2062 |
|
|
|
2061 |
|
(1) |
2013 amounts relate primarily to the decommissioning of Kewaunee. |
(2) |
Assumptions used to determine net periodic cost for the following year. |
(3) |
The Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the ultimate trend rate much more
quickly than previous models. |
The components of AOCI and regulatory assets and liabilities for Dominions and
Dominion Gas (for employees represented by collective bargaining units) plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
At December 31, |
|
2014 |
|
|
2013 |
|
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
DOMINION |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial (gain) loss |
|
$ |
2,382 |
|
|
$ |
1,709 |
|
|
$ |
139 |
|
|
$ |
(40 |
) |
Prior service (credit) cost |
|
|
7 |
|
|
|
10 |
|
|
|
(233 |
) |
|
|
(271 |
) |
Total(1) |
|
$ |
2,389 |
|
|
$ |
1,719 |
|
|
$ |
(94 |
) |
|
$ |
(311 |
) |
DOMINION GAS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss |
|
$ |
303 |
|
|
$ |
279 |
|
|
$ |
43 |
|
|
$ |
3 |
|
Prior service (credit) cost |
|
|
1 |
|
|
|
2 |
|
|
|
7 |
|
|
|
(4 |
) |
Total(2) |
|
$ |
304 |
|
|
$ |
281 |
|
|
$ |
50 |
|
|
$ |
(1 |
) |
(1) |
As of December 31, 2014, of the $2.4 billion and $(94) million related to pension benefits and other postretirement benefits, $1.4 billion and $(81) million,
respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2013, of the $1.7 billion and $(311) million related to pension benefits and other postretirement benefits, $1.0 billion
and $(156) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. |
(2) |
As of December 31, 2014, of the $304 million related to pension benefits, $112 million is included in AOCI, with the remainder included in regulatory assets and
liabilities; the $50 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2013, of the $281 million related to pension benefits, $104 million is included in AOCI, with
the remainder included in regulatory assets and liabilities; the $(1) million related to other postretirement benefits is included entirely in regulatory assets and liabilities. |
The following table provides the components of AOCI and regulatory assets and liabilities for Dominions and Dominion Gas (for
employees represented by collective bargaining units) plans as of December 31, 2014 that are expected to be amortized as components of net periodic benefit (credit) cost in 2015:
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
(millions) |
|
|
|
|
|
|
DOMINION |
|
|
|
|
|
|
|
|
Net actuarial loss |
|
$ |
160 |
|
|
$ |
6 |
|
Prior service (credit) cost |
|
|
2 |
|
|
|
(27 |
) |
DOMINION GAS |
|
|
|
|
|
|
|
|
Net actuarial loss |
|
$ |
20 |
|
|
$ |
2 |
|
Prior service cost |
|
|
1 |
|
|
|
|
|
The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and
mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion develops assumptions, which are then compared to the forecasts of an independent investment advisor (except for the expected long-term rates of return) to
ensure reasonableness. An internal committee selects the final assumptions used for Dominions pension and other postretirement plans, including those in which Dominion Gas participates, including discount rates, expected long-term rates of
return, healthcare cost trend rates and mortality rates.
Dominion determines the expected long-term rates of return on plan
assets for its pension plans and other postretirement
benefit plans, including those in which Dominion Gas participates, 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, including those in which Dominion Gas participates.
Dominion develops its mortality assumption using plan-specific studies and projects mortality improvement using scales
developed by the Society of Actuaries for all its plans, including those in which Dominion Gas participates.
Assumed
healthcare cost trend rates have a significant effect on the amounts reported for Dominions retiree healthcare plans, including those in which Dominion Gas participates. A one percentage point change in assumed healthcare cost trend rates
would have had the following effects for Dominions and Dominion Gas (for employees represented by collective bargaining units) other postretirement benefit plans:
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefits |
|
|
|
One percentage point increase |
|
|
One percentage point decrease |
|
(millions) |
|
|
|
|
|
|
DOMINION |
|
|
|
|
|
|
|
|
Effect on net periodic cost for 2015 |
|
$ |
26 |
|
|
$ |
(16 |
) |
Effect on other postretirement benefit obligation at December 31, 2014 |
|
|
186 |
|
|
|
(152 |
) |
DOMINION GAS |
|
|
|
|
|
|
|
|
Effect on net periodic cost for 2015 |
|
$ |
5 |
|
|
$ |
(4 |
) |
Effect on other postretirement benefit obligation at December 31, 2014 |
|
|
40 |
|
|
|
(30 |
) |
Dominion Gas (Employees Not Represented by Collective Bargaining Units) and Virginia Power-Participation in Defined Benefit Plans
Virginia Power employees and Dominion Gas employees not represented by collective bargaining units are covered by the Dominion Pension
Plan described above. As participating employers, Virginia Power and Dominion Gas are subject to Dominions funding policy, which is to contribute annually an amount that is in accordance with ERISA. During 2014, Virginia Power and Dominion Gas
made no contributions to the Dominion Pension Plan, and no contributions to this plan are currently expected in 2015. Virginia Powers net periodic pension cost related to this plan was $75 million, $96 million and $72 million in 2014, 2013 and
2012, respectively. Dominion Gas net periodic pension credit related to this plan was $(37) million, $(27) million and $(25) million in 2014, 2013 and 2012, respectively. Net periodic pension (credit) cost is reflected in other operations
Combined Notes to Consolidated Financial Statements, Continued
and maintenance expense in their respective Consolidated Statements of Income. The funded status of various Dominion subsidiary groups and employee compensation are the basis for determining the
share of total pension costs for participating Dominion subsidiaries. See Note 24 for Virginia Power and Dominion Gas amounts due to/from Dominion related to this plan.
Retiree healthcare and life insurance benefits, for Virginia Power employees and for Dominion Gas employees not represented by collective bargaining units, are covered by the Dominion Retiree Health and
Welfare Plan described above. Virginia Powers net periodic benefit (credit) cost related to this plan was $(18) million, $5 million and $13 million in 2014, 2013 and 2012, respectively. Dominion Gas net periodic benefit (credit) cost
related to this plan was $(5) million, less than $1 million and $3 million for 2014, 2013 and 2012, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expenses in their respective Consolidated
Statements of Income. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion subsidiaries. See Note 24 for Virginia Power and Dominion Gas amounts due to/from Dominion related
to this plan.
Dominion holds investments in trusts to fund employee benefit payments for the pension and other postretirement
benefit plans in which Virginia Power and Dominion Gas employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be
included in the determination of the amount of cash that Virginia Power and Dominion Gas will provide to Dominion for their shares of employee benefit plan contributions.
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 and Dominion Gas fund other postretirement benefit costs through VEBAs. During 2014 and 2013, Virginia Power made no contributions to the VEBA and does not expect to
contribute to the VEBA in 2015. Dominion Gas contributions to VEBAs for employees not represented by collective bargaining units were $1 million and $2 million for 2014 and 2013, respectively.
Defined Contribution Plans
Dominion also sponsors
defined contribution employee savings plans that cover substantially all employees. During 2014, 2013 and 2012, Dominion recognized $41 million, $40 million and $40 million, respectively, as employer matching contributions to these plans. Dominion
Gas participates in these employee savings plans, both specific to Dominion Gas and that cover multiple Dominion subsidiaries. During 2014, 2013 and 2012, Dominion Gas recognized $7 million, $7 million and $6 million, respectively, as employer
matching contributions to these plans. Virginia Power also participates in these employee savings plans. During 2014, 2013 and 2012, Virginia Power recognized $17 million, $16 million and $15 million, respectively, as employer matching contributions
to these plans.
NOTE 22. COMMITMENTS AND CONTINGENCIES
As a result of issues generated in the ordinary course of business, the Companies 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. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated
insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any 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 the financial position, liquidity or results of operations of the Companies.
Environmental Matters
The Companies 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 the Companies 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 June 2014, the VDEQ granted a one-year MATS compliance extension for two coal-fired units at Yorktown to defer planned retirements and allow for
continued operation of the units to address reliability concerns while necessary electric transmission upgrades are being completed. During the fourth quarter of 2013, Virginia Power recorded charges totaling $26 million ($16 million after-tax) for
certain exit activities associated with these coal units, including the cost of employee severance, vendor contract termination, and inventory not expected to be used or usable at other stations.
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 a successful motion for stay, in October 2014, the U.S. Court of
Appeals for the D.C. Circuit ordered that the EPAs motion to lift the stay of CSAPR be granted. Further, the Court granted the EPAs request to shift the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets (which
would have gone into effect in 2012 and 2013) will apply in 2015 and 2016, and Phase 2 emissions budgets will apply in 2017 and beyond. CSAPR will replace CAIR beginning in January 2015. The cost to comply is not expected to be material to the
Consolidated Financial Statements. Future outcomes of any additional litigation and/or any 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. A number of the Companies 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. In November 2014, the EPA issued a new
proposal to revise the ozone standard and expects to finalize the rule in October 2015. The EPA is not expected to complete attainment designations for a new standard until 2017 and states will have until 2020 to develop plans to address the new
standard. Until the states have developed implementation plans, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significant expenditures are required to implement
additional controls, it could adversely affect the Companies results of operations and cash flows.
In August 2010, the
EPA issued revised National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. The rule was amended in March 2011 and January 2013. The rule establishes emission standards for control of hazardous air
pollutants for engines at smaller facilities, known
as area sources. As a result of these regulations, Dominion Gas installed emissions controls on several compressor engines. Dominion Gas has spent approximately $2 million to date and is
evaluating further expenditures. Dominion Gas is unable to estimate the additional potential impacts on results of operations, financial condition and/or cash flows related to this matter.
In August 2012, the EPA issued the first NSPS impacting the natural gas production and gathering sectors and made revisions to the NSPS
for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of volatile organic compound emissions for natural gas production wells, tanks, pneumatic
controllers, and compressors in the upstream sector. Compliance with these rules is required for installations and wells constructed or reconstructed after August 23, 2011. The cost to comply with the NSPS will depend on the number of new wells
and new equipment installations subject to the rule; therefore, Dominion Gas is unable to estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.
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. The Companies must comply with applicable aspects
of the CWA programs at their operating facilities.
In October 2014, the final regulations under Section 316(b) of the CWA
that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement
based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment
technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals
above two mgd, with a heightened entrainment analysis for those facilities over 125 mgd. Dominion and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. 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 are currently evaluating the need or potential for entrainment controls under the final 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. While the impacts of this rule could be material to Dominions and Virginia Powers results of operations, financial
condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.
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
Combined Notes to Consolidated Financial Statements, Continued
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, Virginia Power, or Dominion Gas 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, Virginia Power, or Dominion Gas 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 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 and 12 of which pertain to Dominion Gas. 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 the Companies 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. Virginia Power is currently evaluating the nature and extent of the contamination from this site as
well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential
financial statement impacts.
