UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20132014
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number | Exact name of registrants as specified in their charters | I.R.S. Employer Identification Number | ||
001-08489 | DOMINION RESOURCES, INC. | 54-1229715 | ||
VIRGINIA ELECTRIC AND POWER COMPANY | 54-0418825 | |||
000-55338 | DOMINION GAS HOLDINGS, LLC | 46-3639580 | ||
VIRGINIA (State or other jurisdiction of incorporation or organization) | ||||
120 TREDEGAR STREET RICHMOND, VIRGINIA (Address of principal executive offices) | 23219 (Zip Code) | |||
(804) 819-2000 (Registrants’ telephone number) |
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered | |
DOMINION RESOURCES, INC. | ||
Common Stock, no par value | ||
| New York Stock Exchange | |
2013 Series A 6.125% Corporate Units | New York Stock Exchange | |
2013 Series B 6% Corporate Units | New York Stock Exchange | |
| New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
NoneVIRGINIA 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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form10-K or any amendment to this Form 10-K.
Dominion Resources, Inc. x¨ Virginia Electric and Power Companyx 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.
Large accelerated filer x | Accelerated filer ¨ | Non-accelerated filer ¨ | Smaller reporting company ¨ |
Virginia Electric and Power Company
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).
Dominion Resources, Inc. Yes ¨ No x Virginia Electric and Power Company Yes ¨ No x
The aggregate market value of Dominion Resources, Inc. common stock held by non-affiliates of Dominion was approximately $32.1 billion based on the closing price of Dominion’s common stock as reported on the New York Stock Exchange as of the last day of Dominion’s most recently completed second fiscal quarter. Dominion is the sole holder of Virginia Electric and Power Company common stock. As of January 31, 2014, Dominion had 581,483,227 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding.
DOCUMENT INCORPORATED BY REFERENCE.
Portions of Dominion’s 2014 Proxy Statement are incorporated by reference in Part III.
This combined Form 10-K represents separate filings by Dominion Resources, Inc. and Virginia Electric and Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Virginia Power makes no representations as to the information relating to Dominion’s other operations.
Virginia Electric and Power Company
Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer x | Smaller reporting company ¨ |
Dominion Gas Holdings, LLC
Item Number | | Page Number | | |||
3 | ||||||
1. | 8 | |||||
1A. | 23 | |||||
1B. | 29 | |||||
2. | 29 | |||||
3. | 32 | |||||
4. | 32 | |||||
33 | ||||||
5. | 34 | |||||
6. | 35 | |||||
7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 36 | ||||
7A. | 55 | |||||
8. | 57 | |||||
9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 133 | ||||
9A. | 133 | |||||
9B. | 136 | |||||
10. | 136 | |||||
11. | 137 | |||||
12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 160 | ||||
13. | Certain Relationships and Related Transactions, and Director Independence | 160 | ||||
14. | 161 | |||||
15. | 162 |
Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer x | Smaller reporting company ¨ | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).
Dominion Resources, Inc. Yes ¨ No x Virginia Electric and Power Company Yes ¨ No x 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 Dominion’s common stock as reported on the New York Stock Exchange as of the last day of Dominion’s most recently completed second fiscal quarter. Dominion is the sole holder of Virginia Electric and Power Company common stock. As of January 31, 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 Dominion’s 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
Item Number |
| Page Number |
| |||
3 | ||||||
Part I | ||||||
1. | 8 | |||||
1A. | 24 | |||||
1B. | 31 | |||||
2. | 31 | |||||
3. | 35 | |||||
4. | 35 | |||||
36 | ||||||
Part II | ||||||
5. | 37 | |||||
6. | 38 | |||||
7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 39 | ||||
7A. | 54 | |||||
8. | 56 | |||||
9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 155 | ||||
9A. | 155 | |||||
9B. | 158 | |||||
Part III | ||||||
10. | 158 | |||||
11. | 158 | |||||
12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 158 | ||||
13. | Certain Relationships and Related Transactions, and Director Independence | 158 | ||||
14. | 158 | |||||
Part IV | ||||||
15. | 160 |
2 |
The following abbreviations or acronyms used in this Form 10-K are defined below:
Abbreviation or Acronym | Definition | |
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2013 Biennial Review Order | Order issued by the Virginia Commission in November 2013 concluding the 2011—2012 biennial review of Virginia Power’s base rates, terms and conditions | |
2013 Equity Units | Dominion’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013 | |
2014 Equity Units | Dominion’s 2014 Series A Equity Units issued in July 2014 | |
2015 Proxy Statement | Dominion | |
ABO | Accumulated benefit obligation | |
AES | Alternative Energy Solutions | |
AFUDC | Allowance for funds used during construction | |
AIP | Annual Incentive Plan | |
Altavista | Altavista power station | |
AMI | Advanced Metering Infrastructure | |
AMR | Automated meter reading program deployed by East Ohio | |
AOCI | Accumulated other comprehensive income (loss) | |
AROs | Asset retirement obligations | |
ARP | Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the CAA | |
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BACT | Best available control technology | |
bcf | Billion cubic feet | |
Bear Garden | A 590 MW combined cycle, natural gas-fired power station in Buckingham County, Virginia | |
Blue Racer | Blue Racer Midstream, LLC, a joint venture with Caiman | |
BOEM | Bureau of Ocean Energy Management | |
BP | BP Wind Energy North America Inc. | |
Brayton Point | Brayton Point power station | |
BREDL | Blue Ridge Environmental Defense League | |
Bremo | Bremo power station | |
BRP | Dominion Retirement Benefit Restoration Plan | |
Brunswick County | A 1,358 MW combined cycle, natural gas-fired power station under construction in Brunswick County, Virginia | |
CAA | Clean Air Act | |
Caiman | Caiman Energy II, LLC | |
CAIR | Clean Air Interstate Rule | |
CAO | Chief Accounting Officer | |
CAP | IRS Compliance Assurance Process | |
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CD&A | Compensation Discussion and Analysis | |
CEA | Commodity Exchange Act | |
CEO | Chief Executive Officer | |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act of 1980 | |
CFO | Chief Financial Officer | |
CFTC | Commodity Futures Trading Commission | |
CGN Committee | Compensation, Governance and Nominating Committee of Dominion’s Board of Directors | |
CGT | Carolina Gas Transmission Corporation | |
Chesapeake | Chesapeake power station | |
Clean Power Plan | 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 | Consolidated Natural Gas Company | |
CNO | Chief Nuclear Officer | |
CO2 | Carbon dioxide | |
COL | Combined Construction Permit and Operating License | |
Companies | Dominion, | |
CONSOL | CONSOL Energy, Inc. | |
COO | Chief Operating Officer | |
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Cooling degree days | Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day | |
Corporate Unit | A stock purchase contract and 1/20 interest in a RSN issued by Dominion | |
Cove Point | Dominion Cove Point LNG, LP |
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Abbreviation or Acronym | Definition | |
Cove Point Holdings | Cove Point GP Holding Company, LLC | |
CPCN | Certificate of Public Convenience and Necessity | |
Crayne interconnect | DTI’s interconnect with Texas Eastern Transmission, LP in Greene County, Pennsylvania | |
CSAPR | Cross State Air Pollution Rule | |
CWA | Clean Water Act | |
DEI | Dominion Energy, Inc. | |
D.C. | District of Columbia | |
Dodd-Frank Act | The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 | |
DOE | Department of Energy |
Dominion | The legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries (other than Virginia | |
Dominion Direct® | A dividend reinvestment and open enrollment direct stock purchase plan | |
Dominion Gas | 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 | 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 | Dominion Iroquois, Inc. | |
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DRS | Dominion Resources Services, Inc. | |
DSM | Demand-side management | |
Dth | Dekatherm | |
DTI | Dominion Transmission, Inc. | |
DVP | Dominion Virginia Power operating segment | |
E&P | Exploration & production | |
EA | Environmental assessment | |
East Ohio | The East Ohio Gas Company, doing business as Dominion East Ohio | |
EGWP | Employer Group Waiver Plan | |
Elwood | Elwood power station | |
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EPA | Environmental Protection Agency | |
EPACT | Energy Policy Act of 2005 | |
EPC | Engineering, procurement and construction | |
EPCRA | Emergency Planning and Community Right-to-Know Act | |
EPS | Earnings per share | |
ERISA | The Employee Retirement Income Security Act of 1974 | |
ERM | Enterprise Risk Management | |
ERO | Electric Reliability Organization | |
ESBWR | General Electric-Hitachi’s Economic Simplified Boiling Water Reactor | |
ESRP | Dominion Executive Supplemental Retirement Plan | |
Excess Tax Benefits | Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation | |
Fairless | Fairless power station | |
FASB | Financial Accounting Standards Board | |
FCM | Futures Commission Merchant | |
FERC | Federal Energy Regulatory Commission | |
Fitch | Fitch Ratings Ltd. | |
Fowler Ridge |
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Frozen Deferred Compensation Plan | Dominion Resources, Inc. Executives’ Deferred Compensation Plan | |
Frozen DSOP | Dominion Resources, Inc. Security Option Plan | |
FTRs | Financial transmission rights | |
GAAP | U.S. generally accepted accounting principles | |
Gal | Gallon | |
GHG | Greenhouse gas | |
Green Mountain | Green Mountain Power Corporation | |
| A natural gas processing and fractionation facility located near Pine Grove, West Virginia | |
HATFA of 2014 | Highway and Transportation Funding Act of 2014 | |
Heating degree days | Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day | |
Hope | Hope Gas, Inc., doing business as Dominion Hope | |
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Abbreviation or Acronym | Definition | |
Illinois Gas Contracts | A Dominion Retail, Inc. natural gas book of business consisting of residential and commercial customers in Illinois | |
INPO | Institute of Nuclear Power Operations | |
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Iroquois | Iroquois Gas Transmission System L.P. | |
IRS | Internal Revenue Service | |
ISO | Independent system operator | |
ISO-NE | ISO New England | |
JD Power | J.D. Power and Associates | |
Joint Committee | U.S. Congressional Joint Committee on Taxation | |
June 2006 hybrids | 2006 Series A Enhanced Junior Subordinated Notes due 2066 | |
June 2009 hybrids | 2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to extensions no later than 2079 | |
Juniper | Juniper Capital L.P. | |
Kewaunee | Kewaunee nuclear power station |
Kincaid | Kincaid power station | |
kV | Kilovolt | |
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LIBOR | London Interbank Offered Rate | |
LIFO | Last-in-first-out inventory method | |
Line TPL-2A | An approximately 11-mile, 30-inch gathering pipeline extending from Tuscarawas County, Ohio to Harrison County, Ohio | |
Line TL-388 | A 37-mile, 24-inch gathering pipeline extending from Texas Eastern, LP in Noble County, Ohio to its terminus at Dominion’s Gilmore Station in Tuscarawas County, Ohio | |
Line TL-404 | An approximately 26-mile, 24- and 30- inch gas gathering pipeline that extends from Wetzel County, West Virginia to Monroe County, Ohio | |
Liquefaction Project | A natural gas export/liquefaction facility currently under construction by Cove Point | |
LNG | Liquefied natural gas | |
LTIP | Long-term incentive program | |
MAP 21 Act | Moving Ahead for Progress in the 21st Century Act | |
Maryland Commission | Maryland Public Service Commission | |
Massachusetts Municipal | Massachusetts Municipal Wholesale Electric Company | |
MATS | Utility Mercury and Air Toxics Standard Rule | |
mcf | thousand cubic feet | |
MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
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Medicare Act | The Medicare Prescription Drug, Improvement and Modernization Act of 2003 | |
Medicare Part D | Prescription drug benefit introduced in the Medicare Act | |
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| Million gallons a day | |
Millstone | Millstone nuclear power station | |
MISO | Midwest Independent Transmission System Operators, Inc. | |
MLP | Master limited partnership, also known as publicly traded partnership | |
Moody’s | Moody’s Investors Service | |
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MW | Megawatt | |
MWh | Megawatt hour | |
NAAQS | National Ambient Air Quality Standards | |
Natrium | A natural gas and fractionation facility located in Natrium, West Virginia, owned by Blue Racer | |
NAV | Net asset value | |
NCEMC | North Carolina Electric Membership Corporation | |
NedPower | A wind-turbine facility joint venture with Shell in Grant County, West Virginia | |
NEIL | Nuclear Electric Insurance Limited | |
NEOs | Named executive officers | |
NERC | North American Electric Reliability Corporation | |
NGLs | Natural gas liquids | |
NO2 | Nitrogen dioxide | |
Non-Employee Directors Plan | Non-Employee Directors Compensation Plan | |
North Anna | North Anna nuclear power station | |
North Carolina Commission | North Carolina Utilities Commission | |
Northern System | Collection of approximately 131 miles of various diameter natural gas pipelines in Ohio | |
NOX | Nitrogen oxide | |
NPDES | National Pollutant Discharge Elimination System | |
NRC | Nuclear Regulatory Commission | |
NSPS | New Source Performance Standards | |
NYMEX | New York Mercantile Exchange | |
NYSE | New York Stock Exchange |
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Abbreviation or Acronym | Definition | |
October 2014 hybrids | 2014 Series A Enhanced Junior Subordinated Notes due 2054 | |
ODEC | Old Dominion Electric Cooperative | |
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Ohio Commission | Public Utilities Commission of Ohio | |
Order 1000 | Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development | |
OSHA | Occupational Safety and Health Administration | |
PBGC | Pension Benefit Guaranty Corporation | |
Peoples | The Peoples Natural Gas Company | |
Philadelphia Utility Index | Philadelphia Stock Exchange Utility Index | |
Pipeline Safety Act | The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 |
PIPP | Percentage of Income Payment Plan deployed by East Ohio | |
PIR | Pipeline Infrastructure Replacement program deployed by East Ohio | |
PJM | PJM Interconnection, L.L.C. | |
PM&P | Pearl Meyer & Partners | |
PNG Companies LLC | An indirect subsidiary of Steel River Infrastructure Fund North America | |
ppb | Parts-per-billion | |
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RCCs | Replacement Capital Covenants | |
RCRA | Resource Conservation and Recovery Act | |
Regulation Act | Legislation effective July 1, 2007, that amended the Virginia Electric Utility Restructuring Act and fuel factor statute, which legislation is also known as the Virginia Electric Utility Regulation Act, as amended in | |
REIT | Real estate investment trust | |
RGGI | Regional Greenhouse Gas Initiative | |
Rider B | A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Power’s coal-fired power stations to biomass | |
Rider BW | A rate adjustment clause associated with the recovery of costs related to Brunswick County | |
Rider R | A rate adjustment clause associated with the recovery of costs related to Bear Garden | |
Rider S | A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center | |
Rider T1 | 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 | A rate adjustment clause associated with the recovery of costs of new underground distribution facilities | |
Rider US-1 | A rate adjustment clause associated with the recovery of costs related to Remington Solar Facility | |
Rider W | A rate adjustment clause associated with the recovery of costs related to Warren County | |
Riders C1A and C2A | Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in DSM cases | |
ROE | Return on equity | |
ROIC | Return on invested capital | |
RPS | Renewable Portfolio Standard | |
RSN | Remarketable subordinated note | |
RTEP | Regional transmission expansion plan | |
RTO | Regional transmission organization | |
SAFSTOR | A method of nuclear decommissioning, as defined by the NRC, in which a nuclear facility is placed and maintained in a condition that allows the facility to be safely stored and subsequently decontaminated to levels that permit release for unrestricted use | |
SAIDI | System Average Interruption Duration Index, metric used to measure electric service reliability | |
Salem Harbor | Salem Harbor power station | |
SEC | Securities and Exchange Commission | |
SELC | Southern Environmental Law Center | |
September 2006 hybrids | 2006 Series B Enhanced Junior Subordinated Notes due 2066 | |
Shell | Shell WindEnergy, Inc. | |
SO2 | Sulfur dioxide | |
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Standard & Poor’s | Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc. | |
State Line | State Line power station | |
Surry | Surry nuclear power station | |
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TSR | Total shareholder return | |
U.S. | United States of America | |
UAO | Unilateral Administrative Order | |
UEX Rider | Uncollectible Expense Rider deployed by East Ohio | |
VDEQ | Virginia Department of Environmental Quality |
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Abbreviation or Acronym | Definition | |
VEBA | Voluntary Employees’ Beneficiary Association | |
VIE | Variable interest entity | |
Virginia City Hybrid Energy Center | A 600 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County, Virginia | |
Virginia Commission | Virginia State Corporation Commission | |
Virginia Power | The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power and its consolidated subsidiaries | |
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Warren County | A | |
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West Virginia Commission | Public Service Commission of West Virginia | |
Western System | Collection of approximately 212 miles of various diameter natural gas pipelines and three compressor stations in Ohio | |
Yorktown | Yorktown power station |
7 |
GENERAL
Dominion, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion’s strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. As of December 31, 2014, Dominion’s portfolio of assets includes approximately 23,60024,600 MW of generating capacity, 6,400 miles of electric transmission lines, 57,00057,100 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 presently serves nearly 6over 5 million utility and retail energy customers in 1510 states and operates one of the nation’s 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 five-yearsix-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, and to upgrade Dominion’s gas and electric transmission and distribution networks.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 2013,2014, Dominion announced the formation of Dominion Gas, a first tier wholly-owned subsidiary holding company for the majority of Dominion’s regulatedAtlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately 550-mile natural gas businesses. Specifically, Dominion transferred direct ownership of East Ohio, DTI and Dominion Iroquois, the latter of which holds a 24.72% general partnership interest in Iroquois,pipeline running from West Virginia through Virginia to Dominion Gas on September 30, 2013. Dominion Gas will be the primary financing entity for Dominion’s regulatedNorth Carolina, to increase natural gas businesses and expects to become an SEC registrantsupplies in 2014.
Also 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. Dominion is currently considering the contribution to the MLP of natural gas business assets other than those owned by Dominion Gas, including interests in Cove Point and Dominion’s share of the Blue Racer joint venture.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 2012 and 2013 and the ongoing exitsale of natural gas trading and certainthe electric retail energy marketing activities.business in March 2014. Dominion’s nonregulated
operations include merchant generation, energy marketing and price risk management activities and natural gas retail energy marketing operations. Dominion’s operations are conducted through various subsidiaries, including Virginia Power.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 Power’s common stock is owned by Dominion.
DominionGas, 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 Dominion’s 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 Dominion’s 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 FERC–regulated 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.
8 |
EMPLOYEES
As of December 31, 2013,2014, Dominion had approximately 14,50014,400 full-time employees, of which approximately 5,300 employees are subject to collective bargaining agreements. As of December 31, 2013,2014, Virginia Power had approximately 6,7006,800 full-time employees, of which approximately 3,100 employees are subject to collective bargaining agreements.
PRINCIPAL EXECUTIVE OFFICES
As of December 31, 2014, Dominion and Virginia Power’s principal executive officesGas had approximately 2,800 full-time employees, of which approximately 2,000 employees are located at 120 Tredegar Street, Richmond, Virginia 23219 and their telephone number is (804) 819-2000.subject to collective bargaining agreements.
WHERE YOU CAN FIND MORE INFORMATION ABOUT DOMINIONANDTHE VCIRGINIA POWEROMPANIES
Dominion and Virginia PowerThe 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 SEC’s website at http://www.sec.gov. You may also read and copy any document they file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.
Dominion and Virginia PowerThe 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 Dominion’s internet website, http://www.dom.com, as soon as reasonably practicable after filing or furnishing the material to the SEC. You may also request a copy of these filings, at no cost, by writing or telephoning Dominion at: Corporate Secretary, Dominion, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Information contained on Dominion’s website is not incorporated by reference in this report.
ACQUISITIONSAND DISPOSITIONS
Following are significant acquisitions and divestitures by Dominion and Virginia Powerthe Companies during the last five years. There
ACQUISITIONOF 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.
SALEOF ELECTRIC RETAIL ENERGY MARKETING BUSINESS
In March 2014, Dominion completed the sale of its electric retail energy marketing business. The proceeds were no significant acquisitions by either registrant during this period.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.
SALEOF PIPELINESAND 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 Dominion’s 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 Ohio’s consideration consisted of $61 million in cash proceeds and the extinguishment of affiliated long-term debt of $187 million and Dominion’s 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.
ASSIGNMENTSOF 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.
SALEOF BRAYTON POINT, KINCAIDAND EQUITY METHOD INVESTMENTIN 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 Point’s and Kincaid’s 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.