In December 2014, the EPA Administrator signed the final rule regulating the management of CCRs
stored in impoundments (ash ponds) and landfills and designating those CCRs as nonhazardous wastes under Subtitle D of the RCRA. The final rule regulates CCR landfills, ash ponds that still receive and manage CCRs (existing ash ponds), and ash ponds
that do not receive, but still store CCRs (inactive ash ponds). Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. Virginia Power is also evaluating
other features at its facilities for potential applicability under the final CCR rule. It is likely that the final rule will cause Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time.
After closure of these structures, Virginia Power will continue to perform required monitoring, corrective action, and post-closure care activities as necessary to comply with the final rule. While Virginia Power is still evaluating the cost of
compliance, there could be a material impact to its financial position, results of operations or cash flows.
CLIMATE
CHANGE LEGISLATION AND REGULATION
In October 2013, the U.S. Supreme Court
granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the D.C. Circuit Courts June 2012 decision upholding the EPAs regulation of GHG emissions from stationary sources under the
CAAs permitting programs. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the
EPAs ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. On July 24, 2014, the EPA issued a memorandum specifying that it will no longer apply or enforce federal
regulations or EPA-approved PSD state implementation plan provisions that require new and modified stationary sources to obtain a PSD permit when GHGs are the only pollutant that would be emitted at levels that exceed the permitting thresholds. In
addition, the EPA stated that it will continue to use the existing thresholds to apply to sources that are otherwise subject to PSD for conventional pollutants until it completes a new rulemaking either justifying and upholding those thresholds or
setting new ones. Some states have issued interim guidance that follows
the EPA guidance. Due to uncertainty regarding what additional actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the Court ruling
under a new rulemaking, the Companies cannot predict the impact to their financial statements at this time.
In July 2011, the EPA signed a final rule deferring the need for PSD and Title V permitting for CO2 emissions for biomass projects. This rule temporarily deferred for a
period of up to three years the consideration of CO2
emissions from biomass projects when determining whether a stationary source meets the PSD and Title V applicability thresholds, including those for the application of BACT. The deferral policy expired in July 2014. In July 2013, the U.S. Court
of Appeals for the D.C. Circuit vacated this rule; however, a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the
CO2 deferral period. It is unclear how the courts
decision or the EPAs final policy regarding the treatment of specific feedstock will affect biomass sources that were permitted during the deferral period; however, the expenditures to comply with any new requirements could be material to
Dominions and Virginia Powers financial statements.
Other Legal Matters
The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are
unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.
Appalachian Gateway
Following the completion of the Appalachian Gateway Project in 2012,
DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DTI filed a complaint in U.S. District Court, Eastern District of Virginia for breach of contract,
accounting and declaratory relief. The contractor filed a motion to dismiss, or in the alternative, a motion to transfer venue to Pennsylvania and/or West Virginia, where the pipelines were constructed. DTI filed an opposition to the
contractors motion in August 2013. In November 2013, the court granted the contractors motion on the basis that DTI must first comply with the dispute resolution process. Pursuant to the ruling, DTI intends to mediate the matter. This
case is pending. DTI has accrued a liability of approximately $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash
flows.
Ash Pond Closure Costs
In September 2014, Virginia Power received a notice from the SELC on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at the
Possum Point Power Station. The notice alleges unpermitted discharges to surface water and groundwater from Possum Points historical and active ash storage facilities. A similar notice from the SELC on behalf of Sierra Club was subsequently
received related to Chesapeake. In December 2014, Virginia Power offered to close all of its coal ash ponds and
landfills at Possum Point, Chesapeake and Bremo to the SELC as settlement of the potential litigation. In January 2015, the SELC declined the offer as presented, however the issue is open to
potential further negotiations. As a result of the settlement offer, Virginia Power recognized a charge of $121 million in other operations and maintenance expense in its Consolidated Statements of Income.
Cove Point
Dominion is constructing the
Liquefaction Project at the Cove Point facility, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. In April 2013, Cove Point filed with FERC for permission to build liquefaction and other facilities
related to the export of natural gas. In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project. In October 2014, several parties filed a motion with FERC to stay the
order and requested rehearing. The order remains in effect pending consideration of the motion by FERC.
In April 2013, Cove
Point filed an application with the Maryland Commission requesting authorization to construct a generating station in connection with the Liquefaction Project. In May 2014, the Maryland Commission granted the CPCN authorizing the construction of
such generating station. The CPCN obligates Cove Point to make payments totaling approximately $48 million. These payments consist of $40 million to the Strategic Energy Investments Fund over a five-year period beginning in 2015 and $8 million to
Maryland low income energy assistance programs over a twenty-year period expected to begin in 2018. In December 2014, upon receipt of applicable approvals to commence construction of the generating station, Dominion recorded the present value of the
obligation as an increase to property, plant and equipment and a corresponding liability.
In June 2014, a party filed a notice
of petition for judicial review of the CPCN with the Circuit Court for Baltimore City in Maryland. In September 2014, the party filed with the Maryland Commission a motion to stay the CPCN pending judicial review of the CPCN. In December 2014,
the Circuit Court issued an order affirming the Maryland Commissions grant of the CPCN and dismissing the appeal, and the motion for stay was denied by the Maryland Commission. In January 2015, the same party filed a Notice of Appeal of
the Baltimore Circuit Courts Order affirming the Maryland Commissions grant of the CPCN with the Court of Special Appeals for the Circuit Court of Baltimore City. This appeal is pending.
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
Combined Notes to Consolidated Financial Statements, Continued
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. Implementation of these enhancements is currently in progress. 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.
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 2014 calculation for the NRC
minimum financial assurance amount, aggregated for Dominions and Virginia Powers nuclear units, excluding joint owners assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.9
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 2014 NRC
minimum financial assurance amounts above were calculated using preliminary December 31, 2014 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 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 NRC minimum financial assurance requirement, which may include, if needed, the use of parent
company guarantees, surety bonding or other financial instruments recognized by the NRC. See Note 6 to the Consolidated Financial Statements for additional information on Kewaunee, and Note 9 for additional information on nuclear decommissioning
trust investments.
NUCLEAR INSURANCE
The Price-Anderson Amendments Act of 1988 provides the public up to $13.6 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 retrospective
rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to
the number of incidents for which this retrospective premium can be assessed.
The current levels of nuclear property insurance
coverage for Dominions and Virginia Powers nuclear units is as follows:
|
|
|
|
|
|
|
Coverage |
|
(billions) |
|
|
|
Dominion |
|
|
|
|
Millstone |
|
$ |
1.70 |
|
Kewaunee |
|
|
1.06 |
|
Virginia Power(1) |
|
|
|
|
Surry |
|
$ |
1.70 |
|
North Anna |
|
|
1.70 |
|
(1) |
Surry and North Anna share a blanket property limit of $200 million. |
Dominions and Virginia Powers nuclear property insurance coverage for Millstone, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per
reactor site. Kewaunee meets the NRC minimum requirement of $1.06 billion. This 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 $72 million
and $42 million, respectively. Based on the severity of the
incident, the Board of Directors of the nuclear insurer 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.
Millstone and Virginia Power also purchase accidental outage 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 $20 million and $9 million, respectively.
ODEC, a part owner of North
Anna, and Massachusetts Municipal and Green Mountain, 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 Dominions and Virginia Powers contracts with the DOE.
Dominion and Virginia Power have previously received damages award payments and settlement payments related to these contracts.
In 2012, Dominion and Virginia Power resolved additional claims for damages incurred at Millstone, Kewaunee, Surry and North Anna with the
Authorized Representative of the Attorney General. Dominion and Virginia Power entered into settlement agreements that resolved claims for damages incurred through December 31, 2010, and also provided for periodic payments after that date for
damages incurred through December 31, 2013.
By mutual agreement of the parties, the settlement agreements are extendable
to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone plants have been extended to provide for periodic payments for damages incurred through December 31, 2016. Possible
extension of the Kewaunee settlement agreement is being evaluated.
In 2014, Virginia Power and Dominion received payments of
$27 million for the resolution of claims incurred at North Anna and Surry for the period January 1, 2011 through December 31, 2012 and $17 million for the resolution of claims incurred at Millstone for the period of July 1, 2012 through June 30,
2013. In 2014, Dominion also received payments totaling $7 million for the resolution of claims incurred at Kewaunee for periods from January 1, 2011 through December 31, 2013. In 2013, Dominion received payment of $5 million for resolution of
claims incurred at Millstone for the period January 1, 2011 through June 30, 2012.
Dominion and Virginia Power 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 $69 million and $79 million at December 31, 2014 and 2013, respectively. Virginia Powers receivables for spent nuclear fuel-related costs
totaled $41 million and $50 million at December 31, 2014 and 2013, respectively.
Pursuant to a November 2013 decision of
the U.S Court of Appeals for the D.C. Circuit, in January 2014 the Secretary of the DOE sent a recommendation to the U.S. Congress to adjust to zero the current fee of $1 per MWh for electricity paid by civilian nuclear power generators for disposal
of spent nuclear fuel. The processes specified in the Nuclear Waste Policy Act for adjustment of the fee have been completed, and as of May 2014, Dominion and Virginia Power are no longer required to pay the waste fee. In 2014, Dominion and Virginia
Power recognized fees of $16 million and $10 million, respectively.
Dominion and Virginia Power will continue to manage their
spent fuel until it is accepted by the DOE.
Long-Term Purchase Agreements
At December 31, 2014, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased electric
capacity(1) |
|
$ |
313 |
|
|
$ |
250 |
|
|
$ |
158 |
|
|
$ |
104 |
|
|
$ |
65 |
|
|
$ |
99 |
|
|
$ |
989 |
|
(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, 2014, the present value of Virginia Powers
total commitment for capacity payments is $833 million. Capacity payments totaled $330 million, $345 million, and $337 million, and energy payments totaled $304 million, $236 million, and $214 million for the years ended 2014, 2013 and 2012,
respectively. |
Lease Commitments
The Companies 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, 2014 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion |
|
$ |
63 |
|
|
$ |
57 |
|
|
$ |
49 |
|
|
$ |
43 |
|
|
$ |
36 |
|
|
$ |
79 |
|
|
$ |
327 |
|
Virginia Power |
|
$ |
30 |
|
|
$ |
26 |
|
|
$ |
21 |
|
|
$ |
18 |
|
|
$ |
12 |
|
|
$ |
26 |
|
|
$ |
133 |
|
Dominion Gas |
|
$ |
28 |
|
|
$ |
25 |
|
|
$ |
23 |
|
|
$ |
21 |
|
|
$ |
19 |
|
|
$ |
25 |
|
|
$ |
141 |
|
Rental expense for Dominion totaled $92 million, $101 million, and $112 million for 2014, 2013 and 2012,
respectively. Rental expense for Virginia Power totaled $43 million, $42 million, and $48 million for 2014, 2013, and 2012, respectively. Rental expense for Dominion Gas totaled $35 million in 2014 and $15 million in each 2013 and 2012. The majority
of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.
Combined Notes to Consolidated Financial Statements, Continued
Guarantees, Surety Bonds and Letters of Credit
DOMINION
At December 31, 2014, Dominion had issued $74 million of guarantees, primarily to
support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2014, Dominions exposure under these guarantees was $49 million, primarily related to certain reserve
requirements associated with non-recourse financing.
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, 2014, Dominion had issued the following subsidiary guarantees:
|
|
|
|
|
|
|
|
|
|
|
Stated Limit |
|
|
Value(1)
|
|
(millions) |
|
|
|
|
|
|
Subsidiary debt(2) |
|
$ |
27 |
|
|
$ |
27 |
|
Commodity transactions(3) |
|
|
3,151 |
|
|
|
919 |
|
Nuclear obligations(4) |
|
|
215 |
|
|
|
76 |
|
Cove Point(5) |
|
|
1,910 |
|
|
|
|
|
Solar(6) |
|
|
531 |
|
|
|
396 |
|
Other(7) |
|
|
532 |
|
|
|
35 |
|
Total |
|
$ |
6,366 |
|
|
$ |
1,453 |
|
(1) |
Represents the estimated portion of the guarantees stated limit that is utilized as of December 31, 2014 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) |
Guarantee of debt of a DEI subsidiary. In the event of default by the subsidiary, Dominion would be obligated to repay such amounts. |
(3) |
Guarantees related to commodity commitments of certain subsidiaries, including subsidiaries of Virginia Power, Dominion Gas 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 (in the event of a prolonged outage) and Kewaunee, respectively, 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 Cove Point, in support of terminal services, transportation and construction. Two of the guarantees have no stated limit, one guarantee has a
$150 million limit, and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million. |
(6) |
Includes guarantees to facilitate the development of solar projects including guarantees to support the issuance of full notice to proceed under EPC agreements.
Includes certain guarantees that do not have stated limits. Also includes guarantees entered into by DEI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects. |
(7) |
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. Dominions maximum remaining cumulative exposure under these equity funding agreements is
$72 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits. |
Additionally, at December 31, 2014, Dominion had purchased $133 million of surety bonds, including $64 million at Virginia Power and
$30 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $48 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are
obligated to indemnify the respective surety bond company for any amounts paid.
As of December 31, 2014, Virginia Power had
issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. The related debt matures in 2031. In the event of default by a conduit, Virginia Power would be obligated to repay such amounts, which are limited to the
principal and interest then outstanding.
Indemnifications
As part of commercial contract negotiations in the normal course of business, the Companies 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. The Companies are unable to
develop an estimate of the maximum potential amount of any other 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, 2014, the Companies believe any other 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.
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.
The Companies 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, 2014 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 commercial 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 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 any collateral. At
December 31, 2014, Dominions credit exposure totaled $228 million. Of this amount, investment grade counterparties, including those internally rated, represented 86%, and no single counterparty, whether investment grade or
non-investment grade, exceeded $23 million of exposure.
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, 2014, Virginia Powers exposure to potential concentrations of credit risk was not considered material.
DOMINION GAS
Dominion Gas transacts mainly with major companies in the energy industry and with residential and commercial energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and
Midwest regions of the U.S. Dominion Gas does not believe that this geographic concentration contributes to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Gas is not exposed to a
significant concentration of credit risk for receivables arising from gas utility operations.
In 2014, DTI provided service to
260 customers with approximately 94% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 41% of the total storage and transportation revenue and the thirty largest provided
approximately 74% of the total storage and transportation revenue of approximately $718 million. Approximately 99% of the transmission capacity under contract on DTIs pipeline is subscribed with long-term contracts (three years or greater).
The remaining 1% is contracted on a year-to-year basis. Less than 1% of firm transportation capacity is currently unsubscribed. All storage services are subscribed under long-term contracts.
East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates established by the Ohio
Commission. Approximately 98% of East Ohio revenues are derived from its regulated gas distribution services. While individual customers of East Ohio have had increased amounts of bad debt in recent years, management believes that this concentration
and bad debt risk is mitigated by the regulatory framework established by the Ohio Commission. See Note 13 for further information about Ohios PIPP and UEX Riders that mitigate East Ohios overall credit risk.
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, 2014 and 2013, Dominion would have been required to post an additional $20 million and $146 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 $1 million in
collateral at December 31, 2014 and $76 million in collateral at December 31, 2013, 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
Combined Notes to Consolidated Financial Statements, Continued
December 31, 2014 and 2013 was $49 million and $169 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for
Virginia Power and Dominion Gas were not material as of December 31, 2014 and 2013. See Note 7 for further information about derivative instruments.
NOTE 24. RELATED-PARTY TRANSACTIONS
Virginia Power and Dominion Gas engage in related party transactions primarily with other Dominion subsidiaries (affiliates). Virginia
Powers and Dominion Gas 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 and Dominion Gas are included in
Dominions consolidated federal income tax return. A discussion of significant related party transactions follows.
VIRGINIA
POWER
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. See Notes 7 and 19 for more information. As of
December 31, 2014 and 2013, Virginia Powers derivative assets and liabilities with affiliates were not material.
Virginia Power participates in certain Dominion benefit plans as described in Note 21. At December 31, 2014 and 2013, Virginia
Powers amounts due to Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets, were $219 million and $144 million, respectively. At
December 31, 2014, Virginia Powers amounts due from Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred charges and other assets in the Consolidated Balance Sheets were $37 million and at
December 31, 2013, amounts due to Dominion and reflected in noncurrent pension and other postretirement benefit liabilities were $3 million.
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, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Commodity purchases from affiliates |
|
$ |
543 |
|
|
$ |
417 |
|
|
$ |
368 |
|
Services provided by affiliates(1) |
|
|
432 |
|
|
|
415 |
|
|
|
399 |
|
Services provided to affiliates |
|
|
22 |
|
|
|
21 |
|
|
|
19 |
|
(1) |
Includes capitalized expenditures.
|
Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were $427
million and $97 million in short-term demand note borrowings from Dominion as of December 31, 2014 and 2013, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion money pool for its nonregulated
subsidiaries as of December 31, 2014 and 2013. Interest charges related to Virginia Powers borrowings from Dominion were immaterial for the years ended December 31, 2014, 2013 and 2012.
There were no issuances of Virginia Powers common stock to Dominion in 2014, 2013 or 2012.
DOMINION GAS
Transactions
with Affiliates
Dominion Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the
ordinary course of business. Additionally, Dominion Gas provides transportation and storage services to affiliates. Dominion Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving
commodities or services. As of December 31, 2014 and 2013, all of Dominion Gas commodity derivatives were with affiliates. See Notes 7 and 19 for more information. See Note 9 for information regarding sales of assets to an affiliate.
Dominion Gas participates in certain Dominion benefit plans as described in Note 21. At December 31, 2014 and 2013, Dominion
Gas amounts due from Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets, were $614 million and $577 million, respectively. At
December 31, 2014 and 2013, Dominion Gas liabilities to Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred credits and other liabilities in the Consolidated Balance Sheets were $7 million and
$14 million, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Purchases of natural gas and transportation and storage services from affiliates |
|
$ |
34 |
|
|
$ |
31 |
|
|
$ |
14 |
|
Sales of natural gas and transportation and storage services to affiliates |
|
|
84 |
|
|
|
109 |
|
|
|
64 |
|
DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion
Gas. Dominion Gas provides certain services to affiliates, including technical services. The costs of these services follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2014 |
|
|
2013 |
|
|
2012 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Services provided by affiliates(1) |
|
$ |
106 |
|
|
$ |
116 |
|
|
$ |
107 |
|
Services provided to affiliates |
|
|
17 |
|
|
|
4 |
|
|
|
3 |
|
(1) |
Includes capitalized expenditures.
|
The following table presents affiliated and related party activity reflected in Dominion
Gas Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
At December 31, |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
Customer receivables from related parties(1) |
|
$ |
22 |
|
|
$ |
3 |
|
Imbalances receivable from affiliates(2) |
|
|
3 |
|
|
|
6 |
|
Imbalances payable to affiliates(3) |
|
|
|
|
|
|
1 |
|
Affiliated notes
receivable(4) |
|
|
9 |
|
|
|
5 |
|
(1) |
Includes $17 million due from Atlantic Coast Pipeline, an affiliated VIE. |
(2) |
Amounts are presented in other current assets in Dominion Gas Consolidated Balance Sheets. |
(3) |
Amounts are presented in other current liabilities in Dominion Gas Consolidated Balance Sheets. |
(4) |
Amounts are presented in other deferred charges and other assets in Dominion Gas Consolidated Balance Sheets. |
Dominion Gas borrowings under the IRCA with Dominion totaled $384 million and $1.3 billion as of December 31, 2014 and 2013,
respectively. Interest charges related to Dominion Gas total borrowings from Dominion were $4 million, $35 million and $61 million for the years ended December 31, 2014, 2013 and 2012, respectively.
NOTE 25. OPERATING SEGMENTS
The Companies 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 |
|
Dominion
Gas |
DVP |
|
Regulated electric distribution |
|
X |
|
X |
|
|
|
|
Regulated electric transmission |
|
X |
|
X |
|
|
Dominion Generation |
|
Regulated electric fleet |
|
X |
|
X |
|
|
|
|
Merchant electric fleet |
|
X |
|
|
|
|
|
|
Nonregulated retail energy marketing |
|
X |
|
|
|
|
Dominion Energy |
|
Gas transmission and storage(1) |
|
X |
|
|
|
X |
|
|
Gas distribution and storage |
|
X |
|
|
|
X |
|
|
Gas gathering and processing |
|
X |
|
|
|
X |
|
|
LNG import and storage |
|
X |
|
|
|
|
(1) |
Includes remaining producer services activities. |
In addition to the operating segments above, the Companies also report a Corporate and Other segment.
DOMINION
The Corporate and Other
Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued or sold. 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.
In January 2014, Dominion announced it would exit the electric retail energy marketing business. Dominion completed the sale in March 2014. As a result, the earnings impact from the electric retail energy
marketing business has been included in the Corporate and Other Segment of Dominion for 2014 first quarter results of operations.
In the second quarter of 2013, Dominion commenced a restructuring of its producer services business, 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 restructuring, which was completed in the first quarter of 2014, resulted in the termination of natural gas trading and certain energy marketing
activities. As a result, the earnings impact from natural gas trading and certain energy marketing activities has been included in the Corporate and Other Segment of Dominion for 2014.
In 2014, Dominion reported after-tax net expense of $970 million in the Corporate and Other segment, with $544 million of these net
expenses attributable to specific items related to its operating segments.
The net expenses for specific items in 2014
primarily related to the impact of the following items:
|
|
$374 million ($248 million after-tax) in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third
nuclear unit located at North Anna and offshore wind facilities, attributable to Dominion Generation; |
|
|
A $319 million ($193 million after-tax) net loss related to the producer services business discussed above, attributable to Dominion Energy; and
|
|
|
A $121 million ($74 million after-tax) charge related to a settlement offer to incur future ash pond closure costs at certain utility generation
facilities, attributable to Dominion Generation. |
In 2013, Dominion reported after-tax net expense of $452
million in the Corporate and Other segment, with $184 million of these net expenses attributable to specific items related to its operating segments.