SALEOF 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.
SALEOF PEOPLES
In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million.
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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 Dominion’s 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 segment’s performance.
While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by Dominion and Virginia Powerthe Companies and their respective legal subsidiaries.
A description of the operations included in the Companies’ primary operating segments is as follows:
Primary Operating Segment | Description of Operations | Dominion | Virginia Power | 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 | X | (1) | X | ||||||||||
Gas distribution and storage | X | X | ||||||||||||
Gas | X | X | ||||||||||||
LNG | X | |||||||||||||
(1) |
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 Dominion’s and Virginia Power’sthe 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 Power’s regulated electric transmission and distributiondis-
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 five-yearsix-year investment plan, which includes spending approximately $4.8$8.9 billion from 20142015 through 20182020 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. Metrics used in measuring electric reliability and customer service were modified in 2013 to align with industry standards. Utilizing the new standard, Virginia Power continues to see improvement as SAIDI performance results, excluding major events, were 106113 minutes at the end of 2013,2014, down from the three-year average of 130120 minutes. Virginia Power’s overall customer satisfaction improved year over year when compared to peer utilitiesits 2013 score in the South Large segment of JD Power’s rankings.
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Based on the annual JD Power Customer Satisfaction results, DVP improved customer satisfaction and moved up three positions in the South Large segment ranking. Customer service options continue to be enhanced and expanded through the use of technology. Customers now have the ability to use the Internet for routine billing and payment transactions, connecting and disconnecting service, reporting outages and obtaining outage updates. Additionally, customers can follow progress of electric service restoration efforts following major outages by accessing Dominion’s Facebook, Twitter or internet website. In the future, safety, electric service reliability and customer service will remain key focus areas for electric distribution.
Revenue provided by Virginia Power’s electric transmission operations is based primarily on rates approved by FERC. The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings primarily results from changes in rates and the timing of property additions, retirements and depreciation.
Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to NERC by EPACT, Virginia Power’s electric transmission operations are committed to meeting NERC standards, modernizing its infrastructure and maintaining superior system reliability. Virginia Power’s electric transmission operations will continue to focus on safety, operational performance, NERC compliance and execution of PJM’s RTEP.
Dominion’s nonregulated retail energy marketing operations are now reflected in the Dominion Generation segment. See Note 25 to the Consolidated Financial Statements for additional information.
COMPETITION
DVP Operating Segment—Dominion and Virginia Power
There is no competition for electric distribution service within Virginia Power’s service territory in Virginia and North Carolina and no such competition is currently permitted. Additionally, there traditionally has been no competition for transmission service in the PJM region and Virginia Power’sHistorically, since its electric transmission facilities are integrated into PJM.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 Power’s service territory is now permitted pursuant to FERC Order 1000, subject to state and local siting and permittingpermit-
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ting approvals. This could result in additional competition to build transmission lines in Virginia Power’s service area in the future and could allow Dominion to seek opportunities to build facilities in other service territories.
REGULATION
DVP Operating Segment—Dominion and Virginia Power
Virginia Power’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia Commission and the North Carolina Commission.Commissions. Virginia Power’s wholesale electric transmission rates, tariffs and terms of service are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. SeeState Regulations and Federal Regulations inRegulation
and Note 13 to the Consolidated Financial Statements for additional information, including a discussion of the 2013 Biennial Review Order.
PROPERTIES
DVP Operating Segment—Dominion 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 Power’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.
As a part of PJM’s RTEP process, PJM authorized the following material reliability projects (including estimated cost):
Ÿ | Mt. Storm-to-Doubs line ($ |
Ÿ | Surry-to-Skiffes Creek-to-Whealton lines ($ |
Ÿ | Dooms-to-Lexington line ($112 million); |
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Ÿ | Landstown voltage regulation project ($ |
The following material reliability projects (including estimated cost) are awaiting PJM authorization:
Ÿ | Warrenton project (including Remington CT-to-Warrenton, Vint Hill-to-Wheeler, Wheeler-to-Loudoun and Vint Hill and Wheeler switching stations) ($109 million); and |
Ÿ | 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 Power’s electric distribution network includes approximately 57,00057,100 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.
SOURCESOF ENERGY SUPPLY
DVP Operating Segment—Dominion and Virginia Power
DVP’s supply of electricity to serve Virginia Power customers is produced or procured by Dominion Generation. SeeDominion Generation for additional information.
SEASONALITY
DVP Operating Segment—Dominion and Virginia Power
DVP’s earnings vary seasonally as a result of the impact of changes in temperature, the impact of storms and other 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 DVP’s electric-utility electric utility–related operations does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
Dominion Generation
The Dominion Generation Operating Segment of Virginia Power includes the generation operations of the Virginia Power regu-
latedregulated electric utility and its related energy supply operations. Virginia Power’s utility generation operations primarily serve the supply requirements for the DVP segment’s utility customers.The Dominion Generation Operating Segment of Dominionincludes Virginia Power’s generation facilities and its related energy supply operations as well as the generation operations of Dominion’s merchant fleet and energy marketing and price risk management activities for these assets and Dominion’s nonregulated natural gas retail energy marketing operations.
Dominion Generation’s five-yearsix-year electric utility investment plan includes spending approximately $3.3$9.7 billion from 20142015 through 20182020 to develop, finance and construct new generation capacity to meet growing electricity demand within its utility service territory. Significant projectsThe most significant project currently under construction include Warren County andis Brunswick County, which areis estimated to cost approximately $1.1 billion and $1.3$1.2 billion, excluding financing costs, respectively.costs. SeeProperties for additional information on thesethis and other utility projects.
In addition, Dominion’s merchant fleet has acquired and developed severalnumerous renewable generation projects, which began commercial operations during the fourth quarter of 2013.in 2013 and 2014. The total cost of the projects is approximately $200$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
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25 years. See Note 3 to the Consolidated Financial Statements for additional information regarding certain solar acquisitions.
Earnings for theDominion Generation Operating Segment of Virginia Powerprimarily 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. SeeElectric Regulationin Virginia underRegulation 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 Power’s utility and Dominion’s merchant generation assets, as well as from associated capacity and ancillary services. Variability in earnings provided by Dominion’s 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. However, earnings have been adversely impacted due to a sustained decline in commodity prices. This sustained decline in power prices in conjunction with Dominion’s regular strategic review of its portfolio of assets led to its decision to sell or retire certain merchant generation assets, which is discussed inProperties. 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.
Dominion’s retail energy marketing operations compete in nonregulated energy markets. TheIn March 2014, Dominion completed the sale of its electric retail business requires limited capital investment and currently has approximately 190 employees. Theenergy marketing business; however, it still participates in the retail customer base includes 2.1 million customer accounts and is diversified across three product lines: natural gas electricity and energy-related products and services.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. Dominion pursues customers in electricity markets where utilities have divested of generation assets and where customers are permitted and have opted to purchase from the market. Major growth drivers are net customer additions, new market penetration, product development and expanded sales channels and supply optimization. In January 2014, Dominion announced it will exit the electric retail energy marketing business, but will retain its natural gas and energy-related products and services retail energy marketing businesses.
COMPETITION
Dominion Generation Operating Segment—Dominion and Virginia Power
Virginia Power’s generation operations are not subject to significant competition as only a limited number of its Virginia jurisdictional electric utility customers have retail choice. SeeRegulation-State Regulations-Electric for more information. Currently, North Carolina does not offer retail choice to electric customers.
Dominion Generation Operating Segment—Dominion
Unlike Dominion Generation’s regulated generation fleet, its 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 Generation’s 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 fleet’s ability to profit from the sale of electricity and related products and services.
Dominion Generation’s nonrenewable merchant assets operate within functioning RTOs and primarily compete on the basis of price.
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Competitors include other generating assets bidding to operate within the RTOs. These RTOs have clearly identified market rules that ensure the competitive wholesale market is functioning properly. Dominion Generation’s 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.
Dominion’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas and electricity.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 Segment—Dominion and Virginia Power
Virginia Power’s utility generation fleet and Dominion’s merchant generation fleet are subject to regulation by FERC, the NRC, the EPA, the DOE, the Army Corps of Engineers and other federal, state and local authorities. Virginia Power’s utility generation fleet is also subject to regulation by the Virginia
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Commission and the North Carolina Commission. SeeStateRegulations andFederal Regulations inRegulation and Note 13 to the Consolidated Financial Statements for more information.
PROPERTIES
For a listing of Dominion’s and Virginia Power’s existing generation facilities, see Item 2. Properties.
Dominion Generation Operating Segment—Dominion and Virginia Power
The generation capacity of Virginia Power’s electric utility fleet totals approximately 19,60020,400 MW. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro, renewables, and power purchase agreements. Virginia Power’s 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:
Ÿ | In |
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Ÿ | 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. |
Ÿ | 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 Segment—Dominion
Dominion continually reviews its portfolio of assets to determine which assets fit strategically and support its objectives to improve ROIC and shareholder value. In connection with these efforts, in April 2011, Dominion announced the decision to pursue the sale of Kewaunee. In the fourth quarter of 2012, Dominion announced plans to close and decommission Kewaunee after the company was unable to find a buyer for the nuclear facility. Kewaunee ceased power production in the second quarter of 2013 and commenced decommissioning activities. In addition, during the second quarter of 2012, Dominion sold State Line, which ceased operations in March 2012, and in August 2012, Dominion completed the sale of Salem Harbor. In the third quarter of 2012, Dominion announced its intention to pursue the sale of its coal-fired merchant power stations, Brayton Point and Kincaid, and its 50% equity method investment in Elwood. Dominion completed the sale of these power stations in the third quarter of 2013.
Following these divestitures, theThe generation capacity of Dominion’s merchant fleet totals approximately 4,0004,200 MW. The generation mix is diversified and
includes nuclear, natural gas, and renewables. Merchant nonrenewable generation facilities are located in Connecticut, Indiana, Georgia, Pennsylvania and Rhode Island, and West Virginia, with a majority of that capacity concentrated in New England. Dominion’s 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:
Ÿ | 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. |
Ÿ | 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. |
SOURCESOF ENERGY SUPPLY
Dominion Generation Operating Segment—Dominion and Virginia Power
Dominion Generation uses a variety of fuels to power its electric generation and purchases power for utility system load requirements and to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are included as contractual obligations inFuture Cash Payments for Contractual Obligations and Planned Capital Expendituresin Item 7. MD&A.
Nuclear Fuel—Dominion Generation primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.
Fossil Fuel—Dominion Generation primarily utilizes coal and natural gas in its fossil fuel plants.
Dominion Generation’s coal supply is obtained through long-term contracts and short-term spot agreements from domestic suppliers.
Dominion Generation’s biomass supply is obtained through long-term contracts and short-term spot agreements from local suppliers.
Dominion Generation’s natural gas and oil supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, purchases from local producers in the Appalachian area 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.
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Biomass—Dominion Generation’s biomass supply is obtained through long-term contracts and short-term spot agreements from local suppliers.
Purchased Power—Dominion Generation purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for utility system load requirements.
Dominion Generation also occasionally purchases electricity from the PJM and ISO-NE spot markets to satisfy physical forward sale requirements as part of its merchant generation operations. Prior to the shutdown of Kewaunee and divestiture of its other Midwest generation facilities, Dominion Generation also occasionally purchased electricity from the MISO spot market.
Dominion Generation Operating Segment—Virginia Power
Presented below is a summary of Virginia Power’s actual system output by energy source:
Source | 2013 | 2012 | 2011 | 2014 | 2013 | 2012 | ||||||||||||||||||
Nuclear(1) | 33 | % | 33 | % | 28 | % | 33 | % | 33 | % | 33 | % | ||||||||||||
Purchased power, net | 21 | 27 | 33 | 19 | 21 | 27 | ||||||||||||||||||
Coal(2) | 29 | 22 | 26 | 30 | 29 | 22 | ||||||||||||||||||
Natural gas | 16 | 17 | 12 | 15 | 16 | 17 | ||||||||||||||||||
Other(3) | 1 | 1 | 1 | 3 | 1 | 1 | ||||||||||||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
(1) | Excludes ODEC’s 11.6% ownership interest in North Anna. |
(2) | Excludes ODEC’s 50.0% ownership interest in the Clover power station. The average cost of coal for |
(3) | Includes oil, hydro and biomass. |
Dominion Generation Operating Segment-Dominion
The supply of electricity to serve Dominion’s nonregulated retail energy marketing customers is procured through market wholesalers and RTO or ISO transactions. The supply of gas to serve Dominion’s retail energy marketing customers is procured through market wholesalers or by Dominion Energy. SeeDominion Energy for additional information.
SEASONALITY
Dominion Generation Operating Segment—Dominion 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. Generally, the demandSeeDVP—Seasonality above for electricity peaks during the summer and winter monthsadditional considerations that also apply to meet cooling and heating needs. An increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials at Virginia Power and because alternative heating sources are more readily available.Dominion Generation.
Dominion Generation Operating Segment—Dominion
The earnings of Dominion’s retail energy marketing operations also vary seasonally. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, while the demand for gas peaks during the winter months to meet heating needs.
NUCLEAR DECOMMISSIONING
Dominion Generation Operating Segment—Dominion and Virginia Power
Virginia Power has a total of four licensed, operating nuclear reactors at Surry and North Anna in Virginia.
Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers 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 requirement,requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial guaranteesinstruments recognized by the NRC.
The estimated cost to decommission Virginia Power’s four nuclear units is reflected in the table below and is primarily based upon site-specific studies completed in 2009.2014. 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 2067.2078.
Dominion Generation Operating Segment—Dominion
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 Dominion’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunee’s trust after decommissioning is completed are required to be refunded to Wisconsin ratepayers. Dominion believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Dominion will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial guaranteesinstruments recognized by the NRC. The estimated cost to decommission Dominion’s eight units is reflected in the table below and is primarily based upon site-specific studies completed for Surry, North Anna and Millstone in 20092014 and for Kewaunee in 2013. For the Millstone operating units, the current cost estimate assumes decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Millstone Unit 1 is in SAFSTOR decommissioning status and will continue to be monitored until full decommissioning activities begin for the remaining Millstone operating units. Dominion expects to start minor decommissioning activities at Millstone Unit 2 in 2035, with full decommissioning of Millstone Units 1, 2 and 3 following the permanent cessation of operations of Millstone Unit 3 during the period 2045 to 2069.
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The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion and Virginia Power are shown in the following table:
NRC license expiration year | Most recent cost estimate (2013 dollars)(1) | Funds in trusts at December 31, 2013 | 2013 contributions to trusts | 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 | $ | 497 | $ | 501 | $ | 0.6 | 2032 | $ | 576 | $ | 547 | $ | 0.6 | ||||||||||||||||||
Unit 2 | 2033 | 521 | 493 | 0.6 | 2033 | 596 | 539 | 0.6 | ||||||||||||||||||||||||
North Anna | ||||||||||||||||||||||||||||||||
Unit 1(2) | 2038 | 443 | 398 | 0.4 | 2038 | 493 | 435 | 0.4 | ||||||||||||||||||||||||
Unit 2(2) | 2040 | 456 | 373 | 0.3 | 2040 | 504 | 409 | 0.3 | ||||||||||||||||||||||||
Total (Virginia Power) | 1,917 | 1,765 | 1.9 | 2,169 | 1,930 | 1.9 | ||||||||||||||||||||||||||
Millstone | ||||||||||||||||||||||||||||||||
Unit 1(3) | n/a | 441 | 419 | — | n/a | 367 | 450 | — | ||||||||||||||||||||||||
Unit 2 | 2035 | 556 | 522 | — | 2035 | 540 | 569 | — | ||||||||||||||||||||||||
Unit 3(4) | 2045 | 596 | 512 | — | 2045 | 656 | 559 | — | ||||||||||||||||||||||||
Kewaunee | — | |||||||||||||||||||||||||||||||
Unit 1(5) | n/a | 651 | 685 | — | n/a | 520 | 688 | — | ||||||||||||||||||||||||
Total (Dominion) | $ | 4,161 | $ | 3,903 | $ | 1.9 | $ | 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 |
(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 Anna’s units. |
(3) | Unit 1 permanently ceased operations in 1998, before Dominion’s 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 Dominion’s ownership percentage. At December 31, |
(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.respectively, and Note 9 for information about nuclear decommissioning trust investments.
Dominion Energy
The Dominion Energy Operating Segment of Dominion Gasincludes the majority of Dominion’s regulated natural gas distribution companies, regulated gas transmission pipeline and storage operations, natural gas gathering and by-products extraction activities, LNG operations and its investment inoperations. DTI, the Blue Racer joint venture. Earnings from Dominion Energy’s producer services business are unregulated, and are subject to variability associated with changes in commodity prices. Producer services uses physical and financial arrangements to hedge this price risk. In the second quarter of 2013, Dominion commenced a restructuring of the 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 ongoing restructuring will result in the termination of natural gas trading and certain energy marketing activities. As a result, the earnings impact from these activities has been included in the Corporate and Other Segment of Dominion.
The gas transmission pipeline and storage business, serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in Dominion Energy’s gasthe transmission pipeline and storage business is its gas gathering and extractionprocessing activity, which sells extracted products at market rates. Dominion Energy’s LNG operations involveEast Ohio, 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 approval to export LNG from Cove Point and is awaiting other federal and state regulatory approvals to operate Cove Point as a bi-directional facility, able to import LNG, and vaporize it as naturalprimary gas and liquefy natural gas and export it as LNG. SeeFuture Issues and Other Matters in MD&A for more information.
The Blue Racer joint venture 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.
In September 2013, Dominion announced the formationdistribution business of Dominion, Gas, a first tier wholly-owned subsidiary holding company for the majority of Dominion’s regulated natural gas businesses. Also 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. SeeGeneral above for more information.
Dominion Energy’s five-year investment plan includes spending approximately $3.4 billion to $3.8 billion, exclusive of financing costs, from 2014 through 2018 for its Cove Point export project. Its five-year investment plan also includes spending approximately $2.1 billion to upgrade existing infrastructure or add new pipelines to meet growing energy needs within its service territory and maintain reliability.
Revenue provided by Dominion Energy’s regulated gas transmission and storage and LNG operations is based primarily on rates established by FERC. Additionally, Dominion Energy receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain gas transportation, gas storage, LNG storage and regasification services. Dominion’s gas distribution operations serveserves residential, commercial and industrial gas sales, transportation and gathering service customers. Revenue provided by itsDominion Iroquois holds a 24.72% general partnership interest in Iroquois, which provides service to local gas distribution operations is basedcompanies, electric utilities and electric power generators, as well as marketers and other end users, through interconnecting pipelines and exchanges primarily onin New York.
Earnings for theDominion Energy Operating Segment of Dominion Gas primarily result from rates established by FERC and the Ohio and West Virginia Commissions.Commission. The profitability of these businesses is dependent on Dominion’sDominion 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 extractionprocessing and fractionation operations largely results from the sale of commodities at market prices. For DTI’s extraction and 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 EnergyGas to commodity price risk for the value of the spread between the NGL products and natural gas. In addition, Dominion EnergyGas has volumetric risk since gas deliveries to DTI’s facilities are not under long-term contracts. However, the extraction
and fractionation operations within Dominion Energy’s Blue Racer joint venture are managed under long-term fee-based contracts, which minimizes commodity and volumetric risk. Variability in earnings largely results from changes in the quantities of natural gas and NGLs supplied to DTI’s facilities and commodity prices.
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 Ohio’s 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 Hope’s gas distribution operations in West Virginia, as well as Dominion’s investments in the Blue Racer joint venture, Atlantic Coast Pipeline and Dominion Midstream. SeeProperties and Investments below for additional information regarding the Atlantic Coast Pipeline investment. Dominion’s LNG operations involve the import and storage of LNG at Cove Point and the transportation of regasified LNG to the interstate pipeline grid and mid-Atlantic and Northeast markets. 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. SeeGeneral above for more information. Also see Note 3 to the Consolidated Financial Statements for a description of Dominion’s 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 Energy’s 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.
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Earnings for theDominion Energy Operating Segment of Dominionprimarily 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. Hope’s gas distribution operations in West Virginia serve residential, commercial and industrial gas sales, transportation and gathering service customers. Revenue provided by Hope’s 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 Energy’s Blue Racer joint venture are primarily managed under long-term fee-based contracts, which minimizes commodity risk.
COMPETITION
Dominion Energy’sEnergy Operating Segment—Dominion 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.