The net expenses for specific items in 2013 primarily related to the impact of the following items:
|
|
A $135 million ($92 million after-tax) net loss from discontinued operations of Brayton Point and Kincaid, including debt extinguishment of $64 million
($38 million after-tax) related to the sale, impairment charges of $48 million ($28 million after-tax), a $17 million ($18 million after-tax) loss on the sale which includes a $16 million write-off of goodwill, and a $6 million ($8 million
after-tax) loss from operations, attributable to Dominion Generation; and |
|
|
A $182 million ($109 million after-tax) net loss, including a $55 million ($33 million after-tax) impairment charge related to certain natural gas
infrastructure assets and a $127 million ($76 million after-tax) loss related to the producer services business discussed above, attributable to Dominion Energy; partially offset by |
|
|
An $81 million ($49 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.
|
Combined Notes to Consolidated Financial Statements, Continued
In 2012, Dominion reported after-tax net expense of $1.7 billion in the Corporate and
Other segment, with $1.5 billion of these net expenses attributable to specific items related 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 discontinued operations, including impairment charges, of Brayton Point and Kincaid, which were
sold in 2013, attributable to Dominion Generation;
|
|
|
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. |
The following table presents segment
information pertaining to Dominions operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
DVP |
|
|
Dominion
Generation |
|
|
Dominion
Energy |
|
|
Corporate and Other |
|
|
Adjustments &
Eliminations |
|
|
Consolidated
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers |
|
$ |
1,918 |
|
|
$ |
7,665 |
|
|
$ |
1,718 |
|
|
$ |
(12 |
) |
|
$ |
1,147 |
|
|
$ |
12,436 |
|
Intersegment revenue |
|
|
18 |
|
|
|
70 |
|
|
|
1,174 |
|
|
|
572 |
|
|
|
(1,834 |
) |
|
|
|
|
Total operating revenue |
|
|
1,936 |
|
|
|
7,735 |
|
|
|
2,892 |
|
|
|
560 |
|
|
|
(687 |
) |
|
|
12,436 |
|
Depreciation, depletion and amortization |
|
|
462 |
|
|
|
516 |
|
|
|
241 |
|
|
|
73 |
|
|
|
|
|
|
|
1,292 |
|
Equity in earnings of equity method investees |
|
|
|
|
|
|
(18 |
) |
|
|
54 |
|
|
|
10 |
|
|
|
|
|
|
|
46 |
|
Interest income |
|
|
|
|
|
|
67 |
|
|
|
14 |
|
|
|
20 |
|
|
|
(33 |
) |
|
|
68 |
|
Interest and related charges |
|
|
205 |
|
|
|
240 |
|
|
|
11 |
|
|
|
770 |
|
|
|
(33 |
) |
|
|
1,193 |
|
Income taxes |
|
|
317 |
|
|
|
392 |
|
|
|
436 |
|
|
|
(693 |
) |
|
|
|
|
|
|
452 |
|
Net income (loss) attributable to Dominion |
|
|
502 |
|
|
|
1,101 |
|
|
|
677 |
|
|
|
(970 |
) |
|
|
|
|
|
|
1,310 |
|
Investment in equity method investees |
|
|
|
|
|
|
262 |
|
|
|
796 |
|
|
|
23 |
|
|
|
|
|
|
|
1,081 |
|
Capital expenditures |
|
|
1,652 |
|
|
|
2,466 |
|
|
|
1,329 |
|
|
|
104 |
|
|
|
|
|
|
|
5,551 |
|
Total assets (billions) |
|
|
13.0 |
|
|
|
24.2 |
|
|
|
12.7 |
|
|
|
8.7 |
|
|
|
(4.3 |
) |
|
|
54.3 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers |
|
$ |
1,825 |
|
|
$ |
8,445 |
|
|
$ |
1,783 |
|
|
$ |
3 |
|
|
$ |
1,064 |
|
|
$ |
13,120 |
|
Intersegment revenue |
|
|
9 |
|
|
|
68 |
|
|
|
1,063 |
|
|
|
609 |
|
|
|
(1,749 |
) |
|
|
|
|
Total operating revenue |
|
|
1,834 |
|
|
|
8,513 |
|
|
|
2,846 |
|
|
|
612 |
|
|
|
(685 |
) |
|
|
13,120 |
|
Depreciation, depletion and amortization |
|
|
427 |
|
|
|
518 |
|
|
|
228 |
|
|
|
35 |
|
|
|
|
|
|
|
1,208 |
|
Equity in earnings of equity method investees |
|
|
|
|
|
|
(14 |
) |
|
|
21 |
|
|
|
7 |
|
|
|
|
|
|
|
14 |
|
Interest income |
|
|
|
|
|
|
66 |
|
|
|
12 |
|
|
|
42 |
|
|
|
(66 |
) |
|
|
54 |
|
Interest and related charges |
|
|
175 |
|
|
|
220 |
|
|
|
26 |
|
|
|
522 |
|
|
|
(66 |
) |
|
|
877 |
|
Income taxes |
|
|
287 |
|
|
|
483 |
|
|
|
409 |
|
|
|
(287 |
) |
|
|
|
|
|
|
892 |
|
Loss from discontinued operations, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(92 |
) |
|
|
|
|
|
|
(92 |
) |
Net income (loss) attributable to Dominion |
|
|
475 |
|
|
|
1,031 |
|
|
|
643 |
|
|
|
(452 |
) |
|
|
|
|
|
|
1,697 |
|
Investment in equity method investees |
|
|
|
|
|
|
280 |
|
|
|
615 |
|
|
|
21 |
|
|
|
|
|
|
|
916 |
|
Capital expenditures |
|
|
1,361 |
|
|
|
1,605 |
|
|
|
1,043 |
|
|
|
95 |
|
|
|
|
|
|
|
4,104 |
|
Total assets (billions) |
|
|
11.9 |
|
|
|
22.0 |
|
|
|
12.1 |
|
|
|
8.5 |
|
|
|
(4.4 |
) |
|
|
50.1 |
|
2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers |
|
$ |
1,846 |
|
|
$ |
8,170 |
|
|
$ |
1,813 |
|
|
$ |
155 |
|
|
$ |
851 |
|
|
$ |
12,835 |
|
Intersegment revenue |
|
|
9 |
|
|
|
104 |
|
|
|
930 |
|
|
|
608 |
|
|
|
(1,651 |
) |
|
|
|
|
Total operating revenue |
|
|
1,855 |
|
|
|
8,274 |
|
|
|
2,743 |
|
|
|
763 |
|
|
|
(800 |
) |
|
|
12,835 |
|
Depreciation, depletion and amortization |
|
|
392 |
|
|
|
483 |
|
|
|
216 |
|
|
|
36 |
|
|
|
|
|
|
|
1,127 |
|
Equity in earnings of equity method investees |
|
|
|
|
|
|
3 |
|
|
|
23 |
|
|
|
(1 |
) |
|
|
|
|
|
|
25 |
|
Interest income |
|
|
1 |
|
|
|
65 |
|
|
|
30 |
|
|
|
71 |
|
|
|
(106 |
) |
|
|
61 |
|
Interest and related charges |
|
|
187 |
|
|
|
177 |
|
|
|
47 |
|
|
|
511 |
|
|
|
(106 |
) |
|
|
816 |
|
Income taxes |
|
|
278 |
|
|
|
576 |
|
|
|
352 |
|
|
|
(395 |
) |
|
|
|
|
|
|
811 |
|
Loss from discontinued operations, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,125 |
) |
|
|
|
|
|
|
(1,125 |
) |
Net income (loss) attributable to Dominion |
|
|
439 |
|
|
|
1,021 |
|
|
|
551 |
|
|
|
(1,709 |
) |
|
|
|
|
|
|
302 |
|
Capital expenditures |
|
|
1,158 |
|
|
|
1,615 |
|
|
|
1,350 |
|
|
|
22 |
|
|
|
|
|
|
|
4,145 |
|
Intersegment sales and transfers for Dominion are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation.
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.
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.
In 2014, Virginia Power reported after-tax net expenses of $342 million for specific items attributable to its operating segments in the
Corporate and Other segment.
The net expenses for specific items in 2014 primarily related to the impact of the following:
|
|
$374 million ($248 million after-tax) in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third
nuclear unit located at North Anna and offshore wind facilities, attributable to Dominion Generation; and
|
|
|
A $121 million ($74 million after-tax) charge related to a settlement offer to incur future ash pond closure costs at certain utility generation
facilities, attributable to Dominion Generation. |
In 2013, Virginia Power reported after-tax net expenses
of $47 million for specific items attributable to its operating segments in the Corporate and Other segment.
The net
expenses for specific items in 2013 primarily related to the impact of the following:
|
|
A $40 million ($28 million after-tax) charge in connection with the 2013 Biennial Review Order, attributable to Dominion Generation.
|
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.
|
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) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
1,928 |
|
|
$ |
5,651 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
7,579 |
|
Depreciation and amortization |
|
|
462 |
|
|
|
416 |
|
|
|
37 |
|
|
|
|
|
|
|
915 |
|
Interest income |
|
|
|
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
8 |
|
Interest and related charges |
|
|
205 |
|
|
|
203 |
|
|
|
3 |
|
|
|
|
|
|
|
411 |
|
Income taxes |
|
|
317 |
|
|
|
416 |
|
|
|
(185 |
) |
|
|
|
|
|
|
548 |
|
Net income (loss) |
|
|
509 |
|
|
|
691 |
|
|
|
(342 |
) |
|
|
|
|
|
|
858 |
|
Capital expenditures |
|
|
1,651 |
|
|
|
1,456 |
|
|
|
|
|
|
|
|
|
|
|
3,107 |
|
Total assets (billions) |
|
|
13.2 |
|
|
|
16.4 |
|
|
|
|
|
|
|
(0.1 |
) |
|
|
29.5 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
1,826 |
|
|
$ |
5,475 |
|
|
$ |
(6 |
) |
|
$ |
|
|
|
$ |
7,295 |
|
Depreciation and amortization |
|
|
427 |
|
|
|
425 |
|
|
|
1 |
|
|
|
|
|
|
|
853 |
|
Interest income |
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Interest and related charges |
|
|
175 |
|
|
|
192 |
|
|
|
2 |
|
|
|
|
|
|
|
369 |
|
Income taxes |
|
|
286 |
|
|
|
399 |
|
|
|
(26 |
) |
|
|
|
|
|
|
659 |
|
Net income (loss) |
|
|
483 |
|
|
|
702 |
|
|
|
(47 |
) |
|
|
|
|
|
|
1,138 |
|
Capital expenditures |
|
|
1,360 |
|
|
|
1,173 |
|
|
|
|
|
|
|
|
|
|
|
2,533 |
|
Total assets (billions) |
|
|
12.0 |
|
|
|
15.1 |
|
|
|
|
|
|
|
(0.1 |
) |
|
|
27.0 |
|
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 |
|
DOMINION GAS
The Corporate and Other Segment of Dominion Gas primarily includes specific items attributable to Dominion Gas operating segment that are not included in profit measures evaluated by
executive management in assessing the segments performance and the effect of certain items recorded at Dominion Gas as a result of Dominions basis in the net assets contributed.