DTI’s extractionprocessing and fractionation operations face competition in obtaining natural gas supplies for its processing and related services. Numerous factors impact any given customer’s choice of processing services provider, including the location of the facilities, efficiency and reliability of operations, and the pricing arrangements offered.
Retail competition for gas supply exists to varying degrees in the two states in which Dominion Energy’s gas distribution subsidiaries operate. In Ohio, there has been no legislation enacted to require supplier choice for residential natural gas distribution consumers. However, DominionEast Ohio has offered an Energy Choice program to residential and commercial customers since October 2000. InEast 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 began to fully exitexited the merchant function for its nonresidential customers, which will require those customersare now required to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2013,2014, approximately 1 million of Dominion’sEast Ohio’s 1.2 million Ohio customers were participating in thisthe Energy Choice program.
Dominion Energy Operating Segment—Dominion
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 Point’s LNG operations are not subject to significant competition due to the long-term nature of their contracts.
REGULATION
Dominion Energy’sEnergy Operating Segment—Dominion and Dominion Gas
Dominion Gas’ natural gas transmission, pipeline, storage, processing and gathering operations are regulated primarily by FERC. East Ohio’s gas distribution operations, including the rates that it may charge to customers, are regulated by the Ohio Commission. SeeState Regulations andFederal Regulations inRegulation for more information.
Dominion Energy Operating Segment—Dominion
Dominion’s LNG operations are regulated primarily by FERC. Dominion Energy’sHope’s gas distribution service,operations, including the rates that it may charge customers, isare regulated by the Ohio and West Virginia Commissions.Commission. SeeState Regulations andFederal Regulations inRegulation for more information.
PROPERTIESAND INVESTMENTS
Dominion Energy’sEnergy Operating Segment—Dominion and Dominion Gas
East Ohio’s gas distribution network is located in the states of Ohio and West Virginia.Ohio. This network involves approximately 21,90018,800 miles of pipe, exclusive of service lines. The rights-
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of-wayrights-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 EnergyGas has approximately 10,9007,700 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion EnergyGas owns gas processing and fractionation facilities in West Virginia with a total processing capacity of 280,000270,000 mcf per day and fractionation capacity of 580,000 gallonsGals per day. Dominion EnergyGas also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with almostapproximately 2,000 storage wells and approximately 349,000399,000 acres of operated leaseholds.
The total designed capacity of the underground storage fields operated by Dominion EnergyGas is approximately 947 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy.Gas. The capacity of those fields owned by Dominion’sDominion Gas’ partners totals about 242 bcf. Dominion Energy also has about 15 bcf of above-ground storage capacity at Cove Point. Dominion Energy has 140 compressor stations with approximately 830,000 installed compressor horsepower.
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
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one of its Pennsylvania natural gas storage fields. See Note 10 to the Consolidated Financial Statements for further information.
Dominion is pursuing a liquefaction project at Cove Point, which would enable the facilityIn July 2013, East Ohio signed long-term precedent agreements with two customers to liquefy domestically-produced natural gas for export as LNG. In September 2013, the DOE conditionally authorized Dominion to export LNG from Cove Point to non-free trade agreement countries. Subject to environmental review by FERC and final FERC and Maryland Commission approval, the Cove Point facility is authorized to export at a rate of 770 million cubic feet of natural gasmove 320,000 Dths per day for a period of 20 years. The DOE previously authorized Dominion to export to countries with free trade agreements. Following receiptprocessed gas from the outlet of regulatory and other approvals, construction of liquefaction facilities could begin in 2014 with an in-service date in 2017. See Item 2. Properties for more information about the Cove Point facility.
In January 2011, Dominion announced the development of a naturalnew gas processing and fractionation facilityfacilities in Natrium, West Virginia. ThisOhio 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 Ohio’s 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 fully contracted, wasexpected 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 FERC’s 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 2013 and was contributed2015. Service under the 20-year contracts is expected to Blue Racercommence in the thirdfourth quarter of 2013 resulting in an increased equity method investment in Blue Racer2017.
During the second quarter of $473 million. In September 2013,2014, DTI executed a binding precedent agreement with a customer for the Natrium facility was shut down following a fire at the plantMonroe-to-Cornwell Project. The project is expected to cost approximately $70 million and returned to service in January 2014.
In May 2012, Dominion began construction of the G-150 pipeline project, which is designed to transport approximately 27,000 barrelsprovide 205,000 Dths per day of NGLsfirm 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 Natrium facilityproject 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 the ATEX line of Enterprise near Follansbee, West Virginia. Transportation services on the pipeline will be subjectTexas Gas Pipeline in Lebanon, Ohio. In September 2014, DTI filed an application to FERC regulation pursuant to the Interstate Commercerequest
Act. In November 2013, FERC granted Dominion’s petition for declaratory order and approved Dominion’s proposed (1) general rate structure, (2) rate and terms for committed shippers, and (3) rate design for uncommitted shippers. Dominion NGL Pipelines, LLC (now Blue Racer NGL Pipelines, LLC), the owner of the 58-mile pipeline and associated equipment, was contributed in January 2014 to Blue Racer prior to commencement of service, resulting in an increased equity method investment of $155 million.
In September 2013, DTI received 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 dekathermsDths 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. The project is anticipated to be in service in November 2014.
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 dekathermsDths per day of firm transportation service from Leidy, Pennsylvania to interconnects with Iroquois and Niagara Mohawk Power Corporation’s distribution system in the Albany, New York market. In June 2014, DTI expects to filefiled 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 dekathermsDths per day of firm transportation service from central West Virginia to Clarington, Ohio. In June 2014, DTI expects to filefiled 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 March 2013, FERC approved DTI’s $17November 2014, DTI placed into service its $112 million Sabinsville-to-Morrisville project, a pipeline to move additional Marcellus supplies from a TGP pipeline in northeast Pennsylvania to its line in upstate New York. DTI previously executed a binding precedent agreement with TGP in October 2010 to provide this firm transportation service up to 92,000 dekatherms per day for a 14-year term. Construction commenced in the second quarter of 2013 and the project was placed in service in November 2013.
In March 2013, DTI received FERC approval for its $67 million Tioga Area Expansion Project, which is designed to provide approximately 270,000 dekatherms per day of firm transportation service from supply interconnects in Tioga and Potter Counties in Pennsylvania to the Crayne interconnect and the Leidy interconnect with Transcontinental Gas Pipe Line Company in Clinton County, Pennsylvania. Two customers have contracted for the service under 15-year terms. Construction commenced in the second quarter of 2013 and the project was placed in service in November 2013.
In 2012, DTI completed the Gathering Enhancement Project, a $200 million expansion of its natural gas gathering, processing and liquids facilities in West Virginia. The project is designed to increase the efficiency and reduce high pressures in its gathering system, thus increasing the amount of natural gas local producers can move through DTI’s West Virginia system.
In September 2012, DTI completed the $575 million Appalachian Gateway Project. The project provides approximately 484,000 dekatherms per day of firm transportation services for new Appalachian gas supplies in West Virginia and southwestern Pennsylvania to an interconnection with Texas Eastern Transmission, LP at Oakford, Pennsylvania.
In November 2012, DTI completed the $97 million Northeast Expansion Project. The project provides approximately 200,000 dekatherms per day of firm transportation services for CONSOL’s Marcellus Shale natural gas production from various receipt points in central and southwestern Pennsylvania to a nexus of market pipelines and storage facilities in Leidy, Pennsylvania.
In November 2012, DTI completed the $46 million Ellisburg-to-Craigs project. The project’s capacity of approximately 150,000 dekatherms per day is leased by TGP to move Marcellus Shale natural gas supplies from TGP’s 300 Line pipeline system in northern Pennsylvania to its 200 Line pipeline system in upstate New York.
In December 2012, DTI received FERC authorization for the Allegheny Storage Project, which is expected to provideprovides approximately 7.5 bcf of incremental storage service and 125,000 dekathermsDths per day of associated year-round firm transportation service to three local distribution companies under 15-year contracts. Storage capacity for the project will be provided from storage pool enhancements at DTI and capacity leased from East Ohio. DTI intends to construct additional compression facilities and upgrade measurement and regulation in order to provide 115,000 dekatherms per day of transportation service. The remaining 10,000 dekatherms per day of transportation service will not require construction of additional facilities. The $112 million project is expected to be placed into service in the fourth quarter of 2014.
In 2008, East Ohio began PIR, aimed at replacing approximately 20%4,100 miles of its pipeline system.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 $2.7program will replace approximately 25% of the pipeline system and is anticipated to take place over a total of 25 years.
Dominion Energy Operating Segment—Dominion
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 Point—Dominion 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
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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 world’s 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 Dominion’s overall growth plan. In total, these renegotiations reduced Cove Point’s 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 Point’s interconnect with Transcontinental Gas Pipe Line in Fairfax County, Virginia to CPV Maryland, LLC’s 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 Point’s interconnect with Transcontinental Gas Pipe Line in Fairfax County, Virginia to Keys Energy Center, LLC’s facility in Prince George’s 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 Investments—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, which has a total expected cost of $4.5 billion 25-year programto $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 ongoing.subject to FERC, state and other federal approvals. See Note 139 to the Consolidated Financial Statements for further information about PIR.Dominion’s equity method investment in Atlantic Coast Pipeline.
In July 2013, East Ohio signed long-term precedent agreementsDecember 2012, Dominion formed Blue Racer with two customersCaiman to move 300,000 dekatherms per day of processedprovide midstream services to natural gas fromproducers operating in the outlet of new gas processing facilitiesUtica Shale region in Ohio to interconnectionsand portions of Pennsylvania. Blue Racer is an equal partnership between Dominion and Caiman, with multiple interstate pipelines. The Western Access Project would provide system enhancements to facilitate the movement of processedDominion contributing midstream assets and Caiman contributing private equity capital. Midstream services offered by Blue Racer include gathering, processing, fractionation, and natural gas over East Ohio’s systemliquids transportation and marketing. Blue Racer is expected to be completed by November 2014, and cost approximately $90 million.leverage Dominion’s 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 Dominion’s equity method investment in Blue Racer.
SOURCESOF ENERGY SUPPLY
Dominion Energy’sEnergy Operating Segment—Dominion and Dominion Gas
Dominion’s 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. Dominion’s and Dominion Gas’ large underground natural gas storage network and the location of itstheir pipeline systemsystems are a significant link between the country’s major interstate gas pipelines and large markets in the Northeast and mid-Atlantic regions. Dominion’s 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.
Dominion’s 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.
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SEASONALITY
Dominion Energy Operating Segment—Dominion and Dominion Gas
Dominion Energy’s natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March; however, implementation of the straight-fixed-variable rate design at East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipeline and storage business can also be weather sensitive. CommodityEarnings are also impacted by changes in commodity prices can be impacteddriven by seasonal weather changes, the effects of unusual weather events on operations and the economy. Dominion’s producer services business is affected by seasonal changes in the prices of commodities that it aggregates and transports.
Corporate and Other
Corporate and Other Segment—Virginia Power and Dominion Gas
Virginia Power’s and Dominion Gas’ Corporate and Other segmentsegments primarily includesinclude certain specific items attributable to itstheir operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Corporate and Other Segment—Dominion
Dominion’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) and the net impact of 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 Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
ENVIRONMENTAL STRATEGY
Dominion and Virginia PowerThe 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:
Ÿ | Compliance with applicable environmental laws, regulations and rules; |
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Ÿ | Renewable generation development; and |
Ÿ | Improvements in other energy |
This strategy incorporates Dominion’s and Virginia Power’sthe Companies’ efforts to voluntarily reduce GHG emissions, which are described below. SeeDominion Generation-Properties andDominion Energy-Propertiesfor 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
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strategic investments to advance Dominion’s degree of understanding of such technologies.
Environmental Compliance
Dominion and Virginia PowerThe Companies remain committed to compliance with all 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 Dominion’sthese and Virginia Power’sother of the Companies’ environmental compliance matters can be found in Item 1.Operating Segments andFuture Issues and Other Mattersin Item 7. MD&A and in NoteNotes 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 Power’s 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.
Virginia Power currently offers the following Currently, there are 22 total DSM programs active in Virginia:
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In August 2013, Virginia Power requested approval from the Virginia Commission to launch three new energy efficiency DSM programs as well as requested additional measures to enhance the
current Non-Residential Energy Audit Program. The three proposed DSM programs are the Non-Residential Lighting Systems & Controls Program, the Non-Residential Heating & Cooling Efficiency Program, and the Non-Residential Solar Window Film Program. This regulatory matter is still pending.
Virginia Power currently offers the following programs in North Carolina:
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Dominion 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 Virginia’s goals of 12% of base year electric energy sales from renewable power sources by 2022, and 15% by 2025, and North Carolina’s RPS of 12.5% by 2021. In May 2010, the Virginia Commission approved Virginia Power’s participation in the state’s RPS program. As a participant, Virginia Power is permitted to seek recovery, through rate adjustment clauses, of the costs of programs designed to meet RPS goals. Virginia Power plans to meet the respective RPS targets in Virginia and North Carolina by utilizing existing renewable facilities, as well as through additional renewable generation. In addition, Virginia Power intends to purchase renewable energy certificates, as permitted by each RPS program, to help meet any remaining annual requirement needs, as well as to fund renewable energy research and development initiatives at Virginia institutions of higher education. Virginia Power continues to explore opportunities to develop new renewable facilities within its service territory, the energy attributes of which would potentially qualify for inclusion in the RPS programs. In 2013, Virginia Power converted three coal-fired Virginia generating power stations to biomass, which increased its renewable generation by 153 MW.
Virginia Power is considering the development of a commercial offshore wind generation project through a federal land lease off the Virginia coast.
Dominion has invested in wind energy through two joint ventures. Dominion is a 50% owner with Shell of NedPower. Dominion’s share of this project produces 132 MW of renewable energy. Dominion is also a 50% owner with BP of the first phase of Fowler Ridge, which has a generating capacity of 300 MW. Dominion has a long-term agreement with Fowler Ridge to purchase 200 MW of energy, capacity and environmental attributes from this first phase.
In addition, during 2013 Dominion acquired and developed 42 MW of renewable energy projects, which includes solar generation facilities in Indiana, Georgia, and Connecticut.
Virginia Power is implementing the Solar Partnership Program. The Virginia Commission requires the project be constructed and operated at a cost to customers not to exceed $80 million. In 2013, Virginia Power announced that Old Dominion University and Canon Virginia’s Industrial Resource Technologies had been selected as participants in the program. During 2014, Virginia Power is planning to develop six to ten additional sites with a total capacity of up to 10 MW.
In March 2013, the Virginia Commission approved Rate Schedule SP, under which Virginia Power will purchase 100% of the energy output from up to a combined 3 MW of customer-owned solar distributed generation facilities, including all environmental attributes and associated renewable energy credits, at a fixed price of $0.15 per kWh for five years. This fixed price has two components: an avoided cost component (including line losses) determined using Virginia Power’s Rate Schedule 19 and recovered through Virginia Power’s fuel factor, and a voluntary environmental contribution component.
In December 2013, Dominion placed into service a fuel cell facility in Connecticut that produces approximately 15 MW of electricity using a reactive process that converts natural gas into electricity.
See Item 1. Business,Future IssuesOperating Segments and Other Mattersin Item 7. MD&A and Note 22 to the Consolidated Financial Statements2. Properties for additional information.information, including Dominion’s merchant solar properties.
Improvements in Other Energy Infrastructure
Virginia Power’s five-yearsix-year investment plan includes significant capital expenditures to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing
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electricity demand within its service territory, maintain reliability, and maintain reliability.to address environmental requirements. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service, and are intended to address both continued population growth and increases in electricity consumption by the typical consumer. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed or to be developed in the future. SeeProperties in Item 1.,Operating Segments, DVP for additional information.
Virginia Power is taking measures to ensure that its electrical infrastructure can support the expected demand from electric vehicles, which have significantly lower carbon intensity than conventional vehicles. Virginia Power has implemented a program designed to encourage customers to charge their electric vehicles at night when electricity demand is lower. The Virginia Commission has approved this program through November 2016.
Dominion and Dominion Gas, in connection with its five-year growththeir six-year investment plan, isare also pursuing the construction or upgrade of regulated infrastructure in itstheir natural gas business.businesses. SeeProperties and Investments in Item 1.,Operating Segments, Dominion Energy for additional information, including natural gas infrastructure projects.
Dominion and Virginia Power’sThe Companies’ Strategy for Voluntarily Reducing GHG Emissions
While Dominion and Virginia PowerThe Companies have not established a standalone GHG emissions reduction target or timetable, but they are actively engaged in voluntary reduction efforts, as well as working toward achieving RPS standards established by existing state regulations, as set forth above.efforts. The Companies have an integrated voluntary strategy for reducing overall GHG emission intensity with diversification as its cornerstone. The six principal components of the strategy include initiatives that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, oil, hydroaddress electric energy management, electric energy production, electric energy delivery and renewable energy, investing in renewable energy projects, implementing technologies to minimize natural gas releasesstorage, transmission and promoting energy conservation and efficiency efforts. Below are some of the Companies’ efforts that have or are expected to reduce the Companies’ overall carbon emissions or intensity:delivery, as follows:
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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. |
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Dominion also developed a comprehensive GHG inventory for calendar year 2012.2013. For Dominion Generation, Dominion’s and Virginia Power’s 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 tonnestons and 24.4 million metric tonnes,tons, respectively, in 2012, compared to 42.1 million metric tonnes and 25.9 million metric tonnes, respectively, in 2011.2012. The overall decrease in emissions from 2011the Dominion fleet from 2012 to 20122013 is largely due to Dominion’s 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 usage, less reliance on coal, and more renewable generation.oil. For the DVP operating segment’s electric transmission and distribution operations, direct CO2 equivalent emissions for 20122013 were 76,14346,446 metric tonnes,tons, representing a slight decrease of almost 50% from 2011 due to a decrease in gas leakage from insulating equipment.2012. For 2012,2013, DTI’s (including Cove Point) direct CO2 equivalent emissions were approximately 1.0 million metric tonnes,tons, and Hope’s and East Ohio’s direct CO2 equivalent emissions were approximately 0.91.0 million metric tonnes, showing a 58% decrease from 2011.tons, both similar to 2012. Dominion’s GHG inventory follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98 for calculating emissions.
Since 2000, the Companies have tracked the emissions of their electric generation fleet. Their electric generation fleet employs a mix of fuel and renewable energy sources. Comparing annual year 2000 to annual year 2012, Dominion’s and Virginia Power’s electric generating fleet (based on ownership percentage) reduced their average CO2 emissions rate per MWh of energy produced from electric generation by about 39% and 28%, respectively. During such time period, the capacity of Dominion’s and Virginia Power’s electric generation fleet has grown. The Companies do not yet have final 2013 emissions data.
Alternative Energy Initiatives
AES conducts research in the renewable and alternative energy technologies sector and supports strategic investments such as the Tredegar Solar Fund I, as discussed below, to advance Dominion’s degree of understanding of such technologies. AES also participates in federal and state policy development on alternative energy and identifies potential alternative energy resource and technology opportunities for Dominion’s business units. For example, in 2013, Virginia Power completed the initial engineering, design and permitting work for a wind turbine demonstration facility as part of the DOE’s Offshore Wind Advanced Technology Demonstration Program. The proposed 12 MW facility would generate power via two turbines located approximately 24 miles off the coast of Virginia, adjacent to the Virginia Wind Energy Area where Virginia Power is considering development of a commercial offshore wind generation project. DominionAES has also conducted a number of studies to evaluate potential transmission solutions for delivering offshore wind resources to its customers. One study determined the existing onshore transmission systemIn addition, AES has the capability to interconnect up to 4,500 MW of offshore wind energy and another evaluated options for high-voltage subsea transmission lines that would connect offshore wind generation facilities to the onshore transmission system.
In 2013, Dominion continued to enhance and refine itsdeveloped EDGE® grid-side efficiency product suite. EDGE® is, a modular and adaptive conservation voltage management solution enabling utilities to deploy incremental grid-side energy management, and that requires no behavioral changes or purchases by end customers. In February 2013, Dominion was awarded a patent relating to the EDGE® technology.
In 2012, Dominion formed Tredegar Solar Fund I, an entity managed by the AES department and focused on unregulated residential solar projects. This fund owns residential roof-top solar systems that are originated and administered by Clean Power Finance, Inc., a provider of solar finance products, in which Dominion has a small indirect equity investment. The systems are subject to power purchase agreements with third parties. In December 2013, Dominion’s Board of Directors approved an incremental investment in this fund, for a total authorized investment of $90 million. This fund currently has originations in process of approximately $32 million and assets in service of approximately $36 million.
REGULATION
Dominion and Virginia PowerThe 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 other federal, state and local authorities.the Department of Transportation.
State Regulations
ELECTRIC
Virginia Power’s electric utility retail service is subject to regulation by the Virginia Commission and the North Carolina Commission.
Virginia Power holds 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 Power’s transactions with affiliates, transfers of certain facilities and the issuance of certain securities.
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Electric Regulation in Virginia
Under the Regulation Act enacted in 2007, Virginia Power’s 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 Power’s base rates, terms and conditions for generation and distribution services on a biennial basis in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a combined two-year historic test period, and the determination of Virginia Power’s authorized ROE prospectively. 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 Power’s 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 Power’s base rates unchanged until at least December 1, 2022. The legislation limits the 2015 biennial review to solely a determination of Virginia Power’s 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 utility’s 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 continuescontains 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 utility’s authorized ROE based on the utility’s 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 utility’s earned ROE is either insufficient or excessive beginning with the biennial review for 2013-2014 to be filed in 2015. Additionally, if a utility is deemed to have over-earned, the customer refund share of excess earnings increases to 70% from the previous 60% level beginning with the biennial review for 2013-2014 to be filed in 2015.
If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, such decisions may adversely affect Virginia Power’s 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 Power’s retail electric base rates in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes and the rules and procedures of the North Carolina Commission. North Carolina base rates 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 Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, Virginia Power’s future earnings could be negatively impacted. Fuel rates are subject to revision under annual fuel cost adjustment proceedings.
Virginia Power’s transmission service rates in North Carolina are regulated by the North Carolina Commission as part of Virginia Power’s 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 Power’s annual non-fuel base revenues based on an authorized ROE of
10.2%, and a $14 million decrease in annual base fuel revenues for a combined total base revenue increase of $22 million. These rate changes became effective on January 1, 2013 and are beingwere 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 Commission’s December 2012 order from Virginia Power’s 2012 base rate case approving a 10.2% ROE for Virginia Power, established net regulatory assetsand remanding the case to the North Carolina Commission for additional findings of $17 million to be recovered over five to ten yearsfact in connection with these new rates.light of a 2013 opinion issued after the North Carolina Commission’s order. This case is pending.
GAS
Dominion’sEast Ohio’s natural gas distribution services, including the rates it may charge its customers, are regulated by the Ohio Commission. Hope’s 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
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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 Ohio’s 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
Dominion’s 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 hasand Dominion Gas have gas distribution operations have considered legislation regarding a competitive deregulation of natural gas sales at the retail level.
Ohio-Since—Since October 2000, East Ohio has offered the Energy Choice program, under which residential and commercial customers are encouraged to purchase gas directly from retail suppliers or through a community aggregation program. In October 2006, East Ohio restructured its commodity service by entering into gas purchase contracts with selected suppliers at a fixed price above the NYMEX month-end settlement and passing that gas cost to customers under the Standard Service Offer program.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 Ohio’s 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, 2013,2014, approximately 1.0 million of Dominion’sDominion Gas’ 1.2 million Ohio customers were participating in the Energy Choice program. Subject to the Ohio Commission’s approval, East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. East Ohio continues to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.
West Virginia—At this time, West Virginia has not enacted legislation to allowallowing customers to choose in the retail natural gas markets served by Hope. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customers a choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.
Rates
Dominion’s gas distribution subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate—Ohio and West Virginia. When necessary, Dominion’s gas distribution subsidiaries seek general base rate increases to recover increased operating costs 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
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of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohio’s customers pursuant to a 2008 rate case settlement. Base rates for Hope are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges.
In addition to general rate increases, Dominion’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective one-, three- or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.
The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure projects and certain other costs that vary widely over time; such costs are excluded from general base rates. See Note 13 to the Consolidated Financial Statements for additional information.
Federal Regulations
FEDERAL ENERGY REGULATORY COMMISSION
Electric
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominion’s merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion’s market-based sales tariffs authorized by FERC. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.
Dominion and Virginia Power are subject to FERC’s Standards of Conduct that govern conduct between transmission function employees of interstate gas and electricity transmission providers and the marketing function employees of their affiliates. The rule defines the scope of transmission and marketing-related functions that are covered by the standards and is designed to prevent transmission providers from giving their affiliates undue preferences.
Dominion and Virginia Power are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between Virginia Power and Dominion’s merchant plants without first receiving FERC authorization, (2) require the merchant plants and Virginia Power to conduct their wholesale power sales operations separately, and (3) prohibit Virginia Power from sharing market information with merchant plant operating personnel. The rules are designed to prohibit Virginia Power from giving the merchant plants a competitive advantage.
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EPACT included provisions to create an ERO. The ERO is required to promulgate mandatory reliability standards governing
the operation of the bulk power system in the U.S. FERC has certified NERC as the ERO and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of between $1 thousand and $1 million per day, and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
Dominion and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion and Virginia Power employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. Dominion and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cybersecurity programs as well as efforts to ensure appropriate facility ratings for Virginia Power’s transmission lines. In October 2010, NERC issued an industry alert identifying possible discrepancies between the design and actual field conditions of transmission facilities as a potential reliability issue. The alert recommends that entities review their current facilities rating methodology to verify that the methodology is based on actual field conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power is evaluatinghas evaluated its transmission facilities for any discrepancies between design and actual field conditions.conditions and has taken necessary corrective actions. In addition, NERC has requested the industry to increaseredefined critical assets which expanded the number of assets subject to NERC reliability standards, that are designated as critical assets, including cybersecurity assets. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
Gas
FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate natural gas company subsidiaries, including DTI, Iroquois, and certain services performed by Cove Point. FERC also has jurisdiction over siting,The design, construction and operation of the Cove Point LNG facility, including associated natural gas pipelines, the Liquefaction Project and the import and export facilities and interstate natural gas pipeline and storage facilities.of LNG are also regulated by the FERC.
Dominion’sDominion 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.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 Dominion’s 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.
See Note 13The 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 Consolidated Financial Statementshealth 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 additional information.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 Dominion’s and Virginia Power’sthe 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. Dominion and Virginia PowerThe 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, seeEnvironmental MattersinFuture Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 22 to the Consolidated Financial Statements.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
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federal, regional and state legislative and regulatory action in this area. Dominion and Virginia PowerThe 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. Dominion’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including climate change, and Dominion’s Board of Directors receives periodic updates on these matters. SeeEnvironmental Strategyabove, Environmental Matters inFuture Issues and Other Mattersin 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 Dominion’s and Virginia Powers’Power’s 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 Dominion’s and Virginia Power’s 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 the CompaniesDominion and Virginia Power are required by the NRC to be financially prepared. For information on decommissioning trusts, seeDominion 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, Dominion and Virginia Powerthe 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.
Dominion and Virginia Power’sThe 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.
Dominion’s and Virginia Power’sThe 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 winter storms,other natural disasters can be destructive, causingdisrupt 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 Dominion’s and Dominion Gas’ gas transmission and distribution operations and Virginia Power’s electric transmission, dis-
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tributiondistribution and generation operations are subject to regulatory review.Revenue provided by Virginia Power’s electric transmission, distribution and generation operations and Dominion’s 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 Power’s wholesale rates for electric transmission service are adjusted on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism, Virginia Power’s wholesale electric transmission cost of service is estimated and thereafter adjusted to reflect Virginia Power’s actual electric transmission costs incurred. These wholesale rates are subject to FERC review and prospective adjustment in the event that customers and/or interested state commissions file a complaint with FERC and are able to demonstrate that Virginia Power’s wholesale revenue requirement is no longer just and reasonable.
Similarly, various rates and charges assessed by Dominion’s and Dominion Gas’ gas transmission businesses are subject to review by FERC. Pursuant to FERC’s February 2014 approval of DTI’s uncontested settlement offer, DTI’s base rates for storage and transportation services are subject to a moratorium through the end of 2016. In addition, the rates of Dominion’s 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 Power’s base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission on a biennial basis in a
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proceeding that involves the determination of Virginia Power’s actual earned ROE during a combined two-year historic test period, and the determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances described in the Regulation Act, Virginia Power may be required to share a portion of its earnings with customers through a refund process, andprocess.
Legislation signed by the Virginia Commission may order aGovernor 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 Power’s existing base rate increase or reduction duringrates until at least December 1, 2022. During this period, Virginia Power bears the biennial review. As a result,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 potentially not fully recover its associated costs associated with these existing rate adjustment clauses.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 Power’s future earnings.
Virginia Power’s retail electric base rates for bundled generation, transmission, and distribution services to customers in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes, and the rules and procedures of the North Carolina Commission. If retail electric earnings exceed the returns established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery through base rates, on a timely basis, of costs incurred in providing service, Virginia Power’s future earnings could be negatively impacted.
Dominion and Virginia PowerThe 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.Dominion’s and Virginia Power’sThe 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 legis-
lationlegislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that the business is conducted in accordance with applicable laws. The Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if either Dominion or Virginia Powerany 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.
Dominion’s and Virginia Power’s generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. Dominion’s and Virginia Power’s generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs to make changes in market design. FERC also periodically reviews Dominion’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets or its interpretation of market rules, Dominion’s or Virginia Power’s authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of Dominion’s or Virginia Power’s generation business. In addition, there have been changes to the interpretation and application of FERC’s market manipulation rules. A failure to comply with these rules could lead to civil and criminal penalties.
DominionThe Companies’ infrastructure build and Virginia Power infrastructure buildexpansion plans often require regulatory approval before construction can commence. Dominion and Virginia PowerThe Companies may not complete plantfacility construction,, pipeline, conversion or expansionother 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 plantfacility construction, pipeline, electric transmission line, expansion, conversion and expansionother 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 plants requiresand 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 their counterparties or vendors, or other factors beyond theirthe Companies’ control. Even if plantfacility construction, pipeline, expansion, electric transmission line, conversion and expansionother infrastructure projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of Dominion and Virginia Powerthe 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, Dominion and Virginia Powerthe 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
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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 plantfacility construction, pipeline, electric transmission line, expansion, conversion and expansionother infrastructure projects.
Dominion’sThe development and Virginia Power’s current costsconstruction of compliance with environmental lawsseveral large-scale infrastructure projects simultaneously involves significant execution risk. The Companies are significant. The costs of compliance with future environmental laws,currently simultaneously developing or constructing several major projects, including lawsthe Liquefaction Project, the Atlantic Coast Pipeline project, the strategic undergrounding project, Brunswick County, and regulations designedmultiple DTI producer outlet projects, which together help contribute to address global climate change, air quality, coal combustion by-products, cooling water and other matters could make certainthe 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 Project—The 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 Dominion’s 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 Dominion’s financial performance and/or impair Dominion’s 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 Dominion’s 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 Dominion’s 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 Project—The 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. Dominion’s 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 Dominion’s 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 compliancecosts 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-
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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 Plan’s 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 Dominion’s and Virginia Power’s generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.
There are also potential impacts on Dominion’s 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 pollutionenvironmental control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and Dominion and Virginia Powerthe 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 Dominion or Virginia Power. The EPA isthe Companies. Risks relating to expected to issue additional regulations with respect to air quality under the CAA, including revised NAAQS and regulations governing theregulation of GHG emissions of GHGs from existing fossil fuel-fired electric generating units. Additionalunits 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. Compliance with GHG emission reduction requirements may require the retrofit or replacement of equipment or could otherwise increase the costThe Companies are also subject to operate and maintain our facilities. Risks relating to potential regulation of GHG emissions are discussed below. Dominion and Virginia Power also expect additionalrecently finalized federal water and waste regulations, including regulations concerning cooling water intake structures, and coal combustion by-product handling and disposal practices, that are expected to be applicable to at least someand the potential further regulation of its generating facilities.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 Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.
If additional federal and/or state requirements are imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements, such requirements may result in compliancecosts that alone or in combination could make some of Dominion’s or Virginia Power’s electric generation units or natural gas facilities uneconomical to maintain or operate.The EPA, environmental advocacy groups, other organizations and some state and other federal agencies are focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. Dominion and Virginia Power expect that additional EPA regulations, and possibly additional state legislation and/or regulations, may be issued resulting in the imposition of additional limitations on GHG emissions or requiring efficiency improvements from fossil fuel-fired electric generating units.
There are also potential impacts on Dominion’s natural gas businesses as federal or state GHG legislation or regulations may require GHG emission reductions from the natural gas sector and could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products. Several regions of the U.S. have moved forward with GHG emission regulations including regions where Dominion has operations. For example, 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.
Compliance with GHG emission reduction requirements may require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon capture and storage technology, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower emitting generation facilities. The cost of compliance with GHG emission legislation and/or regulation is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon capture and storage technology, and the selected compliance alternatives. The Companies cannot estimate the aggregate effect of such requirements on their results of operations, financial condition or their customers. However, such expenditures, if material, could make the Companies’ generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.
Dominion’sVirginia 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 Power’sand 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
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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
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them from accomplishing critical business functions. In addition, weather-related incidents, earthquakesBecause the Companies’ transmission facilities, pipelines and other natural disasters can disrupt operation of the Companies’ facilities. Because Virginia Power’s transmission facilities are interconnected with those of third parties, the operation of itstheir 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.
DominionDominion and Virginia Power have substantial ownership interests in and operate nuclear generating units; as a result, each may incursubstantial costs and liabilities.Dominion’s and Virginia Power’s nuclear facilities are subject to operational, environmental, health and financial risks such as the on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. Dominion and Virginia Power maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If
Dominion’s and Virginia Power’s decommissioning trust funds are insufficient, and they are not allowed to recover the additional costs incurred through insurance, or in the case of Virginia Power through regulatory mechanisms, their results of operations could be negatively impacted.
Dominion’s and Virginia Power’s nuclear facilities are also subject to complex government regulation which could negatively impact their results of operations. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose
fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending on its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require Dominion and Virginia Power to make substantial expenditures at their nuclear plants. In addition, although the Companies have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could materially and adversely affect their results of operations and/or financial condition. A major incident at a nuclear facility anywhere in the world, such as the nuclear events in Japan in 2011, could cause the NRC to adopt increased safety regulations or otherwise limit or restrict the operation or licensing of domestic nuclear units.
Dominion dependsand Dominion Gas depend on third parties to produce the natural gas it gathersthey gather and processes,process, andto providethe NGLsthat itseparates they separate into marketable products.products. A reduction in thesequantities quantities could reduce Dominion’s and Dominion Gas’revenues.Dominion obtains itsand Dominion Gas obtain their supply of natural gas and NGLs from numerous third-party producers. SuchMost producers are under no obligation to deliver a specific quantity of natural gas or NGLs to Dominion’s facilities, althoughand Dominion Gas’ facilities. A number of factors could reduce the producers that have contracted to supplyvolumes of natural gas and NGLs available to the NatriumDominion’s and Dominion Gas’ pipelines and other assets. Increased regulation of energy extraction activities or a decrease in natural gas processingprices 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 fractionation facility are subjectDominion Gas. Producers could shift their production activities to contractual minimum fee payments. Natrium is owned by Blue Racer.regions outside Dominion’s 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 Dominion’s and Dominion Gas’ systems and facilities for any reason, to systemsDominion and facilities in which Dominion has an interest, DominionGas could experience lower revenues to the extent it isthey are unable to replace the lost volumes on similar terms.
The development, construction and operation of the Cove Point liquefaction project would involve significant risks.As described in greater detail inFuture Issues and Other Matters, Dominion intends to invest significant financial resources in the liquefaction project, subject to receipt of required regulatory approvals. An inability to obtain financing or otherwise provide liquidity for the project on acceptable terms could negatively affect Dominion’s financial condition, cash flows, the project’s anticipated financial results and/or impair Dominion’s ability to execute the business plan for the project as scheduled.
The project remains subject to FERC and other federal and state approvals. The DOE has authorized Dominion to export LNG to non-free trade agreement countries, 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, which 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 which, although decided in Dominion’s favor, is the subject of an appeal. A delay in receipt of project approvals or an adverse ruling by an appellate court could adversely affect Dominion’s ability to execute its business plan.
There is limited recent industry experience in the U.S. regarding the construction or operation of large liquefaction projects. The construction of the facility 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 Dominion’s financial performance and/or impair Dominion’s ability to execute the business plan for the project as scheduled.
There are significant customer risks associated with the project. The terminal service agreements are subject to certain conditions precedent, including receipt of regulatory approvals. 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 Dominion’s favor, Dominion may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process.
Assuming current commodity price trends continue, if Dominion is unable to pursue the liquefaction project, Dominion may not be able to offset the prospective revenue reductions associated with the existing import contracts as described inFutureIssues and Other Matters, which could have a negative impact on its results of operations.
Dominion’s merchant power business is operatingoperates in a challenging market, which could adversely affect its results of operationsoperations and future growth. The success of Dominion’s 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
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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 Dominion’s 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.
Dominion’s and Virginia Power’sThe 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 Power’s 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. Dominion and Virginia PowerThe 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. Such defaultsDefaults 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 Dominion’s decommissioning trust funds and Dominion’s and Dominion Gas’ benefit plan assets or increase Dominion’s 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 Dominion’s nuclear plants and under itsDominion’s and Dominion Gas’ pension and other postretirement benefit plans. Dominion hasand 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 Dominion’s nuclear plants or require additional NRC-approved funding assurance.
A decline in the market value of the assets held in trusts to satisfy future obligations under Dominion’s 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 Dominion’s 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 life expectancymortality 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, Dominion’s 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.Dominion and Virginia PowerThe Companies use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity and financial market risks. In addition, Dominion purchases and sellsDominion Gas purchase and sell commodity-based contracts for hedging exposures from its business units. The Companies could recognize financial losses on these contracts,purposes.
including as a result of volatility in the market values of the underlying commodities, if a counterparty fails to perform under a contract or upon the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these transactions. In the absence of actively-quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the under-lying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
The use of derivatives to hedge future sales may limit the benefit Dominion would otherwise receive from increases in commodity prices. These hedge arrangements generally include collateral requirements that require Dominion to deposit funds or securities or post letters of credit with counterparties, financial intermediaries or clearinghouses to cover the fair value of covered contracts in excess of agreed upon credit limits. For instance, when commodity prices rise to levels substantially higher than the levels where it has hedged future sales, Dominion may be required to use a material portion of its available liquidity or obtain additional liquidity to cover these collateral requirements. In some circumstances, this could have a compounding effect on Dominion’s financial liquidity and results of operations. In addition, the availability or security of the collateral delivered by Dominion may be adversely affected by the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these types of transactions.
Derivatives designated under hedge accounting, to the extent not fully offset by the hedged transaction, can result in ineffectiveness losses. These losses primarily result from differences between the location and/or specifications of the derivative hedging instrument and the hedged item and could adversely affect Dominion’s results of operations.
Dominion’s and Virginia Power’s operations in regards to these transactions are subject to multiple market risks including market liquidity, price volatility, credit strength of the Companies’ counterparties and the financial condition of the financial intermediaries, exchanges and clearinghouses used for the types of transactions. These market risks are beyond the Companies’ control and could adversely affect their results of operations, liquidity and future growth.
The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The Dodd-Frank Act includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can choose to exempt their hedging transactions from these clearing and exchange trading
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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, Dominion’s or Virginia Power’sthe 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 Dominion’s and Virginia Power’sthe 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, Dominion and Virginia Powerthe 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 Dominion’sthe Companies’ credit ratings or the credit ratings of Virginia Power could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require Dominionthe 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 Dominion’s 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 Dominion’s and Virginia Power’sthe Companies’ businessplans.Dominion and Virginia PowerThe 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 expenditures,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 Dominion’s and Virginia Power’s 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 Dominion’s and Virginia Power’sthe Companies’ financial results.Dominion and Virginia PowerThe 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 Dominion’s and Virginia Power’sthe Companies’ operations. Dominion and Virginia PowerThe 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 Dominion’s and Virginia Power’sthe Companies’ operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on Dominion’s and Virginia Power’sthe 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. PartiesThere 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 the Companies’ operationsdistribution 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 nation’s 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.
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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,incidents; however, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect the Companies’ business, financial condition and results of operations.
Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on Dominion’s and Virginia Power’sthe Companies’ operations.Dominion’s and Virginia Power’sThe 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 somethese 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 theincreased 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.
As of December 31, 2013,2014, 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 shares itsand Dominion Gas share Dominion’s principal office in Richmond, Virginia, which is owned by Dominion. In addition, Virginia Power’s DVP and Generation segments share certain leased buildings and equipment. See Item 1. Business for additional information about each segment’s principal properties, which information is incorporated herein by reference.
Dominion’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described here and in Item 1. Business.
Substantially all of Virginia Power’s property is subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2013;2014; however, by leaving the indenture open, Virginia Power expects to retain the flexibility to issue mortgage bonds in the future. Certain of Dominion’s merchant generation facilities are also subject to liens. See Item 7. MD&A for more information.
DOMINIONENERGY
Dominion Energy’s 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 EnergyGas also owns NGL extractionprocessing plants capable of processing over 280,000270,000 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 gallonsGals per day of NGLs into marketable products, including propane, isobutane, butane, and natural gasoline. NGL operations have storage capacity of 1,226,500 gallonsGals of propane, 109,000 gallonsGals of isobutane, 442,000 gallonsGals of butane, 2,000,000 gallonsGals of natural gasoline, and 1,012,500 gallonsGals of mixed NGLs.
See Item 1. Business,General and Item 1. Dominion Energy,Properties and Investments for details regarding Dominion Energy’s pipeline and storage capacity.
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DVP
See Item 1. Business,General for details regarding DVP’s principal properties, which primarily include transmission and distribution lines.
PDOWEROMINION GENERATION
Dominion and Virginia Power generate electricity for sale on a wholesale and a retail level. The CompaniesDominion and Virginia Power supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2013,2014, Dominion Generation’s total utility and merchant generating capacity was approximately 23,60024,600 MW.
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The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2013:2014:
VIRGINIA POWER UTILITY GENERATION
Plant | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | ||||||||||||||
Coal | ||||||||||||||||||||
Mt. Storm | Mt. Storm, WV | 1,629 | ||||||||||||||||||
Chesterfield | Chester, VA | 1,267 | ||||||||||||||||||
Virginia City Hybrid Energy Center | Wise County, VA | 600 | ||||||||||||||||||
Chesapeake(1) | Chesapeake, VA | 595 | ||||||||||||||||||
Clover | Clover, VA | 437 | (3) | |||||||||||||||||
Yorktown(1) | Yorktown, VA | 323 | ||||||||||||||||||
Bremo(2) | Bremo Bluff, VA | 227 | ||||||||||||||||||
Mecklenburg | Clarksville, VA | 138 | ||||||||||||||||||
Total Coal | 5,216 | 27 | % | |||||||||||||||||
Gas | ||||||||||||||||||||
Warren County (CC) | Warren County, VA | 1,342 | ||||||||||||||||||
Ladysmith (CT) | Ladysmith, VA | 783 | Ladysmith, VA | 783 | ||||||||||||||||
Remington (CT) | Remington, VA | 608 | Remington, VA | 608 | ||||||||||||||||
Bear Garden (CC) | Buckingham County, VA | 590 | Buckingham County, VA | 590 | ||||||||||||||||
Possum Point (CC) | Dumfries, VA | 559 | Dumfries, VA | 559 | ||||||||||||||||
Chesterfield (CC) | Chester, VA | 397 | Chester, VA | 397 | ||||||||||||||||
Elizabeth River (CT) | Chesapeake, VA | 348 | Chesapeake, VA | 348 | ||||||||||||||||
Possum Point | Dumfries, VA | 316 | Dumfries, VA | 316 | ||||||||||||||||
Bellemeade (CC) | Richmond, VA | 267 | Richmond, VA | 267 | ||||||||||||||||
Bremo(1) | Bremo Bluff, VA | 227 | ||||||||||||||||||
Gordonsville Energy (CC) | Gordonsville, VA | 218 | Gordonsville, VA | 218 | ||||||||||||||||
Gravel Neck (CT) | Surry, VA | 170 | Surry, VA | 170 | ||||||||||||||||
Darbytown (CT) | Richmond, VA | 168 | Richmond, VA | 168 | ||||||||||||||||
Rosemary (CC) | Roanoke Rapids, NC | 165 | Roanoke Rapids, NC | 165 | ||||||||||||||||
Total Gas | 4,589 | 23 | 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 | Surry, VA | 1,676 | ||||||||||||||||
North Anna | Mineral, VA | 1,672 | (4) | Mineral, VA | 1,672 | (4) | ||||||||||||||
Total Nuclear | 3,348 | 17 | 3,348 | 16 | ||||||||||||||||
Oil | ||||||||||||||||||||
Yorktown | Yorktown, VA | 790 | Yorktown, VA | 790 | ||||||||||||||||
Possum Point | Dumfries, VA | 786 | Dumfries, VA | 786 | ||||||||||||||||
Gravel Neck (CT) | Surry, VA | 198 | Surry, VA | 198 | ||||||||||||||||
Darbytown (CT) | Richmond, VA | 168 | Richmond, VA | 168 | ||||||||||||||||
Possum Point (CT) | Dumfries, VA | 72 | Dumfries, VA | 72 | ||||||||||||||||
Chesapeake (CT) | Chesapeake, VA | 51 | Chesapeake, VA | 51 | ||||||||||||||||
Low Moor (CT) | Covington, VA | 48 | Covington, VA | 48 | ||||||||||||||||
Northern Neck (CT) | Lively, VA | 47 | Lively, VA | 47 | ||||||||||||||||
Total Oil | 2,160 | 11 | 2,160 | 11 | ||||||||||||||||
Hydro | ||||||||||||||||||||
Bath County | Warm Springs, VA | 1,802 | (5) | Warm Springs, VA | 1,802 | (5) | ||||||||||||||
Gaston | Roanoke Rapids, NC | 220 | Roanoke Rapids, NC | 220 | ||||||||||||||||
Roanoke Rapids | Roanoke Rapids, NC | 95 | Roanoke Rapids, NC | 95 | ||||||||||||||||
Other | Various | 3 | Various | 3 | ||||||||||||||||
Total Hydro | 2,120 | 11 | 2,120 | 10 | ||||||||||||||||
Biomass | ||||||||||||||||||||
Pittsylvania | Hurt, VA | 83 | Hurt, VA | 83 | ||||||||||||||||
Altavista | Altavista, VA | 51 | Altavista, VA | 51 | ||||||||||||||||
Polyester | Hopewell, VA | 51 | Hopewell, VA | 51 | ||||||||||||||||
Southhampton | Southampton, VA | 51 | Southampton, VA | 51 | ||||||||||||||||
Total Biomass | 236 | 1 | 236 | 1 | ||||||||||||||||
Various | ||||||||||||||||||||
Other | Various | 11 | — | |||||||||||||||||
Mt. Storm (CT) | Mt. Storm, WV | 11 | — | |||||||||||||||||
17,680 | 18,439 | |||||||||||||||||||
Power Purchase Agreements | 1,926 | 10 | 1,978 | 10 | ||||||||||||||||
Total Utility Generation | 19,606 | 100 | % | 20,417 | 100 | % |
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) |
(2) | Coal-fired units are expected to be retired |
(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. |
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DOMINION MERCHANT GENERATION
Plant | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | ||||||||||||||
Nuclear | ||||||||||||||||||||
Millstone | Waterford, CT | 2,001 | (2) | Waterford, CT | 2,001 | (1) | ||||||||||||||
Total Nuclear | 2,001 | 51 | % | 2,001 | 48 | % | ||||||||||||||
Gas | ||||||||||||||||||||
Fairless (CC) | Fairless Hills, PA | 1,196 | Fairless Hills, PA | 1,196 | ||||||||||||||||
Manchester (CC) | Providence, RI | 446 | Providence, RI | 461 | ||||||||||||||||
Total Gas | 1,642 | 41 | 1,657 | 39 | ||||||||||||||||
Wind | ||||||||||||||||||||
Fowler Ridge | Benton County, IN | 150 | (3) | Benton County, IN | 150 | (3) | ||||||||||||||
NedPower Mt. Storm | Grant County, WV | 132 | (4) | Grant County, WV | 132 | (4) | ||||||||||||||
Total Wind | 282 | 7 | 282 | 7 | ||||||||||||||||
Solar | ||||||||||||||||||||
Indy Solar (AC) | Indianapolis, IN | 29 | ||||||||||||||||||
Azalea Solar (AC) | Washington, GA | 8 | ||||||||||||||||||
Somers Solar (AC) | Somers, CT | 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 | 42 | 1 | 253 | 6 | ||||||||||||||||
Fuel Cell | ||||||||||||||||||||
Bridgeport Fuel Cell | Bridgeport, CT | 15 | Bridgeport, CT | 15 | ||||||||||||||||
Total Fuel Cell | 15 | — | 15 | — | ||||||||||||||||
Total Merchant Generation | 3,982 | 100 | % | 4,208 | 100 | % |
Note: (CC) denotes combined cycle and (AC) denotes alternating current.cycle.
(1) |
Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain. |
(2) | Subject to a lien securing the facility’s debt. |
(3) | Excludes 50% membership interest owned by BP. |
(4) | Excludes 50% membership interest owned by Shell. |
(5) | All solar facilities are alternating current. |
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From time to time, Dominion and Virginia Powerthe 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 Altavista’s 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 andFuture Issues and Other Mattersin 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 | 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 | |
Mark F. McGettrick | Executive Vice President and CFO of Dominion | |
| ||
David A. Christian | Executive Vice President and | |
Paul D. Koonce (55) | Executive Vice President and CEO—Energy 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 | President and CNO of Virginia Power from June 2009 to | |
Robert M. Blue | President of Virginia Power from January 2014 to date; Senior Vice President-Law, Public Policy and Environment of Dominion | |
| Vice President, Controller and CAO of Dominion | |
Diane Leopold | President of DTI, East Ohio and Dominion Cove Point, Inc. | |
Mark O. Webb | Vice President, General Counsel and Chief Risk Officer of Dominion, |
(1) | Any service listed for Virginia Power, Dominion Midstream GP, LLC, Dominion Gas, DTI, |
36 |
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Dominion
Dominion’s common stock is listed on the NYSE. At January 31, 2014,2015, there were approximately 135,000132,000 record holders of Dominion’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion Direct. Discussions of expected dividend payments and restrictions on Dominion’s payment of dividends required by this Item are contained inLiquidity and Capital Resources in Item 7. MD&A and Notes 17 and 20 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 20132014 and 2012.2013. 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 Dominion’s common stock repurchases during the fourth quarter of 2013:2014:
DOMINION PURCHASESOF EQUITY SECURITIES | DOMINION PURCHASESOF EQUITY SECURITIES | DOMINION PURCHASESOF 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) | 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) | ||||||||||||||||||||||||
10/1/2013-10/31/13 | 3,839 | $ | 62.51 | N/A | 19,629,059 shares/$ | 1.18 billion | ||||||||||||||||||||||||||
11/1/2013-11/30/13 | — | $ | — | N/A | 19,629,059 shares/$ | 1.18 billion | ||||||||||||||||||||||||||
12/1/2013-12/31/13 | — | $ | — | N/A | 19,629,059 shares/$ | 1.18 billion | ||||||||||||||||||||||||||
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 | 3,839 | $ | 62.51 | N/A | 19,629,059 shares/$ | 1.18 billion | 849 | $ | 70.33 | N/A | 19,629,059 shares/$ | 1.18 billion |
(1) |
(2) | Represents the weighted-average price paid per share. |
(3) | The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion Board of Directors was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion. |
Virginia Power
There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion. Restrictions on Virginia Power’s payment of dividends are discussed inDividend Restrictions in Item 7. MD&A and Note 20 to the Consolidated Financial Statements. Virginia Power paid quarterly cash dividends on its common stock as follows:
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year | |||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
2014 | $ | 148 | $ | 121 | $ | 196 | $ | 125 | $ | 590 | ||||||||||||||||||||||||||||||
2013 | $ | 148 | $ | 120 | $ | 195 | $ | 116 | $ | 579 | 148 | 120 | 195 | 116 | 579 | |||||||||||||||||||||||||
2012 | 149 | 120 | 110 | 180 | 559 |
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 Power’s Articles of Incorporation to delete references to the redeemed series of preferred stock.
The text of the foregoing amendment to Virginia Power’s Articles of Incorporation is included in the Amended and Restated Articles of Incorporation filed with Virginia Power’s 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 |
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Item 6. Selected Financial Data
DOMINION
Year Ended December 31, | 2013 | 2012 | 2011 | 2010 | 2009 | 2014 | 2013 | 2012 | 2011 | 2010 | ||||||||||||||||||||||||||||||
(millions, except per share amounts) | ||||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 13,120 | $ | 12,835 | $ | 13,765 | $ | 14,392 | $ | 14,032 | $ | 12,436 | $ | 13,120 | $ | 12,835 | $ | 13,765 | $ | 14,392 | ||||||||||||||||||||
Income from continuing operations, net of tax(1) | 1,789 | 1,427 | 1,466 | 3,056 | 1,301 | 1,310 | 1,789 | 1,427 | 1,466 | 3,056 | ||||||||||||||||||||||||||||||
Loss from discontinued operations, net of tax(1) | (92 | ) | (1,125 | ) | (58 | ) | (248 | ) | (14 | ) | — | (92 | ) | (1,125 | ) | (58 | ) | (248 | ) | |||||||||||||||||||||
Net income attributable to Dominion | 1,697 | 302 | 1,408 | 2,808 | 1,287 | 1,310 | 1,697 | 302 | 1,408 | 2,808 | ||||||||||||||||||||||||||||||
Income from continuing operations before loss from discontinued operations per common share-basic | 3.09 | 2.49 | 2.56 | 5.19 | 2.19 | 2.25 | 3.09 | 2.49 | 2.56 | 5.19 | ||||||||||||||||||||||||||||||
Net income attributable to Dominion per common share-basic | 2.93 | 0.53 | 2.46 | 4.77 | 2.17 | 2.25 | 2.93 | 0.53 | 2.46 | 4.77 | ||||||||||||||||||||||||||||||
Income from continuing operations before loss from discontinued operations per common share-diluted | 3.09 | 2.49 | 2.55 | 5.18 | 2.19 | 2.24 | 3.09 | 2.49 | 2.55 | 5.18 | ||||||||||||||||||||||||||||||
Net income attributable to Dominion per common share-diluted | 2.93 | 0.53 | 2.45 | 4.76 | 2.17 | 2.24 | 2.93 | 0.53 | 2.45 | 4.76 | ||||||||||||||||||||||||||||||
Dividends declared per common share | 2.25 | 2.11 | 1.97 | 1.83 | 1.75 | 2.40 | 2.25 | 2.11 | 1.97 | 1.83 | ||||||||||||||||||||||||||||||
Total assets | 50,096 | 46,838 | 45,614 | 42,817 | 42,554 | 54,327 | 50,096 | 46,838 | 45,614 | 42,817 | ||||||||||||||||||||||||||||||
Long-term debt | 19,330 | 16,851 | 17,394 | 15,758 | 15,481 | 21,805 | 19,330 | 16,851 | 17,394 | 15,758 |
(1) | Amounts attributable to Dominion’s 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 Dominion’s 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 Dominion’s 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 management’s decision to cease operations and begin decommissioning Kewaunee in 2013.
2011 results include a $139 million after-tax charge reflecting generation plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units and a $59 million after-tax charge reflecting restoration costs associated with damage caused by Hurricane Irene.
2010 results include a $1.4 billion after-tax net income benefit from the sale of substantially all of Dominion’s Appalachian E&P operations, net of charges related to the divestiture and a $202 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program. The loss from discontinued operations in 2010 includes $127 million of after-tax impairment charges at certain merchant generation facilities and a $140 million after-tax loss on the sale of Peoples.
2009 results include a $435 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings. Also in 2009, Dominion recorded a $281 million after-tax ceiling test impairment charge related to the carrying value of its Appalachian E&P properties.
VIRGINIA POWER
Year Ended December 31, | 2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
(millions) | ||||||||||||||||||||
Operating revenue | $ | 7,295 | $ | 7,226 | $ | 7,246 | $ | 7,219 | $ | 6,584 | ||||||||||
Net income | 1,138 | 1,050 | 822 | 852 | 356 | |||||||||||||||
Balance available for common stock | 1,121 | 1,034 | 805 | 835 | 339 | |||||||||||||||
Total assets | 26,961 | 24,811 | 23,544 | 22,262 | 20,118 | |||||||||||||||
Long-term debt | 7,974 | 6,251 | 6,246 | 6,702 | 6,213 |
2013 results include a $28 million after-tax charge resulting from impacts of the 2013 Biennial Review Order.
2012 results include a $53 million after-tax charge reflecting restoration costs associated with damage caused by severe storms.
2011 results include a $139 million after-tax charge reflecting generation plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired generating units and a $59 million after-tax charge reflecting restoration costs associated with damage caused by Hurricane Irene.
2010 results include a $123 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program.
2009 results include a $427 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
MD&A discusses Dominion’s and Virginia Power’s results of operations and general financial condition.condition and Virginia Power’s 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.
CONTENTSOF MD&A
MD&A consists of the following information:
Ÿ | Forward-Looking Statements |
Ÿ | Accounting |
Ÿ | Dominion |
Ÿ | Results of Operations |
Ÿ | Segment Results of Operations |
Ÿ | Virginia Power |
Ÿ | Results of Operations |
Ÿ | Dominion Gas |
Ÿ |
|
|
Ÿ | Liquidity and Capital |
Ÿ | Future Issues and Other |
FORWARD-LOOKING STATEMENTS
This report contains statements concerning Dominion’s and Virginia Power’sthe 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.
Dominion and Virginia PowerThe 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:
Ÿ | Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; |
Ÿ | Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities; |
Ÿ | Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations; |
Ÿ | Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances; |
Ÿ | Cost of environmental compliance, including those costs related to climate change; |
Ÿ | Changes in enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; |
Ÿ | Changes in regulator implementation of environmental standards and litigation exposure for remedial activities; |
Ÿ | Difficult to anticipate mitigation requirements associated with environmental approvals; |
Ÿ | Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; |
Ÿ | Unplanned outages at facilities in which |
Ÿ | Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s and Dominion Gas’ earnings and |
|
Ÿ | Counterparty credit and performance risk; |
Ÿ | Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; |
Ÿ | Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; |
Ÿ | Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by |
Ÿ | Fluctuations in interest rates; |
Ÿ | Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; |
Ÿ | Changes in financial or regulatory accounting principles or policies imposed by governing bodies; |
Ÿ | Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; |
Ÿ | Risks of operating businesses in regulated industries that are subject to changing regulatory structures; |
Ÿ | Impacts of acquisitions, divestitures, transfers of assets to joint ventures or |
Ÿ | Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; |
Ÿ | The timing and execution of |
Ÿ | Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models; |
Ÿ | Political and economic conditions, including inflation and deflation; |
Ÿ | Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; |
Ÿ | 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; |
Ÿ | Additional competition in industries in which |
Ÿ | Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; |
39 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Ÿ | Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion; |
Ÿ | Changes in operating, maintenance and construction costs; |
Ÿ | Timing and receipt of regulatory approvals necessary for planned construction or expansion |
Ÿ | 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; |
Ÿ | Adverse outcomes in litigation matters or regulatory proceedings; and |
Ÿ | 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.
ACCOUNTING MATTERS
Critical Accounting Policies and Estimates
Dominion and Virginia Power havehas 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 theirits financial condition or results of operations under different conditions or using different assumptions. Dominion and Virginia Power havehas discussed the development, selection and disclosure of each of these policies with the Audit CommitteesCommittee of their Boards of Directors. Virginia Power’sits Board of Directors also serves as its Audit Committee.Directors.
ACCOUNTINGFOR REGULATED OPERATIONS
The accounting for Virginia Power’sDominion’s regulated electric and Dominion’s regulated gas operations differs from the accounting for nonregulated operations in that they areDominion is required to reflect the effect of rate regulation in theirits Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs are deferred as regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.
The Companies evaluateDominion evaluates whether or not recovery of theirits regulatory assets through future rates is probable and makemakes various assumptions in their analyses.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 and Virginia Power recognizerecognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists and the ARO can be reasonably estimated. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, the Companies estimateDominion estimates the fair value of theirits AROs using present value techniques, in which they makeit 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 the Companies reviseDominion revises any assumptions used to calculate the fair value of existing AROs, they adjustit 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, they adjustDominion adjusts the carrying amount of the
ARO liability with such changes recognized in income. The Companies accreteDominion accretes the ARO liability to reflect the passage of time.