In 2014, Dominion Gas reported after-tax net expenses of $9 million in its Corporate and
Other segment, with none of these net expenses attributable to specific items related to its operating segment.
In 2013,
Dominion Gas reported after-tax net expenses of $49 million in the Corporate and Other segment, with $41 million of these net expenses attributable to specific items related to its operating segment.
Combined Notes to Consolidated Financial Statements, Continued
The net expenses for specific items in 2013 primarily related to the impact of the
following:
|
|
$55 million ($33 million after-tax) of impairment charges related to certain natural gas infrastructure assets; and |
|
|
A $14 million ($8 million after-tax) charge primarily reflecting severance pay and other benefits related to workforce reductions.
|
In 2012, Dominion Gas reported after-tax net expenses of $10 million in its Corporate and
Other segment, with none of these net expenses attributable to specific items related to its operating segment.
The following table
presents segment information pertaining to Dominion Gas operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Dominion Energy |
|
|
Corporate and
Other |
|
|
Consolidated
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
1,898 |
|
|
$ |
|
|
|
$ |
1,898 |
|
Depreciation and amortization |
|
|
197 |
|
|
|
|
|
|
|
197 |
|
Equity in earnings of equity method investees |
|
|
21 |
|
|
|
|
|
|
|
21 |
|
Interest income |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Interest and related charges |
|
|
27 |
|
|
|
|
|
|
|
27 |
|
Income taxes |
|
|
340 |
|
|
|
(6 |
) |
|
|
334 |
|
Net income (loss) |
|
|
521 |
|
|
|
(9 |
) |
|
|
512 |
|
Investment in equity method investees |
|
|
107 |
|
|
|
|
|
|
|
107 |
|
Capital expenditures |
|
|
719 |
|
|
|
|
|
|
|
719 |
|
Total assets (billions) |
|
|
9.2 |
|
|
|
0.6 |
|
|
|
9.8 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
1,937 |
|
|
$ |
|
|
|
$ |
1,937 |
|
Depreciation and amortization |
|
|
188 |
|
|
|
|
|
|
|
188 |
|
Equity in earnings of equity method investees |
|
|
22 |
|
|
|
|
|
|
|
22 |
|
Interest income |
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Interest and related charges |
|
|
28 |
|
|
|
|
|
|
|
28 |
|
Income taxes |
|
|
333 |
|
|
|
(32 |
) |
|
|
301 |
|
Net income (loss) |
|
|
510 |
|
|
|
(49 |
) |
|
|
461 |
|
Investment in equity method investees |
|
|
105 |
|
|
|
|
|
|
|
105 |
|
Capital expenditures |
|
|
650 |
|
|
|
|
|
|
|
650 |
|
Total assets (billions) |
|
|
8.5 |
|
|
|
0.6 |
|
|
|
9.1 |
|
2012 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
1,677 |
|
|
$ |
|
|
|
$ |
1,677 |
|
Depreciation and amortization |
|
|
176 |
|
|
|
|
|
|
|
176 |
|
Equity in earnings of equity method investees |
|
|
23 |
|
|
|
|
|
|
|
23 |
|
Interest income |
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Interest and related charges |
|
|
40 |
|
|
|
|
|
|
|
40 |
|
Income taxes |
|
|
293 |
|
|
|
(5 |
) |
|
|
288 |
|
Net income (loss) |
|
|
469 |
|
|
|
(10 |
) |
|
|
459 |
|
Capital expenditures |
|
|
928 |
|
|
|
|
|
|
|
928 |
|
NOTE 26. QUARTERLY FINANCIAL AND COMMON STOCK
DATA (UNAUDITED)
A summary of the Companies quarterly results of operations for the years ended December 31, 2014 and 2013 follows.
Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.
DOMINION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter |
|
|
Second
Quarter |
|
|
Third
Quarter |
|
|
Fourth
Quarter |
|
|
Year |
|
(millions, except per share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
3,630 |
|
|
$ |
2,813 |
|
|
$ |
3,050 |
|
|
$ |
2,943 |
|
|
$ |
12,436 |
|
Income from operations |
|
|
768 |
|
|
|
394 |
|
|
|
921 |
|
|
|
638 |
|
|
|
2,721 |
|
Net income including noncontrolling interests |
|
|
385 |
|
|
|
161 |
|
|
|
531 |
|
|
|
249 |
|
|
|
1,326 |
|
Income from continuing operations(1) |
|
|
379 |
|
|
|
159 |
|
|
|
529 |
|
|
|
243 |
|
|
|
1,310 |
|
Net income attributable to Dominion |
|
|
379 |
|
|
|
159 |
|
|
|
529 |
|
|
|
243 |
|
|
|
1,310 |
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations(1) |
|
|
0.65 |
|
|
|
0.27 |
|
|
|
0.91 |
|
|
|
0.42 |
|
|
|
2.25 |
|
Net income attributable to Dominion |
|
|
0.65 |
|
|
|
0.27 |
|
|
|
0.91 |
|
|
|
0.42 |
|
|
|
2.25 |
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations(1) |
|
|
0.65 |
|
|
|
0.27 |
|
|
|
0.90 |
|
|
|
0.42 |
|
|
|
2.24 |
|
Net income attributable to Dominion |
|
|
0.65 |
|
|
|
0.27 |
|
|
|
0.90 |
|
|
|
0.42 |
|
|
|
2.24 |
|
Dividends declared per share |
|
|
0.60 |
|
|
|
0.60 |
|
|
|
0.60 |
|
|
|
0.60 |
|
|
|
2.40 |
|
Common stock prices (intraday high-low) |
|
$ |
72.22 - 63.14 |
|
|
$ |
73.75 - 67.06 |
|
|
$ |
71.62 - 64.71 |
|
|
$ |
80.89 - 65.53 |
|
|
$ |
80.89 - 63.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter |
|
|
Second
Quarter |
|
|
Third
Quarter |
|
|
Fourth
Quarter |
|
|
Year |
|
(millions, except per share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
3,523 |
|
|
$ |
2,980 |
|
|
$ |
3,432 |
|
|
$ |
3,185 |
|
|
$ |
13,120 |
|
Income from operations |
|
|
930 |
|
|
|
548 |
|
|
|
1,034 |
|
|
|
804 |
|
|
|
3,316 |
|
Net income including noncontrolling interests |
|
|
502 |
|
|
|
208 |
|
|
|
575 |
|
|
|
435 |
|
|
|
1,720 |
|
Income from continuing operations(1) |
|
|
494 |
|
|
|
272 |
|
|
|
592 |
|
|
|
431 |
|
|
|
1,789 |
|
Income (loss) from discontinued operations(1) |
|
|
1 |
|
|
|
(70 |
) |
|
|
(23 |
) |
|
|
|
|
|
|
(92 |
) |
Net income attributable to Dominion |
|
|
495 |
|
|
|
202 |
|
|
|
569 |
|
|
|
431 |
|
|
|
1,697 |
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations(1) |
|
|
0.86 |
|
|
|
0.47 |
|
|
|
1.02 |
|
|
|
0.74 |
|
|
|
3.09 |
|
Income (loss) from discontinued operations(1) |
|
|
|
|
|
|
(0.12 |
) |
|
|
(0.04 |
) |
|
|
|
|
|
|
(0.16 |
) |
Net income attributable to Dominion |
|
|
0.86 |
|
|
|
0.35 |
|
|
|
0.98 |
|
|
|
0.74 |
|
|
|
2.93 |
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations(1) |
|
|
0.86 |
|
|
|
0.47 |
|
|
|
1.02 |
|
|
|
0.74 |
|
|
|
3.09 |
|
Income (loss) from discontinued operations(1) |
|
|
|
|
|
|
(0.12 |
) |
|
|
(0.04 |
) |
|
|
|
|
|
|
(0.16 |
) |
Net income attributable to Dominion |
|
|
0.86 |
|
|
|
0.35 |
|
|
|
0.98 |
|
|
|
0.74 |
|
|
|
2.93 |
|
Dividends declared per share |
|
|
0.5625 |
|
|
|
0.5625 |
|
|
|
0.5625 |
|
|
|
0.5625 |
|
|
|
2.25 |
|
Common stock prices (intraday high-low) |
|
$ |
58.25 -
51.92 |
|
|
$ |
61.85 -
53.79 |
|
|
$ |
64.04 - 55.51 |
|
|
$ |
67.97 -
61.36 |
|
|
$ |
67.97 -
51.92 |
|
(1) |
Amounts attributable to Dominions common shareholders. |
Dominions 2014 results include the impact of the following significant items:
|
|
Fourth quarter results include $172 million in after-tax charges associated with the Liability Management Exercise in 2014 and $74 million in after-tax
costs related to Virginia Powers settlement offer to incur future ash pond closure costs at certain utility generation facilities. |
|
|
Second quarter results include $191 million in after-tax charges associated with Virginia legislation enacted in April 2014 relating to the development
of a third nuclear unit located at North Anna and offshore wind facilities. |
|
|
First quarter results include a $193 million after-tax reduction in revenues associated with the repositioning of Dominions producer services
business which was completed in the first quarter of 2014. |
Combined Notes to Consolidated Financial Statements, Continued
Dominions 2013 results include the impact of the following significant items:
|
|
Second quarter results include a $70 million after-tax net loss from discontinued operations of Brayton Point and Kincaid; and a $57 million after-tax
net loss, including a $33 million after-tax impairment charge related to certain natural gas infrastructure assets and a $24 million after-tax loss related to the producer services business. |
VIRGINIA POWER
Virginia Powers quarterly results of operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter |
|
|
Second
Quarter |
|
|
Third
Quarter |
|
|
Fourth
Quarter |
|
|
Year |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
1,983 |
|
|
$ |
1,729 |
|
|
$ |
2,053 |
|
|
$ |
1,814 |
|
|
$ |
7,579 |
|
Income from operations |
|
|
613 |
|
|
|
205 |
|
|
|
594 |
|
|
|
312 |
|
|
|
1,724 |
|
Net income |
|
|
324 |
|
|
|
69 |
|
|
|
314 |
|
|
|
151 |
|
|
|
858 |
|
Balance available for common stock |
|
|
318 |
|
|
|
67 |
|
|
|
312 |
|
|
|
148 |
|
|
|
845 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
1,781 |
|
|
$ |
1,710 |
|
|
$ |
2,059 |
|
|
$ |
1,745 |
|
|
$ |
7,295 |
|
Income from operations |
|
|
530 |
|
|
|
463 |
|
|
|
679 |
|
|
|
408 |
|
|
|
2,080 |
|
Net income |
|
|
287 |
|
|
|
265 |
|
|
|
387 |
|
|
|
199 |
|
|
|
1,138 |
|
Balance available for common stock |
|
|
283 |
|
|
|
261 |
|
|
|
383 |
|
|
|
194 |
|
|
|
1,121 |
|
Virginia Powers 2014 results include the impact of the following significant items:
|
|
Fourth quarter results include $74 million in after-tax costs related to Virginia Powers settlement offer to incur future ash pond closure costs
at certain utility generation facilities. |
|
|
Second quarter results include a $191 million after-tax charge associated with Virginia legislation enacted in April 2014 relating to the development
of a third nuclear unit located at North Anna and offshore wind facilities. |
Virginia Powers 2013
results include the impact of the following significant item:
|
|
Fourth quarter results include a $28 million after-tax charge resulting from impacts of the 2013 Biennial Review Order. |
DOMINION GAS
Dominion Gas quarterly results of operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter |
|
|
Second
Quarter |
|
|
Third
Quarter |
|
|
Fourth
Quarter |
|
|
Year |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
569 |
|
|
$ |
428 |
|
|
$ |
391 |
|
|
$ |
510 |
|
|
$ |
1,898 |
|
Income from operations |
|
|
265 |
|
|
|
154 |
|
|
|
177 |
|
|
|
255 |
|
|
|
851 |
|
Net income |
|
164 |
|
|
93 |
|
|
107 |
|
|
148 |
|
|
512 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
586 |
|
|
$ |
430 |
|
|
$ |
388 |
|
|
$ |
533 |
|
|
$ |
1,937 |
|
Income from operations |
|
|
224 |
|
|
|
88 |
|
|
|
217 |
|
|
|
233 |
|
|
|
762 |
|
Net income |
|
|
138 |
|
|
|
53 |
|
|
|
130 |
|
|
|
140 |
|
|
|
461 |
|
Dominion Gas 2014 results include the impact of the following significant item:
|
|
Fourth quarter results include a $36 million after-tax gain from agreements to convey Marcellus Shale development rights underneath several natural gas
storage fields. |
Dominion Gas 2013 results include the impact of the following significant item:
|
|
Second quarter results include a $33 million after-tax charge resulting from the impairment of certain natural gas infrastructure assets.