In 2014, 2013 2012 and 2011,2012, Dominion recognized $81 million, $86 million $77 million and $84$77 million, respectively, of accretion, and expects to recognize $84$86 million in 2014. In 2013, 2012 and 2011, Virginia Power recognized $38 million, $34 million and $36 million, respectively, of accretion, and expects to recognize $39 million in 2014. Virginia Power2015. Dominion records accretion and depreciation associated with utility nuclear decommissioning AROs as an adjustment to itsthe regulatory liability forrelated to its nuclear decommissioning.decommissioning trust.
A significant portion of the Companies’Dominion’s AROs relates to the future decommissioning of Dominion’sits merchant and Virginia Power’s utility nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2013,2014, Dominion’s nuclear decommissioning AROs totaled $1.4 billion, representing approximately 86% of its total AROs. At December 31, 2013, Virginia Power’s nuclear decommissioning AROs totaled $616 million, representing approximately 89%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 the Companies’Dominion’s nuclear decommissioning obligations.
The Companies obtainDominion 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 theirits nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. In addition, the Companies’Dominion’s cost estimates include cost escalation rates that are applied to the base year costs. The Companies determineDominion 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.
40 |
In December 2013, Dominion and Virginia Power recorded a reduction of $129 million ($47 million of which was credited to income) and $52 million, respectively, in the nuclear decommissiong AROs for their units due to a reduction in estimated costs.
In September 2012, Dominion recorded an increase of $246 million in the nuclear decommissioning AROs for its units ($183 million of which was chargeddue to income). The ARO revision was primarily driven by management’s decision to cease operations and begin decommissioning Kewaunee in 2013. Virginia Power recorded an increase of $43 million in the nuclear decommissioning AROs for its units. The ARO revision was driven by an increasea 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.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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, 2013,2014, Dominion had $222 million and Virginia Power had $39$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 and Virginia Power evaluateevaluates quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. The Companies establishDominion 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, 2013,2014, Dominion had established $69$87 million of valuation allowances and Virginia Power had no valuation allowances.
ACCOUNTINGFOR DERIVATIVE CONTRACTSAND OTHER INSTRUMENTSAT FAIR VALUE
Dominion and Virginia Power useuses derivative contracts such as futures, swaps, forwards, options and FTRs to manage commodity, currency exchange and financial market risks of theirits business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies. The majority of investments held in Dominion’s and Virginia Power’s nuclear decommissioning and Dominion’s rabbi and benefit plan trust funds are also subject to fair value accounting. See Notes 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 evaluatingevaluat-
ing pricing information provided by brokers and other pricing services, the Companies considerDominion 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 the Companies believeDominion believes that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, the CompaniesDominion must estimate prices based on available historical and near-term
future price information and use of statistical methods, including regression analysis, that reflect theirits market assumptions.
The Companies maximizeDominion maximizes the use of observable inputs and minimizeminimizes the use of unobservable inputs when measuring fair value.
USEOF ESTIMATESIN GOODWILL IMPAIRMENT TESTING
As of December 31, 2013,2014, Dominion reported $3.1$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 2012 and 20112012 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 Dominion’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present. See Note 11 to the Consolidated Financial Statements for additional information.
USEOF ESTIMATESIN LONG-LIVED ASSET IMPAIRMENT TESTING
Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived
41 |
Management’s 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 Dominion’s assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.
The expected long-term rates of return on plan assets, discount rates, and healthcare cost trend rates 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:
Ÿ | Expected inflation and risk-free interest rate assumptions; |
Ÿ | Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes; |
Ÿ | Expected future risk premiums, asset volatilities and correlations; |
Ÿ | Forecasts of an independent investment advisor; |
Ÿ | Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; and |
Ÿ | Investment allocation of plan assets. The strategic target asset allocation for Dominion’s pension funds is 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments, such as private equity investments. |
Strategic investment policies are established for Dominion’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include those mentioned above such as employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/
liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns.
Dominion develops assumptions, which are then compared to the forecasts of 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 2012 and 2011.2012. 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 2012 and 2011.2012. 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 and 5.90% in 2011.2012. Dominion selected a discount rates ranging from 5.20% to 5.30%, and from 5.00% to 5.10%,rate of 4.40% for determining both its December 31, 20132014 projected pension and other postretirement benefit obligations, respectively.obligations.
Dominion establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected, and demographics of plan participants. Dominion’s healthcare cost trend rate assumption as of December 31, 20132014 was 7.00% and is expected to gradually decrease to 4.60%5.00% by 20622018 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.
42 |
The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed, while holding all other assumptions constant:
Increase in Net Periodic Cost | Increase in Net Periodic Cost | |||||||||||||||||||||||
Change in Actuarial Assumption | Pension Benefits | Other Postretirement Benefits | Change in Actuarial Assumption | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
(millions, except percentages) | ||||||||||||||||||||||||
Discount rate | (0.25 | )% | $ | 14 | $ | 1 | (0.25 | )% | $ | 17 | $ | 1 | ||||||||||||
Long-term rate of return on plan assets | (0.25 | )% | 14 | 3 | (0.25 | )% | 15 | 3 | ||||||||||||||||
Healthcare cost trend rate | 1 | % | N/A | 16 | 1 | % | N/A | 26 |
In addition to the effects on cost, at December 31, 2013,2014, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $181$236 million and its accumulated postretirement benefit obligation by $37$47 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $140$186 million.
See Note 21 to the Consolidated Financial Statements for additional information.
REVENUE RECOGNITION—UNBILLED REVENUE
Virginia Power recognizes and records revenues when energy is delivered to the customer. The determination of sales to individual customers is basedinformation on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, the amount of electric energy delivered to customers, but not yet billed, is estimated and recorded as
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
unbilled revenue. This estimate is reversed in the following month and actual revenue is recorded based on meter readings. Virginia Power’s customer receivables included $395 million and $348 million of accrued unbilled revenue at December 31, 2013 and 2012, respectively.
The calculation of unbilled revenues is complex and includes numerous estimates and assumptions including historical usage, applicable customer rates, weather factors and total daily electric generation supplied, adjusted for line losses. Changes in customer usage patterns and other factors, which are the basis for the estimates of unbilled revenues, could have a significant effect on the calculation and therefore on Virginia Power’s results of operations and financial condition.Dominion’s employee benefit plans.
DOMINION
RESULTSOF OPERATIONS
Presented below is a summary of Dominion’s consolidated results:
Year Ended December 31, | 2013 | $ Change | 2012 | $ Change | 2011 | 2014 | $ Change | 2013 | $ Change | 2012 | ||||||||||||||||||||||||||||||
(millions, except EPS) | ||||||||||||||||||||||||||||||||||||||||
Net Income attributable to Dominion | $ | 1,697 | $ | 1,395 | $ | 302 | $ | (1,106 | ) | $ | 1,408 | $ | 1,310 | $ | (387 | ) | $ | 1,697 | $ | 1,395 | $ | 302 | ||||||||||||||||||
Diluted EPS | 2.93 | 2.40 | 0.53 | (1.92 | ) | 2.45 | 2.24 | (0.69 | ) | 2.93 | 2.40 | 0.53 |
Overview
2014VS. 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 Dominion’s Liability Management Exercise, and the repositioning of Dominion’s 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.
2013VS. 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 management’s decision to cease operations and begin decommissioning Kewaunee in 2013.
2012VS. 2011
Net income attributable to Dominion decreased by 79%. Unfavorable drivers include impairment and other charges related to the discontinued operations of Brayton Point and Kincaid and management’s decision to cease operations and begin decommissioning Kewaunee in 2013. Favorable drivers include the absence of an impairment charge related to certain utility coal-fired power stations and the absence of restoration costs associated with damage caused by Hurricane Irene recorded in 2011.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion’s results of operations:
Year Ended December 31, | 2013 | $ Change | 2012 | $ Change | 2011 | 2014 | $ Change | 2013 | $ Change | 2012 | ||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
Operating Revenue | $ | 13,120 | $ | 285 | $ | 12,835 | $ | (930 | ) | $ | 13,765 | $ | 12,436 | $ | (684 | ) | $ | 13,120 | $ | 285 | $ | 12,835 | ||||||||||||||||||
Electric fuel and other energy-related purchases | 3,885 | 240 | 3,645 | (297 | ) | 3,942 | 3,400 | (485 | ) | 3,885 | 240 | 3,645 | ||||||||||||||||||||||||||||
Purchased electric capacity | 358 | (29 | ) | 387 | (67 | ) | 454 | 361 | 3 | 358 | (29 | ) | 387 | |||||||||||||||||||||||||||
Purchased gas | 1,331 | 154 | 1,177 | (587 | ) | 1,764 | 1,355 | 24 | 1,331 | 154 | 1,177 | |||||||||||||||||||||||||||||
Net Revenue | 7,546 | (80 | ) | 7,626 | 21 | 7,605 | 7,320 | (226 | ) | 7,546 | (80 | ) | 7,626 | |||||||||||||||||||||||||||
Other operations and maintenance | 2,459 | (632 | ) | 3,091 | (87 | ) | 3,178 | 2,765 | 306 | 2,459 | (632 | ) | 3,091 | |||||||||||||||||||||||||||
Depreciation, depletion and amortization | 1,208 | 81 | 1,127 | 109 | 1,018 | 1,292 | 84 | 1,208 | 81 | 1,127 | ||||||||||||||||||||||||||||||
Other taxes | 563 | 13 | 550 | 21 | 529 | 542 | (21 | ) | 563 | 13 | 550 | |||||||||||||||||||||||||||||
Other income | 265 | 42 | 223 | 45 | 178 | 250 | (15 | ) | 265 | 42 | 223 | |||||||||||||||||||||||||||||
Interest and related charges | 877 | 61 | 816 | 20 | 796 | 1,193 | 316 | 877 | 61 | 816 | ||||||||||||||||||||||||||||||
Income tax expense | 892 | 81 | 811 | 33 | 778 | 452 | (440 | ) | 892 | 81 | 811 | |||||||||||||||||||||||||||||
Loss from discontinued operations | (92 | ) | 1,033 | (1,125 | ) | (1,067 | ) | (58 | ) | — | 92 | (92 | ) | 1,033 | (1,125 | ) |
An analysis of Dominion’s results of operations follows:
2014VS. 2013
Net revenue decreased 3%, primarily reflecting:
Ÿ | A $263 million decrease from retail energy marketing operations, primarily due to the sale of the retail electric business in March 2014; and |
Ÿ | A $195 million decrease primarily related to the repositioning of Dominion’s 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:
Ÿ | A $171 million increase from electric utility operations, primarily reflecting: |
Ÿ | An increase from rate adjustment clauses at electric utility operations ($132 million); and |
Ÿ | An increase in sales from electric utility operations primarily due to an increase in heating degree days ($34 million); |
Ÿ | A $46 million increase in gas transportation and storage activities and other revenues, largely due to various expansion projects being placed into service; and |
Ÿ | 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:
Ÿ | $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; |
Ÿ | A $135 million increase in planned outage costs at certain merchant generation facilities and at certain non-nuclear utility facilities; and |
43 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Ÿ | 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:
Ÿ | A gain on the sale of Dominion’s electric retail energy marketing business in March 2014 ($100 million), net of a $31 million write-off of goodwill; |
Ÿ | 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; |
Ÿ | The absence of a $65 million charge primarily reflecting impairment charges recorded in 2013 for certain natural gas infrastructure assets; and |
Ÿ | 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 Dominion’s 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.
2013VS. 2012
Net Revenue decreased 1%, primarily reflecting:
Ÿ | 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; |
Ÿ | 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 |
Ÿ | 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:
Ÿ | A $161 million increase from electric utility operations, primarily reflecting: |
Ÿ | An increase in sales to retail customers, primarily due to an increase in heating degree days ($112 million); and |
Ÿ | An increase from rate adjustment clauses ($92 million); partially offset by |
Ÿ | A decrease in ancillary revenues received from PJM ($12 million) primarily due to a decrease in net operating reserve credits; and |
Ÿ | 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 |
Other operations and maintenance decreased 20%, primarily reflecting:
Ÿ | A $589 million decrease related to Kewaunee largely due to the absence of charges recorded in 2012 following management’s decision to cease operations and begin decommissioning in 2013; |
Ÿ | A $123 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates; |
Ÿ | 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; |
Ÿ | 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 |
Ÿ | Increased gains from the sales of assets to Blue Racer ($32 million). |
These decreases were partially offset by:
Ÿ | A $65 million increase primarily related to impairment charges for certain natural gas infrastructure assets; |
Ÿ | A $46 million increase resulting from impacts of the 2013 Biennial Review Order; |
Ÿ | A $35 million increase due to the absence of adjustments recorded in 2012 in connection with the 2012 North Carolina rate case; |
Ÿ | A $34 million increase in PJM operating reserves and reactive service charges; and |
Ÿ | A $26 million charge related to the expected shutdown of certain coal-fired generating units. |
Other Incomeincreased 19%, primarily due to higher realized gains (including investment income) on nuclear decommissioning trust funds ($40 million) and a gain on the sale of Dominion’s 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 primarily reflects the sale of Brayton Point and Kincaid in 2013.
2012VS. 2011
Net Revenue increased $21 million, primarily reflecting:
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These increases were partially offset by:
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Other operations and maintenance decreased 3%, primarily reflecting:
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These decreases were partially offset by:
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Depreciation, depletion and amortizationincreased 11%, primarily due to property additions.
Other Incomeincreased 25%, primarily due to higher realized gains (including investment income) on nuclear decommissioning trust funds.
Loss from discontinued operations primarily reflects losses associated with Brayton Point and Kincaid, which were sold in 2013.
Outlook
Dominion’s strategy is to continue focusing on its regulated businesses while maintaining upside potential in well-positioned nonregulated businesses. The goals of this strategy are to provide earnings per share growth, a growing dividend and 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 2014,2015, Dominion is expected to experience an increase in net income on a per share basis as compared to 2013.2014. Dominion’s anticipated 20142015 results reflect the following significant factors:
Ÿ | A return to normal weather in its electric utility operations; |
Ÿ | Growth in weather-normalized electric utility sales of approximately |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Ÿ | Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue; |
Ÿ | 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 Dominion’s Liability Management Exercise, charges related to the repositioning of Dominion’s 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; |
Ÿ | Construction and operation of growth projects in gas transmission and distribution; |
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Ÿ | An increase in depreciation, depletion, and amortization; |
Ÿ | Higher operating and maintenance expenses; |
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Ÿ | A |
However, if the proposed Virginia legislation for nuclear and offshore wind facilities is signed into law, Dominion would expect to experience a decreaseAdditionally, in net income on a per share basis for 2014 as compared to 2013. See Note 13 to the Consolidated Financial Statements for additional information.
On January 2, 2013, U.S. federal legislation was enacted that provides an extension of the 50% bonus depreciation allowance for qualifying capital expenditures incurred through 2013, as discussed in Note 5 to the Consolidated Financial Statements.2015, Dominion expects the bonus depreciation provisions to reduce income taxes otherwise payable, resultingfocus on meeting new and developing environmental requirements, including by making significant investments in cash savingsutility solar generation, particularly in 2014 of approximately $300 million.Virginia.
SEGMENT RESULTSOF OPERATIONS
Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. Presented below is a summary of contributions by Dominion’s operating segments to net income attributable to Dominion:
Year Ended December 31, | 2013 | 2012 | 2011 | |||||||||||||||||||||
Net Income attributable to Dominion | Diluted EPS | Net Income attributable | Diluted EPS | Net Income attributable | Diluted EPS | |||||||||||||||||||
(millions, except EPS) | ||||||||||||||||||||||||
DVP(1) | $ | 475 | $ | 0.82 | $ | 439 | $ | 0.77 | $ | 416 | $ | 0.72 | ||||||||||||
Dominion Generation(1) | 1,031 | 1.78 | 1,021 | 1.78 | 1,078 | 1.87 | ||||||||||||||||||
Dominion Energy | 643 | 1.11 | 551 | 0.96 | 521 | 0.91 | ||||||||||||||||||
Primary operating segments | 2,149 | 3.71 | 2,011 | 3.51 | 2,015 | 3.50 | ||||||||||||||||||
Corporate and Other | (452 | ) | (0.78 | ) | (1,709 | ) | (2.98 | ) | (607 | ) | (1.05 | ) | ||||||||||||
Consolidated | $ | 1,697 | $ | 2.93 | $ | 302 | $ | 0.53 | $ | 1,408 | $ | 2.45 |
Year Ended December 31, | 2014 | 2013 | 2012 | |||||||||||||||||||||
Net Income attribu- table to | Diluted EPS | Net Income attribu- table to | Diluted EPS | Net Income attribu- table to | 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 DVP’s operations:
Year Ended December 31, | 2013 | % Change | 2012 | % Change | 2011 | 2014 | % Change | 2013 | % Change | 2012 | ||||||||||||||||||||||||||||||
Electricity delivered | 82.4 | 2 | % | 80.8 | (2 | )% | 82.3 | 83.5 | 1 | % | 82.4 | 2 | % | 80.8 | ||||||||||||||||||||||||||
Degree days: | ||||||||||||||||||||||||||||||||||||||||
Cooling | 1,645 | (8 | ) | 1,787 | (6 | ) | 1,899 | 1,638 | — | 1,645 | (8 | ) | 1,787 | |||||||||||||||||||||||||||
Heating | 3,651 | 24 | 2,955 | (12 | ) | 3,354 | 3,793 | 4 | 3,651 | 24 | 2,955 | |||||||||||||||||||||||||||||
Average electric distribution customer accounts (thousands)(1) | 2,475 | 1 | 2,455 | 1 | 2,438 | 2,500 | 1 | 2,475 | 1 | 2,455 |
(1) |
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
2014VS. 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 |
2013VS. 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. |
2012VS. 2011
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Regulated electric sales: | ||||||||
Weather | $ | (34 | ) | $ | (0.06 | ) | ||
Other | 28 | 0.05 | ||||||
FERC transmission equity return | 19 | 0.04 | ||||||
Storm damage and service restoration(1) | 14 | 0.03 | ||||||
Other | (4 | ) | (0.01 | ) | ||||
Change in net income contribution | $ | 23 | $ | 0.05 |
Dominion Generation
Presented below are operating statistics related to Dominion Generation’s operations:
Year Ended December 31, | 2013 | % Change | 2012 | % Change | 2011 | 2014 | % Change | 2013 | % Change | 2012 | ||||||||||||||||||||||||||||||
Electricity supplied | ||||||||||||||||||||||||||||||||||||||||
Utility | 82.8 | 2 | % | 80.9 | (2 | )% | 82.3 | 83.9 | 1 | % | 82.8 | 2 | % | 80.9 | ||||||||||||||||||||||||||
Merchant(1) | 26.6 | (5 | ) | 28.0 | 9 | 25.8 | 25.0 | (6 | ) | 26.6 | (5 | ) | 28.0 | |||||||||||||||||||||||||||
Degree days (electric | ||||||||||||||||||||||||||||||||||||||||
Cooling | 1,645 | (8 | ) | 1,787 | (6 | ) | 1,899 | 1,638 | — | 1,645 | (8 | ) | 1,787 | |||||||||||||||||||||||||||
Heating | 3,651 | 24 | 2,955 | (12 | ) | 3,354 | 3,793 | 4 | 3,651 | 24 | 2,955 | |||||||||||||||||||||||||||||
Average retail energy marketing customer accounts (thousands)(2) | 2,119 | — | 2,129 | (1 | ) | 2,152 | 1,283 | (3) | (39 | ) | 2,119 | — | 2,129 |
(1) | Excludes 7.6 million |
(2) |
(3) | Excludes 511 thousand average retail electric energy marketing customer accounts due to the sale of this business in March 2014. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
2014VS. 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. |
2013VS. 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 | $ | — |
2012VS. 2011
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Merchant generation margin | $ | (72 | ) | $ | (0.13 | ) | ||
Regulated electric sales: | ||||||||
Weather | (78 | ) | (0.13 | ) | ||||
Other | 46 | 0.08 | ||||||
Retail energy marketing operations | 35 | 0.06 | ||||||
Rate adjustment clause equity return | 17 | 0.03 | ||||||
PJM ancillary services | (27 | ) | (0.05 | ) | ||||
Net capacity expenses | 19 | 0.04 | ||||||
Outage costs | 10 | 0.02 | ||||||
Other | (7 | ) | (0.01 | ) | ||||
Change in net income contribution | $ | (57 | ) | $ | (0.09 | ) |
Dominion Energy
Presented below are selected operating statistics related to Dominion Energy’s operations.