|
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 2014 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, 2014, 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, 2014. This assessment was based on criteria for effective internal control over financial
reporting described in Internal ControlIntegrated Framework (2013) 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, 2014.
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, 2015
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, 2014, based on criteria established in Internal ControlIntegrated Framework (2013) 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,
2014, based on the criteria established in Internal ControlIntegrated Framework (2013) 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, 2014 of Dominion and our report dated February 27, 2015 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 2015
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 2014 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, 2014, 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, 2014. This assessment was based on criteria for effective internal control over financial reporting described in Internal ControlIntegrated Framework (2013) 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, 2014.
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, 2015
DOMINION GAS
DISCLOSURE CONTROLS AND PROCEDURES
An evaluation of the effectiveness of the design and operation of Dominion Gas disclosure controls and procedures (as defined in Rules 13(a)-15(e)
and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended) was carried out under the supervision and with the participation of management, including the CEO and CFO of Dominion Gas. Based upon that evaluation, the CEO and CFO of Dominion
Gas concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2014, the end of the period covered by this report.
INTERNAL CONTROL OVER FINANCIAL REPORTING
The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules that generally require every company that files reports with the SEC to include a management report on such companys
internal control over financial reporting in its annual report. In addition, an independent registered public accounting firm must attest to a companys internal control over financial reporting. This first Annual Report on Form 10-K does not
include a report of managements assessment regarding internal control over financial reporting or an attestation report of Dominion Gas independent registered public accounting firm due to a transition period established by SEC rules
applicable to new public companies. Management will be required to provide an assessment of the effectiveness of Dominion Gas internal control over financial reporting as of December 31, 2015. Managements report will not be subject to
attestation by Dominion Gas independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL
REPORTING
There have been no changes in internal control over financial reporting that have materially affected, or are
reasonably likely to materially affect, Dominion Gas internal control over financial reporting during the quarter ended December 31, 2014.
Item 9B. Other Information
None.
Part III
Item 10. Directors, Executive Officers and Corporate Governance
DOMINION
The following information for Dominion is incorporated by reference from the
Dominion 2015 Proxy Statement, which will be filed on or around March 23, 2015:
|
|
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.
Item 11. Executive Compensation
DOMINION
The following information
about Dominion is contained in the 2015 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.
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 2015 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 2015 Proxy Statement is incorporated by reference.
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 2015 Proxy Statement is incorporated by reference.
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 2015 Proxy Statement is incorporated by reference.
VIRGINIA POWER AND DOMINION GAS
The following table presents fees paid to Deloitte & Touche LLP for services related to Virginia Power and Dominion Gas for the fiscal
years ended December 31, 2014 and 2013.
|
|
|
|
|
|
|
|
|
Type of Fees |
|
2014 |
|
|
2013 |
|
(millions) |
|
|
|
|
|
|
Virginia Power |
|
|
|
|
|
|
|
|
Audit fees |
|
$ |
1.96 |
|
|
$ |
1.89 |
|
Audit-related fees |
|
|
|
|
|
|
0.02 |
|
Tax fees |
|
|
|
|
|
|
|
|
All other fees |
|
|
|
|
|
|
|
|
Total fees |
|
$ |
1.96 |
|
|
$ |
1.91 |
|
Dominion Gas |
|
|
|
|
|
|
|
|
Audit fees |
|
$ |
0.52 |
|
|
$ |
|
|
Audit-related fees |
|
|
0.14 |
|
|
|
|
|
Tax fees |
|
|
|
|
|
|
|
|
All other fees |
|
|
|
|
|
|
|
|
Total fees |
|
$ |
0.66 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
Audit Fees represent fees of Deloitte & Touche LLP for the audit of Virginia Powers
and Dominion Gas annual consolidated financial statements, the review of financial statements included in Virginia Powers and Dominion Gas quarterly Form 10-Q reports, and the services that an independent auditor would customarily
provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC.
Audit-Related Fees consist of assurance and related services that are reasonably
related to the performance of the audit or review of Virginia Powers and Dominion Gas consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and
attest services not required by statute or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.
Virginia Powers and Dominion Gas Boards of Directors have adopted the Dominion Audit Committee pre-approval policy for their
independent auditors services and fees and have 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 January 2015 meeting, the Dominion Audit Committee approved Virginia Powers and Dominion Gas schedules of services and fees for 2015. 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.
The audit fees for Dominion Gas presented above for the year ended December 31, 2014, were for professional services rendered during the
period subsequent to Dominion Gas becoming an SEC registrant. Total audit fees and audit-related fees incurred prior to Dominion Gas becoming an SEC registrant were $680 thousand and $70 thousand, respectively, and were paid by Dominion.
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 56.
2. All schedules are omitted because they are not applicable, or the
required information is either not material or is shown in the financial statements or the related notes.
3. Exhibits (incorporated by
reference unless otherwise noted)
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Exhibit Number |
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Description |
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Dominion |
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Virginia Power |
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Dominion Gas |
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2 |
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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). |
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X |
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3.1.a |
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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). |
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X |
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3.1.b |
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Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255). |
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X |
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3.1.c |
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Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066). |
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X |
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3.2.a |
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Dominion Resources, Inc. Amended and Restated Bylaws, effective May 3, 2013 (Exhibit 3.1, Form 8-K filed May 3, 2013, File No. 1-8489). |
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X |
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3.2.b |
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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). |
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X |
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3.2.c |
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Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066). |
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X |
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4 |
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Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC 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. |
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X |
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X |
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X |
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4.1.a |
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See Exhibit 3.1.a above. |
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X |
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4.1.b |
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See Exhibit 3.1.b above. |
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X |
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4.2 |
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Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indenture (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). |
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X |
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X |
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4.3 |
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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 Tenth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.3, Form 8-K filed December 4, 2003, File No.
1-2255); Form of Twelfth Supplemental Indenture, dated January 1, 2006 (Exhibit 4.2, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Thirteenth Supplemental Indenture, dated as of January 1, 2006 (Exhibit 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); Form of Seventeenth Supplemental Indenture, dated November 1, 2007 (Exhibit 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- |
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X |
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X |
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Exhibit Number |
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Description |
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Dominion |
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Virginia Power |
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Dominion Gas |
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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); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1, 2014
(Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No. 1-2255). |
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4.4 |
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Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank
(formerly The Chase Manhattan Bank)) as supplemented by a Form of Second Supplemental Indenture, dated January 1, 2001 (Exhibit 4.6, Form 8-K filed January 12, 2001, File No. 1-8489). |
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X |
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4.5 |
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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); 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, 2026); 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). |
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X |
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4.6 |
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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 Sixteenth Supplemental Indenture, dated December 1, 2002 (Exhibit 4.3, Form 8-K filed December 13, 2002, File
No. 1-8489); Form of Twenty-First Supplemental Indenture, dated March 1, 2003 (Exhibits 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-Fifth Supplemental Indenture, dated January 1, 2004 (Exhibit 4.2, 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); Form of Twenty-Ninth Supplemental Indenture, dated June 1, 2005 (Exhibit 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-Second Supplemental Indenture, dated November 1, 2006 (Exhibit 4.2, 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 30, 2007, File No. 1-8489); Forms of Thirty-Fifth and Thirty-Sixth Supplemental Indentures,
dated June 1, 2008 (Exhibits 4.2 and 4.3, 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 |
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Exhibit Number |
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Description |
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Dominion |
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Virginia Power |
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Dominion Gas |
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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); Forty-Eighth Supplemental Indenture, dated
March 1, 2014 (Exhibit 4.3, Form 8-K, filed March 24, 2014, File No. 1-8489); Forty-Ninth Supplemental Indenture, dated November 1, 2014 (Exhibit 4.3, Form 8-K, filed November 25, 2014, File No. 1-8489); Fiftieth Supplemental Indenture,
dated November 1, 2014 (Exhibit 4.4, Form 8-K, filed November 25, 2014, File No. 1-8489); Fifty-First Supplemental Indenture, dated November 1, 2014 (Exhibit 4.5, Form 8-K, filed November 25, 2014, File No. 1-8489). |
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4.7 |
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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 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). |
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X |
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4.8 |
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Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee
(Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended
June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental
and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489); Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental
Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture,
dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2014, File No. 1-8489). |
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X |
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4.9 |
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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). |
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X |
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4.10 |
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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). |
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X |
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4.11 |
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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), as amended by Amendment
No. 1 to Replacement Capital Covenant dated July 18, 2014 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2014 filed July 30, 2014, File No. 1-8489). |
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X |
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4.12 |
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Series A Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent,
Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.7, Form 8-K filed June 7, 2013, File No. 1-8489). |
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X |
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4.13 |
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Series B Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent,
Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.8, Form 8-K filed June 7, 2013, File No. 1-8489). |
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X |
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Exhibit Number |
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Description |
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Dominion |
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Virginia Power |
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Dominion Gas |
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4.14 |
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2014 Series A Purchase Contract and Pledge Agreement, dated as of July 1, 2014, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract
Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.5, Form 8-K filed July 1, 2014, File No. 1-8489). |
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X |
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4.15 |
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Indenture, dated as of October 1, 2013, between Dominion Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form S-4 filed April 4, 2014, File
No. 333-195066); First Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.2, Form S-4 filed April 4, 2014, File No. 333-195066); Second Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.3, Form S-4 filed April 4, 2014,
File No. 333-195066); Third Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.4, Form S-4 filed April 4, 2014, File No. 333-195066); Fourth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.2, Form 8-K filed December
8, 2014, File No. 333-195066); Fifth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.3, Form 8-K filed December 8, 2014, File No. 333-195066); Sixth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.4, Form 8-K filed
December 8, 2014, File No. 333-195066). |
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X |
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X |
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10.1 |
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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). |
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X |
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10.2 |
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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). |
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X |
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10.3 |
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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). |
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X |
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X |
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10.4 |
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$4,000,000,000 Five-Year Amended and Restated Revolving Credit Agreement, dated May 19, 2014, among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas
Holdings, LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, The Royal Bank of Scotland plc, Bank of America, N.A., Barclays Bank PLC and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein (Exhibit 10.1, Form 8-K
filed May 19, 2014, File No. 1-8489 and File No. 1-2255). |
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X |
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X |
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X |
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10.5 |
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$500,000,000 Five-Year Amended and Restated Revolving Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, Keybank
National Association, as Administrative Agent, U.S. Bank National Association, as Syndication Agent, and other lenders named therein (Exhibit 10.1, Form 8-K filed June 2, 2014, File No. 1-8489 and File
No. 1-2255). |
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X |
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X |
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X |
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10.6 |
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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). |
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X |
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X |
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10.7* |
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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), as amended September 26, 2014 (Exhibit 10.1, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). |
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X |
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X |
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X |
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10.8* |
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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). |
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X |
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X |
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X |
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10.9* |
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Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company dated January 24, 2013 (effective for certain
officers elected subsequent to February 1, 2013) (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2013 filed February 27, 2014, File No. 1-8489 and File No. 1-2255). |
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X |
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X |
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X |
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Exhibit Number |
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Description |
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Dominion |
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Virginia Power |
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Dominion Gas |
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10.10* |
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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),
as amended September 26, 2014 (Exhibit 10.2, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). |
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X |
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X |
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X |
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10.11* |
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Dominion Resources, Inc. Executives Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No.