Year Ended December 31, | 2013 | % Change | 2012 | % Change | 2011 | 2014 | % Change | 2013 | % Change | 2012 | ||||||||||||||||||||||||||||||
Gas distribution | ||||||||||||||||||||||||||||||||||||||||
Sales | 29 | 12 | % | 26 | (13 | )% | 30 | 32 | 10 | % | 29 | 12 | % | 26 | ||||||||||||||||||||||||||
Transportation | 281 | 8 | 259 | 2 | 253 | 353 | 26 | 281 | 8 | 259 | ||||||||||||||||||||||||||||||
Heating degree days | 5,875 | 18 | 4,986 | (11 | ) | 5,584 | 6,330 | 8 | 5,875 | 18 | 4,986 | |||||||||||||||||||||||||||||
Average gas distribution customer accounts (thousands)(1): | ||||||||||||||||||||||||||||||||||||||||
Sales | 246 | (2 | ) | 251 | (2 | ) | 256 | 244 | (1 | ) | 246 | (2 | ) | 251 | ||||||||||||||||||||||||||
Transportation | 1,049 | — | 1,044 | — | 1,040 | 1,052 | — | 1,049 | — | 1,044 |
(1) |
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:
2014VS. 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. |
2013VS. 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. |
2012VS. 2011
Increase (Decrease) | ||||||||
Amount | EPS | |||||||
(millions, except EPS) | ||||||||
Weather | $ | (5 | ) | $ | (0.01 | ) | ||
Producer services margin | (13 | ) | (0.02 | ) | ||||
Gas transmission margin(1) | 8 | 0.01 | ||||||
Gain from sale of assets to Blue Racer | 43 | 0.08 | ||||||
Other | (3 | ) | (0.01 | ) | ||||
Change in net income contribution | $ | 30 | $ | 0.05 |
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results:
Year Ended December 31, | 2013 | 2012 | 2011 | 2014 | 2013 | 2012 | ||||||||||||||||||
(millions, except EPS amounts) | ||||||||||||||||||||||||
Specific items attributable to operating segments | $ | (184 | ) | $ | (1,467 | ) | $ | (364 | ) | $ | (544 | ) | $ | (184 | ) | $ | (1,467 | ) | ||||||
Specific items attributable to Corporate and Other segment | — | (5 | ) | 29 | (149 | ) | — | (5 | ) | |||||||||||||||
Total specific items | (184 | ) | (1,472 | ) | (335 | ) | (693 | ) | (184 | ) | (1,472 | ) | ||||||||||||
Other corporate operations | (268 | ) | (237 | ) | (272 | ) | (277 | ) | (268 | ) | (237 | ) | ||||||||||||
Total net expense | $ | (452 | ) | $ | (1,709 | ) | $ | (607 | ) | $ | (970 | ) | $ | (452 | ) | $ | (1,709 | ) | ||||||
EPS impact | $ | (0.78 | ) | $ | (2.98 | ) | $ | (1.05 | ) | $ | (1.66 | ) | $ | (0.78 | ) | $ | (2.98 | ) |
TOTAL SPECIFIC ITEMS
Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing 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 Dominion’s Liability Management Exercise.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
VIRGINIA POWER
RESULTSOF OPERATIONS
Presented below is a summary of Virginia Power’s consolidated results:
Year Ended December 31, | 2013 | $ Change | 2012 | $ Change | 2011 | 2014 | $ Change | 2013 | $ Change | 2012 | ||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
Net Income | $ | 1,138 | $ | 88 | $ | 1,050 | $ | 228 | $ | 822 | $ | 858 | $ | (280 | ) | $ | 1,138 | $ | 88 | $ | 1,050 |
Overview
2014VS. 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.
2013VS. 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.
2012VS. 2011
Net income increased by 28%. Favorable drivers include the absence of an impairment charge related to certain coal-fired power stations recorded in 2011, the impact of rate adjustment clauses, and the absence of restoration costs associated with damage caused by Hurricane Irene recorded in 2011. Unfavorable drivers include the impact of less favorable weather and the restoration costs associated with damage caused by severe storms.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Power’s results of operations:
Year Ended December 31, | 2013 | $ Change | 2012 | $ Change | 2011 | 2014 | $ Change | 2013 | $ Change | 2012 | ||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
Operating Revenue | $ | 7,295 | $ | 69 | $ | 7,226 | $ | (20 | ) | $ | 7,246 | $ | 7,579 | $ | 284 | $ | 7,295 | $ | 69 | $ | 7,226 | |||||||||||||||||||
Electric fuel and other energy-related purchases | 2,304 | (64 | ) | 2,368 | (138 | ) | 2,506 | 2,406 | 102 | 2,304 | (64 | ) | 2,368 | |||||||||||||||||||||||||||
Purchased electric capacity | 358 | (28 | ) | 386 | (66 | ) | 452 | 360 | 2 | 358 | (28 | ) | 386 | |||||||||||||||||||||||||||
Net Revenue | 4,633 | 161 | 4,472 | 184 | 4,288 | 4,813 | 180 | 4,633 | 161 | 4,472 | ||||||||||||||||||||||||||||||
Other operations and maintenance | 1,451 | (15 | ) | 1,466 | (277 | ) | 1,743 | 1,916 | 465 | 1,451 | (15 | ) | 1,466 | |||||||||||||||||||||||||||
Depreciation and amortization | 853 | 71 | 782 | 64 | 718 | 915 | 62 | 853 | 71 | 782 | ||||||||||||||||||||||||||||||
Other taxes | 249 | 17 | 232 | 10 | 222 | 258 | 9 | 249 | 17 | 232 | ||||||||||||||||||||||||||||||
Other income | 86 | (10 | ) | 96 | 8 | 88 | 93 | 7 | 86 | (10 | ) | 96 | ||||||||||||||||||||||||||||
Interest and related charges | 369 | (16 | ) | 385 | 54 | 331 | 411 | 42 | 369 | (16 | ) | 385 | ||||||||||||||||||||||||||||
Income tax expense | 659 | 6 | 653 | 113 | 540 | 548 | (111 | ) | 659 | 6 | 653 |
An analysis of Virginia Power’s results of operations follows:
2014VS. 2013
Other operations and maintenance increased 32%, primarily reflecting:
Ÿ | $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 |
Ÿ | 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.
2013VS. 2012
Net Revenue increased 4%, primarily reflecting:
Ÿ | An increase in sales to retail customers, primarily due to an increase in heating degree days ($112 million); and |
Ÿ | An increase from rate adjustment clauses ($92 million); partially offset by |
Ÿ | 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:
Ÿ | A $123 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates; and |
Ÿ | 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:
Ÿ | A $46 million increase resulting from impacts of the 2013 Biennial Review Order; |
Ÿ | A $35 million increase due to the absence of adjustments recorded in 2012 in connection with the 2012 North Carolina rate case; |
Ÿ | A $34 million increase in PJM operating reserves and reactive service charges; |
Ÿ | A $26 million charge related to the expected shutdown of certain coal-fired generating units; and |
Ÿ | A $22 million increase in salaries, wages and benefits. |
2012DVSOMINION. 2011 GAS
Net Revenue increased 4%, primarily reflecting:
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Other operations and maintenance decreased 16%, primarily reflecting:
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Interest and related charges increased 16%, primarily due to the absence of the recognition of hedging gains into income in 2011, that had been deferred as regulatory liabilities, as a result of the 2011 Biennial Review Order.
Income tax expense increased 21%, primarily reflecting higher pre-tax income in 2012.
Outlook
Virginia Power expects to provide growth in net income in 2014. Virginia Power’s anticipated 2014 results reflect the following significant factors:
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However, if the proposed Virginia legislation for nuclear and offshore wind facilities is signed into law, Virginia Power would expect to experience a decrease in net income for 2014 as compared to 2013. See Note 13 to the Consolidated Financial Statements for additional information.
On January 2, 2013, U.S. federal legislation was enacted that provides an extension of the 50% bonus depreciation allowance for qualifying capital expenditures incurred through 2013, as discussed in Note 5 to the Consolidated Financial Statements. Virginia Power expects the bonus depreciation provisions to reduce income taxes otherwise payable, resulting in cash savings in 2014 of approximately $285 million.
SEGMENTRESULTSOF OPERATIONS
Presented below is a summary of contributions by Virginia Power’s operating segments to net income:Dominion Gas’ consolidated results:
Year Ended December 31, | 2013 | $ Change | 2012 | $ Change | 2011 | |||||||||||||||
(millions) | ||||||||||||||||||||
DVP | $ | 483 | $ | 35 | $ | 448 | $ | 22 | $ | 426 | ||||||||||
Dominion Generation | 702 | 49 | 653 | (11 | ) | 664 | ||||||||||||||
Primary operating segments | 1,185 | 84 | 1,101 | 11 | 1,090 | |||||||||||||||
Corporate and Other | (47 | ) | 4 | (51 | ) | 217 | (268 | ) | ||||||||||||
Consolidated | $ | 1,138 | $ | 88 | $ | 1,050 | $ | 228 | $ | 822 |
Year Ended December 31, | 2014 | $ Change | 2013 | $ Change | 2012 | |||||||||||||||
(millions) | ||||||||||||||||||||
Net Income | $ | 512 | $ | 51 | $ | 461 | $ | 2 | $ | 459 |
DVPOverview
Presented below are operating statistics2014VS. 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 to Virginia Power’s DVP segment:
Year Ended December 31, | 2013 | % Change | 2012 | % Change | 2011 | |||||||||||||||
Electricity delivered (million MWh) | 82.4 | 2 | % | 80.8 | (2 | )% | 82.3 | |||||||||||||
Degree days (electric service area): | ||||||||||||||||||||
Cooling | 1,645 | (8 | ) | 1,787 | (6 | ) | 1,899 | |||||||||||||
Heating | 3,651 | 24 | 2,955 | (12 | ) | 3,354 | ||||||||||||||
Average electric distribution customer accounts (thousands)(1) | 2,475 | 1 | 2,455 | 1 | 2,438 |
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:parties.
2013VS. 2012
Increase (Decrease) | ||||
(millions, except EPS) | ||||
Regulated electric sales: | ||||
Weather | $ | 24 | ||
Other | (2 | ) | ||
FERC transmission equity return | 30 | |||
Storm damage and service restoration(1) | (20 | ) | ||
Depreciation | (7 | ) | ||
Other operations and maintenance expense | 7 | |||
Other | 3 | |||
Change in net income contribution | $ | 35 |
2012VS. 2011
Increase (Decrease) | ||||
(millions) | ||||
Regulated electric sales: | ||||
Weather | $ | (34 | ) | |
Other | 28 | |||
FERC transmission equity return | 19 | |||
Storm damage and service restoration(1) | 14 | |||
Other | (5 | ) | ||
Change in net income contribution | $ | 22 |
Dominion Generation
Presented below are operating statisticsNet 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 Virginia Power’s Dominion Generation segment:certain natural gas infrastructure assets.
Year Ended December 31, | 2013 | % Change | 2012 | % Change | 2011 | |||||||||||||||
Electricity supplied (million MWh) | 82.8 | 2 | % | 80.9 | (2 | )% | 82.3 | |||||||||||||
Degree days (electric service area): | ||||||||||||||||||||
Cooling | 1,645 | (8 | ) | 1,787 | (6 | ) | 1,899 | |||||||||||||
Heating | 3,651 | 24 | 2,955 | (12 | ) | 3,354 |
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
2013VS. 2012
Increase (Decrease) | ||||
(millions) | ||||
Regulated electric sales: | ||||
Weather | $ | 44 | ||
Other | (4 | ) | ||
Rate adjustment clause equity return | 35 | |||
PJM ancillary services | (26 | ) | ||
Outage costs | 15 | |||
Other | (15 | ) | ||
Change in net income contribution | $ | 49 |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
2012VS. 2011
Increase (Decrease) | ||||
(millions) | ||||
Regulated electric sales: | ||||
Weather | $ | (78 | ) | |
Other | 46 | |||
Rate adjustment clause equity return | 17 | |||
PJM ancillary services | (27 | ) | ||
Net capacity expenses | 19 | |||
Other | 12 | |||
Change in net income contribution | $ | (11 | ) |
Corporate and OtherAnalysis of Consolidated Operations
Presented below are the Corporate and Other segment’s after-tax results:selected amounts related to Dominion Gas’ results of operations:
Year Ended December 31, | 2013 | 2012 | 2011 | |||||||||
(millions) | ||||||||||||
Specific items attributable to operating segments | $ | (47 | ) | $ | (51 | ) | $ | (268 | ) | |||
Other corporate operations | — | — | — | |||||||||
Total net expense | $ | (47 | ) | $ | (51 | ) | $ | (268 | ) |
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:
S2014PECIFICVS ITEMS ATTRIBUTABLETO OPERATING SEGMENTS. 2013
CorporateOther operations and Othermaintenance decreased 20%, primarily includes specific items attributable to Virginia Power’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 25 to the Consolidated Financial Statements for a discussion of these items.
SELECTED INFORMATION—ENERGY TRADING ACTIVITIESreflecting:
Dominion engages in energy trading, marketing and hedging activities to complement its businesses and facilitate its price risk management activities. As part of these operations, Dominion enters into contracts for purchases and sales of energy-related commodities, including electricity, natural gas and other energy-related products. Settlements of contracts may require physical delivery of the underlying commodity or cash settlement. Dominion also enters into contracts with the objective of benefiting from changes in prices. For example, after entering into a contract to purchase a commodity, Dominion typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, Dominion may receive a net cash margin (a realized gain), or may pay a net cash margin (a realized loss). Dominion continually monitors its contract positions, considering location and timing of delivery or settlement for each energy commodity in relation to market price activity.
A summary of the changes in the unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes follows:
Amount | ||||
(millions) | ||||
Net unrealized gain at December 31, 2012 | $ | 78 | ||
Contracts realized or otherwise settled during the period | (64 | ) | ||
Change in unrealized gains and losses | (100 | ) | ||
Net unrealized loss at December 31, 2013 | $ | (86 | ) |
The balance of net unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes at December 31, 2013, is summarized in the following table based on the approach used to determine fair value:
Maturity Based on Contract Settlement or Delivery Date(s) | ||||||||||||||||||||
Sources of Fair Value | 2014 | 2015—2016 | 2017—2018 | 2019 and thereafter | Total | |||||||||||||||
(millions) | ||||||||||||||||||||
Prices actively quoted—Level 1(1) | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Prices provided by other external sources—Level 2(2) | (41 | ) | (23 | ) | — | — | (64 | ) | ||||||||||||
Prices based on models and other valuation methods—Level 3(3) | (7 | ) | (10 | ) | (5 | ) | — | (22 | ) | |||||||||||
Total | $ | (48 | ) | $ | (33 | ) | $ | (5 | ) | $ | — | $ | (86 | ) |
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 |
An increase in gains associated with |
Ÿ | 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:
Ÿ | 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 |
Ÿ | An increase in gathering and storage services ($32 million); |
Ÿ | An increase in sales to gas distribution customers primarily due to an increase in heating degree days and other revenues ($18 million); and |
Ÿ | an increase in AMR and PIR program revenues ($16 million). |
These increases were partially offset by:
Ÿ | 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:
Ÿ | Decreased gains on the sales of pipeline systems ($72 million); and |
Ÿ | Impairment charges related to certain natural gas infrastructure assets ($55 million). |
These decreases were partially offset by:
Ÿ | 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 |
Ÿ | 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 chargesdecreased 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.
LIQUIDITYAND CAPITAL RESOURCES
Dominion and Virginia Power dependdepends 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, 2013,2014, Dominion had $1.6$1.7 billion of unused capacity under its credit facilities, including $407 million of unused capacity under joint credit facilities available to Virginia Power.facilities. See additional discussion below underCredit Facilities andShort-Term DebtDebt..
A summary of Dominion’s cash flows is presented below:
Year Ended December 31, | 2013 | 2012 | 2011 | 2014 | 2013 | 2012 | ||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Cash and cash equivalents at beginning of year | $ | 248 | $ | 102 | $ | 62 | $ | 316 | $ | 248 | $ | 102 | ||||||||||||
Cash flows provided by (used in): | ||||||||||||||||||||||||
Operating activities | 3,433 | 4,137 | 2,983 | 3,439 | 3,433 | 4,137 | ||||||||||||||||||
Investing activities | (3,458 | ) | (3,840 | ) | (3,321 | ) | (5,181 | ) | (3,458 | ) | (3,840 | ) | ||||||||||||
Financing activities | 93 | (151 | ) | 378 | 1,744 | 93 | (151 | ) | ||||||||||||||||
Net increase in cash and cash equivalents | 68 | 146 | 40 | 2 | 68 | 146 | ||||||||||||||||||
Cash and cash equivalents at end of year | $ | 316 | $ | 248 | $ | 102 | $ | 318 | $ | 316 | $ | 248 |
A summary of Virginia Power’s cash flows is presented below:
Year Ended December 31, | 2013 | 2012 | 2011 | |||||||||
(millions) | ||||||||||||
Cash and cash equivalents at beginning of year | $ | 28 | $ | 29 | $ | 5 | ||||||
Cash flows provided by (used in): | ||||||||||||
Operating activities | 2,329 | 2,706 | 2,024 | |||||||||
Investing activities | (2,601 | ) | (2,282 | ) | (1,947 | ) | ||||||
Financing activities | 260 | (425 | ) | (53 | ) | |||||||
Net increase (decrease) in cash and cash equivalents | (12 | ) | (1 | ) | 24 | |||||||
Cash and cash equivalents at end of year | $ | 16 | $ | 28 | $ | 29 |
Operating Cash Flows
In 2013, netNet cash provided by Dominion’s operating activities decreased by $704 million, primarily due to lower deferred fuel cost recoveries in its Virginia jurisdiction, higher net margin collateral requirements, and lower margins from retail energy marketing activities and merchant generation operations. The decrease was partially offset by lower rate refund payments and higher margins from regulated natural gas transmission operations.
In 2013, net cash provided by Virginia Power’s operating activities decreased by $377 million, primarily due to lower deferred fuel cost recoveries in its Virginia jurisdiction, higher income tax payments and net changes in other working capital items; partially offset by lower rate refund payments and the impact of favorable weather.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 2013,2015, Dominion’s Board of Directors affirmedupdated the dividend policy it set in December 2012 forto a target payout ratio of 65-70%70-75%, and established an annual dividend rate for 20142015 of $2.40$2.59 per share of common stock, a 6.7%an 8% increase over the 20132014 rate. In January 2014,2015, Dominion’s Board of Directors declared dividends payable March 20, 20142015 of 6064.75 cents per share of common stock. Declarations of dividends are subject to further Board of Directors approval. Virginia Power believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and provide dividends to Dominion.
The Companies’Dominion’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, and which are discussed in Item 1A. Risk Factors.
CREDIT RISK
Dominion’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion’s credit exposure as of December 31, 20132014 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.
Gross Credit Exposure | Credit Collateral | Net Credit Exposure | Gross Credit Exposure | Credit Collateral | Net Credit Exposure | |||||||||||||||||||
(millions) | ||||||||||||||||||||||||
Investment grade(1) | $ | 100 | $ | — | $ | 100 | $ | 189 | $ | 114 | $ | 75 | ||||||||||||
Non-investment grade(2) | 4 | — | 4 | 1 | — | 1 | ||||||||||||||||||
No external ratings: | ||||||||||||||||||||||||
Internally rated-investment grade(3) | 67 | — | 67 | 7 | — | 7 | ||||||||||||||||||
Internally rated-non-investment grade(4) | 92 | — | 92 | 31 | — | 31 | ||||||||||||||||||
Total | $ | 263 | $ | — | $ | 263 | $ | 228 | $ | 114 | $ | 114 |
(1) | Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately |
(2) | The five largest counterparty exposures, combined, for this category represented approximately 1% of the total net credit exposure. |
(3) | The five largest counterparty exposures, combined, for this category represented approximately |
(4) | The five largest counterparty exposures, combined, for this category represented approximately |
Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers and was not considered material at December 31, 2013.