1-8489). |
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X |
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X |
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X |
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10.12* |
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Dominion Resources, Inc. New Executive Supplemental Retirement Plan, as amended and restated effective July 1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013
filed August 6, 2013 File No. 1-8489), as amended September 26, 2014 (Exhibit 10.3, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). |
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X |
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X |
|
|
|
X |
|
|
|
|
|
|
10.13* |
|
Dominion Resources, Inc. New Retirement Benefit Restoration Plan, 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), as amended September 26, 2014 (Exhibit 10.4, Form 10-Q for the
fiscal quarter ended September 30, 2014 filed November 3, 2014). |
|
|
X |
|
|
|
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. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated May 7, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended
June 30, 2014 filed July 30, 2014, File No. 1-8489 and File No. 1-2250). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.19* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.20* |
|
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 |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.21* |
|
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 |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.22* |
|
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 |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit Number |
|
Description |
|
Dominion |
|
|
Virginia Power |
|
|
Dominion Gas |
|
|
|
|
|
|
10.23* |
|
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 |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.24* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.25* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.26* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.27* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.28* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.29* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.30* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.31* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.32* |
|
Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012,
File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.33* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.34* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.35* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.36* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.37* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.38* |
|
Retirement Agreement, dated as of June 20, 2013, between Dominion Resources, Inc. and Gary L. Sypolt (Exhibit 10.1, Form 8-K filed June 24, 2013, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.39* |
|
2014 Performance Grant Plan under 2014 Long-Term Incentive Program approved January 16, 2014 (Exhibit 10.40, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.40* |
|
Form of Restricted Stock Award Agreement under the 2014 Long-term Incentive Program approved January 16, 2014 (Exhibit 10.41, Form 10-K for the fiscal year ended December 31,
2013, File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.41* |
|
Form of Special Performance Grant for Thomas F. Farrell II and Mark F. McGettrick approved January 16, 2014 (Exhibit 10.42, Form 10-K for the fiscal year ended December 31, 2013,
File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit Number |
|
Description |
|
Dominion |
|
|
Virginia Power |
|
|
Dominion Gas |
|
|
|
|
|
|
10.42* |
|
2015 Performance Grant Plan under 2015 Long-Term Incentive Program approved January 22, 2015 (filed herewith). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.43* |
|
Form of Restricted Stock Award Agreement under the 2015 Long-term Incentive Program approved January 22, 2015 (filed herewith). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.44* |
|
Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith). |
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.45* |
|
Non-employee directors annual compensation for Dominion Resources, Inc. (filed herewith). |
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.46* |
|
Dominion Resources, Inc. 2014 Incentive Compensation Plan, effective May 7, 2014 (Exhibit 10.1, Form 8-K filed May 7, 2014, File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.47 |
|
Registration Rights Agreement, dated as of October 22, 2013, by and among Dominion Gas Holdings, LLC and RBC Capital Markets, LLC, RBS Securities Inc. and Scotia Capital (USA) Inc.,
as the initial purchasers of the Notes (Exhibit 10.1, Form S-4 filed April 4, 2014, File No. 333-195066). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
10.48 |
|
Inter-Company Credit Agreement, dated October 17, 2013, between Dominion Resources, Inc. and Dominion Gas Holdings, LLC (Exhibit 10.2, Form S-4 filed April 4, 2014, File No. 333-195066). |
|
|
X |
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
10.49 |
|
DRS Services Agreement, dated September 12, 2013, between Dominion Gas Holdings, LLC and Dominion Resources Services, Inc. (Exhibit 10.3, Form S-4 filed April 4, 2014, File
No. 333-195066). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
10.50 |
|
DRS Services Agreement, dated January 1, 2003, between Dominion Transmission Inc. and Dominion Resources Services, Inc. (Exhibit 10.4, Form S-4 filed April 4, 2014, File No. 333-195066). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
10.51 |
|
DRS Services Agreement, dated January 1, 2003, between The East Ohio Company and Dominion Resources Services, Inc. (Exhibit 10.5, Form S-4 filed April 4, 2014, File No.
333-195066). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
10.52 |
|
DRS Services Agreement, dated January 1, 2003, between Dominion Iroquois, Inc. and Dominion Resources Services, Inc. (Exhibit 10.6, Form S-4 filed April 4, 2014, File No.
333-195066). |
|
|
|
|
|
|
|
|
|
|
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 for Dominion Gas Holdings, LLC (filed herewith). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
21 |
|
Subsidiaries of Dominion Resources, Inc. (filed herewith). |
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23 |
|
Consent of Deloitte & Touche LLP (filed herewith). |
|
|
X |
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
31.e |
|
Certification by Chief Executive Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
31.f |
|
Certification by Chief Financial Officer of Dominion Gas Holdings, LLC 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 |
|
|
Dominion Gas |
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
32.c |
|
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the
Sarbanes-Oxley Act of 2002 (furnished herewith). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
101 |
|
The following financial statements from Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC Annual Report on Form 10-K for the year ended
December 31, 2014, filed on February 27, 2015, 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 |
|
|
|
X |
|
* |
Indicates management contract or compensatory plan or arrangement |
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 27, 2015
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 27th day
of February, 2015.
|
|
|
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/ James O. Ellis,
Jr. James O. Ellis, Jr. |
|
Director |
|
|
/s/ John W.
Harris John W. Harris |
|
Director |
|
|
/s/ Mark J.
Kington Mark J. Kington |
|
Director |
|
|
/s/ Pamela J.
Royal Pamela J. Royal |
|
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/ Michele L.
Cardiff Michele L. Cardiff |
|
Vice President, Controller and 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 27, 2015
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 27th day
of February, 2015.
|
|
|
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/ Mark O.
Webb Mark O. Webb |
|
Director |
|
|
/s/ Michele L.
Cardiff Michele L. Cardiff |
|
Vice President, Controller and Chief Accounting Officer |
Dominion Gas
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 GAS HOLDINGS, LLC |
|
|
By: |
|
/S/ THOMAS F. FARRELL
II |
|
|
(Thomas F. Farrell II, Chairman of the Board
of Directors and Chief Executive Officer) |
Date: February 27, 2015
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 27th day
of February, 2015.
|
|
|
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/ Mark O.
Webb Mark O. Webb |
|
Director |
|
|
/s/ Michele L.
Cardiff Michele L. Cardiff |
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Vice President, Controller and Chief Accounting Officer |
Exhibit Index
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Exhibit Number |
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Description |
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Dominion |
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Virginia Power |
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Dominion Gas |
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2 |
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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). |
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X |
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3.1.a |
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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). |
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X |
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3.1.b |
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Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255). |
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X |
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3.1.c |
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Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066). |
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X |
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3.2.a |
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Dominion Resources, Inc. Amended and Restated Bylaws, effective May 3, 2013 (Exhibit 3.1, Form 8-K filed May 3, 2013, File No. 1-8489). |
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X |
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3.2.b |
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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). |
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X |
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3.2.c |
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Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066). |
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X |
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4 |
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Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC 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. |
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X |
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X |
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X |
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4.1.a |
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See Exhibit 3.1.a above. |
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X |
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4.1.b |
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See Exhibit 3.1.b above. |
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X |
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4.2 |
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Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indenture (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). |
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X |
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X |
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4.3 |
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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 Tenth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.3, Form 8-K filed December 4, 2003, File No.
1-2255); Form of Twelfth Supplemental Indenture, dated January 1, 2006 (Exhibit 4.2, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Thirteenth Supplemental Indenture, dated as of January 1, 2006 (Exhibit 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); Form of Seventeenth Supplemental Indenture, dated November 1, 2007 (Exhibit 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); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3,
Form 8-K filed March 14, 2013, File No. 1-2255); Twenty- |
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X |
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X |
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Exhibit Number |
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Description |
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Dominion |
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Virginia Power |
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Dominion Gas |
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Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1,
2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No. 1-2255). |
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4.4 |
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Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank
(formerly The Chase Manhattan Bank)) as supplemented by a Form of Second Supplemental Indenture, dated January 1, 2001 (Exhibit 4.6, Form 8-K filed January 12, 2001, File No. 1-8489). |
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X |
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4.5 |
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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); 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, 2026); 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). |
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X |
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4.6 |
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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 Sixteenth Supplemental Indenture, dated December 1, 2002 (Exhibit 4.3, Form 8-K filed December 13, 2002, File
No. 1-8489); Form of Twenty-First Supplemental Indenture, dated March 1, 2003 (Exhibits 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-Fifth Supplemental Indenture, dated January 1, 2004 (Exhibit 4.2, 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); Form of Twenty-Ninth Supplemental Indenture, dated June 1, 2005 (Exhibit 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-Second Supplemental Indenture, dated November 1, 2006 (Exhibit 4.2, 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 30, 2007, File No. 1-8489); Forms of Thirty-Fifth and Thirty-Sixth Supplemental Indentures,
dated June 1, 2008 (Exhibits 4.2 and 4.3, 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); Forty-Eighth Supplemental Indenture, dated March 1, 2014 (Exhibit 4.3, Form 8-K, filed March 24, 2014, File No. 1-8489); Forty-Ninth Supplemental Indenture, dated November 1, 2014 (Exhibit 4.3, Form 8-K, filed November 25, 2014,
File No. 1-8489); Fiftieth |
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X |
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Exhibit Number |
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Description |
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Dominion |
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Virginia Power |
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Dominion Gas |
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Supplemental Indenture, dated November 1, 2014 (Exhibit 4.4, Form 8-K, filed November 25, 2014, File No. 1-8489); Fifty-First Supplemental Indenture, dated November 1, 2014 (Exhibit
4.5, Form 8-K, filed November 25, 2014, File No. 1-8489). |
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4.7 |
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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 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). |
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X |
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4.8 |
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Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee
(Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended
June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental
and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489); Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental
Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture,
dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2014, File No. 1-8489). |
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X |
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4.9 |
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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). |
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X |
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4.10 |
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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). |
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X |
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4.11 |
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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), as amended by Amendment
No. 1 to Replacement Capital Covenant dated July 18, 2014 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2014 filed July 30, 2014, File No. 1-8489). |
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X |
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4.12 |
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Series A Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent,
Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.7, Form 8-K filed June 7, 2013, File No. 1-8489). |
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X |
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4.13 |
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Series B Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent,
Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.8, Form 8-K filed June 7, 2013, File No. 1-8489). |
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X |
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4.14 |
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2014 Series A Purchase Contract and Pledge Agreement, dated as of July 1, 2014, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract
Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.5, Form 8-K filed July 1, 2014, File No. 1-8489). |
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X |
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4.15 |
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Indenture, dated as of October 1, 2013, between Dominion Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form S-4 filed April 4, 2014, File
No. 333-195066); First Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.2, |
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X |
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X |
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Exhibit Number |
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Description |
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Dominion |
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Virginia Power |
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Dominion Gas |
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Form S-4 filed April 4, 2014, File No. 333-195066); Second Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.3, Form S-4 filed April 4, 2014, File No. 333-195066);
Third Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.4, Form S-4 filed April 4, 2014, File No. 333-195066); Fourth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.2, Form 8-K filed December 8, 2014, File No.
333-195066); Fifth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.3, Form 8-K filed December 8, 2014, File No. 333-195066); Sixth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.4, Form 8-K filed December 8, 2014,
File No. 333-195066). |
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10.1 |
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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). |
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X |
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10.2 |
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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). |
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X |
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10.3 |
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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). |
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X |
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X |
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10.4 |
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$4,000,000,000 Five-Year Amended and Restated Revolving Credit Agreement, dated May 19, 2014, among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas
Holdings, LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, The Royal Bank of Scotland plc, Bank of America, N.A., Barclays Bank PLC and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein (Exhibit 10.1, Form 8-K
filed May 19, 2014, File No. 1-8489 and File No. 1-2255). |
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X |
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X |
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X |
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10.5 |
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$500,000,000 Five-Year Amended and Restated Revolving Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, Keybank
National Association, as Administrative Agent, U.S. Bank National Association, as Syndication Agent, and other lenders named therein (Exhibit 10.1, Form 8-K filed June 2, 2014, File No. 1-8489 and File
No. 1-2255). |
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X |
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X |
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X |
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10.6 |
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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). |
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X |
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X |
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10.7* |
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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), as amended September 26, 2014 (Exhibit 10.1, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). |
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X |
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X |
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X |
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10.8* |
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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). |
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X |
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X |
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X |
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10.9* |
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Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company dated January 24, 2013 (effective for certain
officers elected subsequent to February 1, 2013) (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2013 filed February 27, 2014, File No. 1-8489 and File No. 1-2255). |
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X |
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X |
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X |
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10.10* |
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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),
as amended September 26, 2014 (Exhibit 10.2, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). |
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X |
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X |
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X |
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10.11* |
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Dominion Resources, Inc. Executives Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No.
1-8489). |
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X |
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X |
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X |
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Exhibit Number |
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Description |
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Dominion |
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Virginia Power |
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Dominion Gas |
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10.12* |
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Dominion Resources, Inc. New Executive Supplemental Retirement Plan, as amended and restated effective July 1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013
filed August 6, 2013 File No. 1-8489), as amended September 26, 2014 (Exhibit 10.3, Form 10-Q for the fiscal quarter ended September 30, 2014 filed November 3, 2014). |
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X |
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X |
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X |
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10.13* |
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Dominion Resources, Inc. New Retirement Benefit Restoration Plan, 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), as amended September 26, 2014 (Exhibit 10.4, Form 10-Q for the
fiscal quarter ended September 30, 2014 filed November 3, 2014). |
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X |
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X |
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X |
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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). |
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|
X |
|
|
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|
|
|
|
|
|
|
|
|
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|
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). |
|
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X |
|
|
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|
|
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|
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). |
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|
X |
|
|
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|
|
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|
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|
|
|
|
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|
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). |
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X |
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10.18* |
|
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated May 7, 2014 (Exhibit 10.4, Form 10-Q for the fiscal quarter ended
June 30, 2014 filed July 30, 2014, File No. 1-8489 and File No. 1-2250). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
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|
10.19* |
|
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 |
|
|
|
X |
|
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|
10.20* |
|
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). |
|
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X |
|
|
|
X |
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|
|
X |
|
|
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|
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|
10.21* |
|
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 |
|
|
|
X |
|
|
|
X |
|
|
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|
10.22* |
|
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). |
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X |
|
|
|
X |
|
|
|
X |
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10.23* |
|
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). |
|
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X |
|
|
|
X |
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X |
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10.24* |
|
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 |
|
|
X |
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|
|
X |
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|
X |
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|
Exhibit Number |
|
Description |
|
Dominion |
|
|
Virginia Power |
|
|
Dominion Gas |
|
|
|
(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). |
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10.25* |
|
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 |
|
|
|
X |
|
|
|
|
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|
10.26* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.27* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.28* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.29* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.30* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.31* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.32* |
|
Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012,
File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.33* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.34* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.35* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.36* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.37* |
|
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 |
|
|
|
X |
|
|
|
|
|
|
10.38* |
|
Retirement Agreement, dated as of June 20, 2013, between Dominion Resources, Inc. and Gary L. Sypolt (Exhibit 10.1, Form 8-K filed June 24, 2013, File No. 1-8489). |
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.39* |
|
2014 Performance Grant Plan under 2014 Long-Term Incentive Program approved January 16, 2014 (Exhibit 10.40, Form 10-K for the fiscal year ended December 31, 2013, File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.40* |
|
Form of Restricted Stock Award Agreement under the 2014 Long-term Incentive Program approved January 16, 2014 (Exhibit 10.41, Form 10-K for the fiscal year ended December 31,
2013, File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.41* |
|
Form of Special Performance Grant for Thomas F. Farrell II and Mark F. McGettrick approved January 16, 2014 (Exhibit 10.42, Form 10-K for the fiscal year ended December 31, 2013,
File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.42* |
|
2015 Performance Grant Plan under 2015 Long-Term Incentive Program approved January 22, 2015 (filed herewith). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.43* |
|
Form of Restricted Stock Award Agreement under the 2015 Long-term Incentive Program approved January 22, 2015 (filed herewith). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
Exhibit Number |
|
Description |
|
Dominion |
|
|
Virginia Power |
|
|
Dominion Gas |
|
|
|
|
|
|
10.44* |
|
Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith). |
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.45* |
|
Non-employee directors annual compensation for Dominion Resources, Inc. (filed herewith). |
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.46* |
|
Dominion Resources, Inc. 2014 Incentive Compensation Plan, effective May 7, 2014 (Exhibit 10.1, Form 8-K filed May 7, 2014, File No. 1-8489). |
|
|
X |
|
|
|
X |
|
|
|
X |
|
|
|
|
|
|
10.47 |
|
Registration Rights Agreement, dated as of October 22, 2013, by and among Dominion Gas Holdings, LLC and RBC Capital Markets, LLC, RBS Securities Inc. and Scotia Capital (USA) Inc.,
as the initial purchasers of the Notes (Exhibit 10.1, Form S-4 filed April 4, 2014, File No. 333-195066). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
10.48 |
|
Inter-Company Credit Agreement, dated October 17, 2013, between Dominion Resources, Inc. and Dominion Gas Holdings, LLC (Exhibit 10.2, Form S-4 filed April 4, 2014, File No. 333-195066). |
|
|
X |
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
10.49 |
|
DRS Services Agreement, dated September 12, 2013, between Dominion Gas Holdings, LLC and Dominion Resources Services, Inc. (Exhibit 10.3, Form S-4 filed April 4, 2014, File
No. 333-195066). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
10.50 |
|
DRS Services Agreement, dated January 1, 2003, between Dominion Transmission Inc. and Dominion Resources Services, Inc. (Exhibit 10.4, Form S-4 filed April 4, 2014, File No. 333-195066). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
10.51 |
|
DRS Services Agreement, dated January 1, 2003, between The East Ohio Company and Dominion Resources Services, Inc. (Exhibit 10.5, Form S-4 filed April 4, 2014, File No.
333-195066). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
10.52 |
|
DRS Services Agreement, dated January 1, 2003, between Dominion Iroquois, Inc. and Dominion Resources Services, Inc. (Exhibit 10.6, Form S-4 filed April 4, 2014, File No.
333-195066). |
|
|
|
|
|
|
|
|
|
|
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 for Dominion Gas Holdings, LLC (filed herewith). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
21 |
|
Subsidiaries of Dominion Resources, Inc. (filed herewith). |
|
|
X |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23 |
|
Consent of Deloitte & Touche LLP (filed herewith). |
|
|
X |
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
31.e |
|
Certification by Chief Executive Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
31.f |
|
Certification by Chief Financial Officer of Dominion Gas Holdings, LLC 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exhibit Number |
|
Description |
|
Dominion |
|
|
Virginia Power |
|
|
Dominion Gas |
|
|
|
|
|
|
32.c |
|
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the
Sarbanes-Oxley Act of 2002 (furnished herewith). |
|
|
|
|
|
|
|
|
|
|
X |
|
|
|
|
|
|
101 |
|
The following financial statements from Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC Annual Report on Form 10-K for the year ended
December 31, 2014, filed on February 27, 2015, 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 |
|
|
|
X |
|
* |
Indicates management contract or compensatory plan or arrangement |