Investing Cash Flows
In 2013,2014, net cash used in Dominion’s investing activities decreased by $382 million, primarily due to the proceeds from the sale of Brayton Point, Kincaid and equity method investment in Elwood and lower restricted cash reimbursements for the purpose of funding certain qualifying construction projects.
In 2013, net cash used in Virginia Power’s investing activities increased by $319 million,$1.7 billion, primarily due to higher capital expenditures.expenditures and lower proceeds from sales of assets and businesses.
Financing Cash Flows and Liquidity
Dominion and Virginia Power relyrelies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by theirits operations. As discussed inCredit Ratings, the Companies’Dominion’s ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances and, in the case of Virginia Power, approval by the Virginia Commission.issuances.
Each of the CompaniesDominion currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows the CompaniesDominion to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
In 2013,2014, net cash provided by Dominion’s financing activities was $93 million as compared to net cash used in financing activities of $151 million in 2012,increased by $1.7 billion, primarily reflecting higher net debt issuances, partially offset byproceeds from Dominion Midstream’s initial public offering and the absence of the acquisition of the Juniper noncontrollingnon-controlling interest recorded in Fairless2013 related to Fairless.
LIABILITY MANAGEMENT
During 2014, Dominion elected to redeem certain debt and higher common dividendpreferred 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 1517 to the Consolidated Financial Statements for more information.descriptions of these redemptions.
In 2013, net cash provided by Virginia Power’s financing activities was $260 million comparedFrom time to net cash usedtime, Dominion may reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity and repurchases in financing activities of $425 millionthe open market, in 2012, primarily reflecting higher net debt issuances.privately negotiated transactions, through tender offers or otherwise.
CREDIT FACILITIESAND SHORT-T-ERMTERM DEBT
Dominion and Virginia Power useuses short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.
In connection with commodity hedging activities, the Companies areDominion is required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, the CompaniesDominion may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, the CompaniesDominion 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 the CompaniesDominion can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives.
DOMINION
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Commercial
Dominion’s commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:
December 31, 2013 | Facility Limit | Outstanding Commercial Paper | Outstanding Letters of Credit | Facility Capacity Available | ||||||||||||||||||||||||||||
December 31, 2014 | Facility Limit | Outstanding Commercial Paper | Outstanding Letters of Credit | Facility Capacity Available | ||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||
Joint revolving credit facility(1) | $ | 3,000 | $ | 1,927 | $ | — | $ | 1,073 | $ | 4,000 | $ | 2,664 | $ | — | $ | 1,336 | ||||||||||||||||
Joint revolving credit facility(2) | 500 | — | 11 | 489 | 500 | 111 | 48 | 341 | ||||||||||||||||||||||||
Total | $ | 3,500 | $ | 1,927 | (3) | $ | 11 | $ | 1,562 | $ | 4,500 | $ | 2,775 | (3) | $ | 48 | $ | 1,677 |
(1) |
(2) |
(3) | The weighted-average interest |
VIRGINIA POWER
Virginia Power’s short-term financing is supported by two joint revolving credit facilities with Dominion. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion and Virginia Power and for other general corporate purposes.
Virginia Power’s share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion, were as follows:
December 31, 2013 | Facility Sub-limit | Outstanding Commercial Paper | Outstanding Letters of Credit | Facility Sub-limit Capacity Available | ||||||||||||
(millions) | ||||||||||||||||
Joint revolving credit facility(1) | $ | 1,000 | $ | 842 | $ | — | $ | 158 | ||||||||
Joint revolving credit facility(2) | 250 | — | 1 | 249 | ||||||||||||
Total | $ | 1,250 | $ | 842 | (3) | $ | 1 | $ | 407 |
In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility. Effective September 2013, the maturity date was extended from September 2017 to September 2018. As of December 31, 2013, this facility supports approximately $119 million of certain variable rate tax-exempt financings of Virginia Power.
SHORT-TERM NOTES
In November and December 2012,2013, Dominion issued $250$400 million and $150 million, respectively, of private placement short-term notes that matured and were repaid in November 20132014 and bore interest at a variable rate. The proceeds were used for general corporate purposes.
In November 2013,2014, Dominion issued $400 million of private placement short-term notes that mature in November 20142015 and bear interest at a variable rate. The proceeds were used for general corporate purposes.
LONG-TERM DEBT
During 2013,2014, Dominion and Virginia Power issued the following long-term debt:
Type | Principal | Rate | Maturity | Issuing Company | Principal | Rate | Maturity | |||||||||||||||||||||
(millions) | (millions) | |||||||||||||||||||||||||||
Remarketable subordinated notes | $ | 550 | 1.18 | % | 2019 | Dominion | ||||||||||||||||||||||
Remarketable subordinated notes | 550 | 1.07 | % | 2021 | Dominion | |||||||||||||||||||||||
Senior notes | 250 | 1.20 | % | 2018 | Virginia Power | $ | 400 | 1.25 | % | 2017 | ||||||||||||||||||
Senior notes | 500 | 2.75 | % | 2023 | Virginia Power | 700 | 2.50 | % | 2019 | |||||||||||||||||||
Senior notes | 500 | 4.00 | % | 2043 | Virginia Power | 450 | 2.50 | % | 2019 | |||||||||||||||||||
Senior notes | 585 | 4.65 | % | 2043 | Virginia Power | 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 | $ | 2,935 | $ | 6,085 |
In March 2013, Virginia Power redeemed the $50 million 2.5% IDA of the Town of Louisa, Virginia Solid Waste and Sewage Disposal Revenue Bonds, Series 2001A, that would have otherwise matured in March 2031. In FebruaryDuring 2014, Virginia Power provided notice to redeem the $10 million 2.5% and the $30 million 2.5% IDA of the Town of Louisa, Virginia Solid Waste and Sewage Disposal Revenue Bonds, Series 1997A and 2000A, that would otherwise mature in April 2022 and September 2030, respectively. The bonds will be redeemed on April 1, 2014 at the amount of principal then outstanding plus accrued interest. At December 31, 2013, the bonds were included in securities due within one year in Virginia Power’s Consolidated Balance Sheets.
In connection with the sale of Kincaid, in May 2013, Kincaid redeemed its 7.33% senior secured bonds due June 2020 with an outstanding principal amount of approximately $145 million. The bonds were redeemed for approximately $185 million, including a make-whole premium and accrued interest.
In connection with the sale of Brayton Point, Brayton Point provided notice of defeasance for three series of MDFA tax-exempt bonds, totaling approximately $257 million in outstanding principal amount, that would have otherwise matured in 2036 through 2042. In June 2013, Brayton Point delivered approximately $284 million to fund an irrevocable trust for the purpose of paying maturing principal and interest due through and including the earliest redemption dates of the bonds in 2016 and 2019. The bonds are no longer included in Dominion’s Consolidated Balance Sheet.
In June 2013, Brayton Point obtained bondholder consent and entered into a supplement to the Loan and Trust Agreement for approximately $75 million of variable rate MDFA Solid Waste Disposal Revenue Bonds, Series 2010B due 2041. The supplement and associated assignment agreement changed the sole obligor under the bonds from Brayton Point to Dominion; the bonds continue to be included in Dominion’s Consolidated Balance Sheet.
Dominion Gas issued $1.2 billion principal amount of unsecured senior notes in a private placement in October 2013 and will be the primary financing entity for Dominion’s regulated natural gas businesses. Dominion Gas used the proceeds from this offering to acquire intercompany long-term notes from Dominion and to repay a portion of its intercompany revolving credit agreement balances with Dominion.
During 2013, Dominion and Virginia Power repaid and repurchased $1.5$4 billion and $470 million, respectively, of long-term debt, and notes payable.including redemption premiums.
ISSUANCEOF COMMON STOCKAND OTHER EQUITY SECURITIES
Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2012, Dominion began issuing new common shares for these direct stock purchase plans. 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 2013,2014, Dominion issued approximately 5.43.8 million shares of common stock totaling $273 million through various programs.employee savings plans, direct stock purchase and dividend reinvestment plans, converted securities and other employee and director benefit plans. Dominion received cash proceeds of $279$205 million from the issuance of 4.72.9 million of such shares through Dominion Direct and employee savings plans.
In January 2012,December 2014, Dominion filed a newan SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an atat-the-market program. See Note 19 to the marketConsolidated Financial Statements for a description of the at-the-market program. Dominion entered into four separate Sales Agency Agreements to effect sales under the program. However, with the exception of issuing approximately $317 million in equity through employee savings plans, direct stock purchase and dividend reinvestment plans, converted securities and other employee and director benefit plans, Dominion did not issue common stock in 2013.
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.
In 2013, Virginia Power did not issue any shares of its common stock to Dominion.
REPURCHASEOF COMMON STOCK
Dominion did not repurchase any shares in 20132014 and does not plan to repurchase shares during 2014,2015, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, and purchases of common stock on the open market in 2014 for direct stock purchase plans, which dodoes not count against its stock repurchase authorization.
BORROWINGS FROM PARENT
Virginia Power has the ability to borrow funds from Dominion under both short-term and long-term borrowing arrangements. Virginia Power’s short-term demand note borrowings from Dominion were $97 million at December 31, 2013. There were no long-term borrowings from Dominion at December 31, 2013. At December 31, 2013, Virginia Power’s nonregulated subsidiaries had no borrowings under the Dominion money pool.
CREDIT RATINGSCredit 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
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
securities. Dominion and Virginia Power believebelieves that theirits current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion and Virginia Power may affect theirits ability to access these funding sources or cause an increase in the return required by investors. The Companies’Dominion’s credit ratings affect theirits liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which they areit is able to offer theirits debt securities.
Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for Dominion and Virginia Power are affected by each company’sits 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.
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In October 2013,November 2014, Standard & Poor’s affirmedchanged Dominion’s corporate credit rating of A- but lowered the rating for Dominion’s senior unsecured debt securitiesoutlook to BBB+negative from A- to reflect greater structural subordination at Dominion due to new debt at Dominion Gas.stable. Dominion cannot predict with certainty the potential impact the lowered ratingnegative outlook at Standard & Poor’s could have on its cost of borrowing.
Credit ratings as of February 24, 201423, 2015 follow:
Fitch | Moody’s | Standard
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Senior unsecured debt securities | BBB+ | Baa2 | BBB+ | |||||||||
Junior subordinated debt securities | BBB- | Baa3 | BBB | |||||||||
Enhanced junior subordinated notes | BBB- | Baa3 | BBB | |||||||||
Commercial paper | F2 | P-2 | A-2 | |||||||||
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As of February 24, 2014,23, 2015, Fitch Moody’s and Standard & Poor’sMoody’s maintained a stable outlook for their respective ratings of Dominion and Virginia Power.Standard & Poor’s maintained a negative outlook for its respective ratings of Dominion.
A downgrade in an individual company’s credit rating would not necessarily restrict its ability to raise short-term and long-term financing as long as its credit rating remains investment grade, but it could result in an increase in the cost of borrowing. Dominion and Virginia Power workworks closely with Fitch, Moody’s and Standard & Poor’s with the objective of maintaining their currentachieving its targeted credit ratings. The CompaniesDominion may find it necessary to modify theirits business plansplan to maintain or achieve appropriate credit ratings and such changes may adversely affect growth and EPS.
Debt Covenants
As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion and Virginia Power must enter into enabling agreements. These agreements contain covenants that, in the event of default, could result in the
acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion and Virginia Power.Dominion.
Some of the typical covenants include:
Ÿ | The timely payment of principal and interest; |
Ÿ | Information requirements, including submitting financial reports filed with the SEC and information about changes in Dominion’s |
Ÿ | Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation, and restrictions on disposition of all or substantially all assets; |
Ÿ | Compliance with collateral minimums or requirements related to mortgage bonds; and |
Ÿ | Limitations on liens. |
Dominion and Virginia Power areis required to pay annual commitment fees to maintain theirits credit facilities. In addition, theirDominion’s credit agreements contain various terms and conditions that could affect theirits ability to borrow under these facilities. They include maximum debt to total capital ratios and cross-default provisions.
As of December 31, 2013,2014, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:
Company | Maximum Allowed Ratio | Actual Ratio(1) | Maximum Allowed Ratio | Actual Ratio(1) | ||||||||||||
Dominion | 65 | % | 58 | % | 65 | % | 59 | % | ||||||||
Virginia Power | 65 | % | 47 | % |
(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. |
These provisions apply separately to Dominion and Virginia Power.
If Dominion or Virginia Power or any of either company’sits 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 facilityfacilities and the lenders could terminate their commitment to lend funds to that company. Accordingly, any default by Dominion will not affect the lenders’ commitment to Virginia Power. However, any default by Virginia Power would affect the lenders’ commitment toor Dominion Gas under the joint credit agreements.facilities with Dominion would affect the lender’s commitment to Dominion.
Dominion executed RCCs in connection with its issuance of the following hybrid securities:
Ÿ | June 2006 hybrids; |
Ÿ | September 2006 hybrids; and |
Ÿ | June 2009 hybrids. |
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, 2013,2014, the termination dates and covered debt under the RCCs associated with Dominion’s hybrids were as follows:
Hybrid | RCC Termination Date | Designated Covered Debt Under RCC | ||||||
June 2006 hybrids | 6/30/2036 | September 2006 hybrids | ||||||
September 2006 hybrids | 9/30/2036 | June 2006 hybrids | ||||||
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Dominion and Virginia Power monitor themonitors these debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2013,2014, there have been no events of default under or changes to Dominion’s or Virginia Power’s debt covenants.
Virginia Power Mortgage Supplement
Substantially all of Virginia Power’s property is subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. In July 2012, Virginia Power entered into a supplement to the indenture in order to amend various of its terms and conditions and to incorporate certain new provisions. The supplement reduces Virginia Power’s overall compliance responsibilities associated with the indenture by limiting the maximum principal amount of bonds that may be outstanding under the indenture to $10 million unless otherwise provided in a further supplement, and by modifying or eliminating altogether certain compliance requirements while there are no bonds outstanding. The supplement also provides Virginia Power with flexibility to determine when or if certain newly or recently acquired properties will be pledged as collateral under the indenture. There were no bonds outstanding as of December 31, 2013; however, by leaving the indenture open, Virginia Power expects to retain the flexibility to issue mortgage bonds in the future.
Dividend Restrictions
The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2013, the Virginia Commission had not restricted the payment of dividends by Virginia Power.
Certain agreements associated with Dominion’s and Virginia Power’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s or Virginia Power’s ability to pay dividends or receive dividends from theirits subsidiaries at December 31, 2013.2014.
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.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
CONTRACTUAL OBLIGATIONS
Dominion and Virginia Power areis party to numerous contracts and arrangements obligating themit to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion and Virginia Power are partiesis a party as of December 31, 2013.2014. 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 Dominion’s and Virginia Power’s current liabilities will be paid in cash in 2014.2015.
Dominion | 2014 | 2015- 2016 | 2017- 2018 | 2019 and thereafter | Total | |||||||||||||||||||||||||||||||||||
2015 | 2016- 2017 | 2018- 2019 | 2020 and thereafter | Total | ||||||||||||||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||||||||||||||||||
Long-term debt(1) | $ | 1,505 | $ | 2,731 | $ | 2,728 | $ | 13,878 | $ | 20,842 | $ | 861 | $ | 2,756 | $ | 3,900 | $ | 15,683 | $ | 23,200 | ||||||||||||||||||||
Interest payments(2) | 1,006 | 1,855 | 1,593 | 13,280 | 17,734 | 1,081 | 1,914 | 1,603 | 13,147 | 17,745 | ||||||||||||||||||||||||||||||
Leases(3) | 63 | 111 | 80 | 87 | 341 | 63 | 106 | 79 | 79 | 327 | ||||||||||||||||||||||||||||||
Purchase obligations(4): | ||||||||||||||||||||||||||||||||||||||||
Purchased electric capacity for utility operations | 336 | 569 | 263 | 163 | 1,331 | 313 | 408 | 169 | 99 | 989 | ||||||||||||||||||||||||||||||
Fuel commitments for utility operations | 776 | 831 | 238 | 323 | 2,168 | 769 | 825 | 488 | 2,052 | 4,134 | ||||||||||||||||||||||||||||||
Fuel commitments for nonregulated operations | 68 | 143 | 183 | 168 | 562 | 148 | 105 | 105 | 117 | 475 | ||||||||||||||||||||||||||||||
Pipeline transportation and storage | 97 | 113 | 75 | 240 | 525 | 176 | 278 | 244 | 750 | 1,448 | ||||||||||||||||||||||||||||||
Energy commodity purchases for resale(5) | 307 | 45 | 29 | 190 | 571 | 24 | 2 | — | — | 26 | ||||||||||||||||||||||||||||||
Other(6) | 1,495 | 1,686 | 90 | 15 | 3,286 | 1,021 | 79 | 24 | 13 | 1,137 | ||||||||||||||||||||||||||||||
Other long-term liabilities(7): | ||||||||||||||||||||||||||||||||||||||||
Financial derivative-commodities(5) | 126 | 24 | 2 | — | 152 | 18 | 14 | — | — | 32 | ||||||||||||||||||||||||||||||
Other contractual obligations(8) | 64 | 95 | 2 | — | 161 | 98 | 201 | 109 | 19 | 427 | ||||||||||||||||||||||||||||||
Total cash payments | $ | 5,843 | $ | 8,203 | $ | 5,283 | $ | 28,344 | $ | 47,673 | $ | 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 Dominion’s 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, |
(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 |
(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, |
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
(8) | Includes interest rate swap agreements. |
Virginia Power | 2014 | 2015- 2016 | 2017- 2018 | 2019 and thereafter | Total | |||||||||||||||
(millions) | ||||||||||||||||||||
Long-term debt(1) | $ | 58 | $ | 687 | $ | 1,529 | $ | 5,769 | $ | 8,043 | ||||||||||
Interest payments(2) | 386 | 744 | 671 | 4,857 | 6,658 | |||||||||||||||
Leases(3) | 27 | 47 | 31 | 27 | 132 | |||||||||||||||
Purchase obligations(4): | ||||||||||||||||||||
Purchased electric capacity for utility operations | 336 | 569 | 263 | 163 | 1,331 | |||||||||||||||
Fuel commitments for utility operations | 776 | 831 | 238 | 323 | 2,168 | |||||||||||||||
Transportation and storage | 34 | 59 | 50 | 222 | 365 | |||||||||||||||
Other(5) | 353 | 26 | 4 | 10 | 393 | |||||||||||||||
Total cash payments(6) | $ | 1,970 | $ | 2,963 | $ | 2,786 | $ | 11,371 | $ | 19,090 |
PLANNED CAPITAL EXPENDITURES
Dominion’s planned capital expenditures are expected to total approximately $5.8 billion, $5.6 billion and $4.6 billion in 2015, 2016 and $4.2 billion in 2014, 2015 and 2016,2017, respectively. Dominion’s expenditures are expected to include construction and expansion of electric generation and natural gas transmission distribution and storage facilities, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel and the planned construction of the Cove Point liquefaction project in Maryland.
Virginia Power’s planned capital expenditures are expected to total approximately $3.0 billion, $2.5 billionLiquefaction Project and $2.3 billion in 2014, 2015 and 2016, respectively. Virginia Power’s expenditures are expected to include construction and expansionDominion’s portion of electric generation facilities, construction improvements and expansion of electric transmission and distribution assets and purchases of nuclear fuel.the Atlantic Coast Pipeline project.
Dominion and Virginia Power expectexpects to fund theirits capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the respective company’s Board of Directors.
Based on available generation capacity and current estimates of growth in customer demand, Virginia Power will need additional generation in the future. SeeDVP, Dominion Generationand Dominion Energy-Properties in Item 1. Business for a discussion of Dominion’s and Virginia Power’s expansion plans.
These estimates are based on a capital expenditures plan reviewed and endorsed by Dominion’s Board of Directors in late 20132014 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. The CompaniesDominion may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.
Use of Off-Balance Sheet Arrangements
GUARANTEES
Dominion primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others.See Note 22 to the Consolidated Financial Statements for additional information, which information is incorporated herein by reference.
FUTURE ISSUESAND 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.
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Environmental Matters
Dominion and Virginia Power areis subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
ENVIRONMENTAL PROTECTIONAND MONITORING EXPENDITURES
Dominion incurred approximately $192 million, $182 million $189 million and $184$189 million of expenses (including depreciation) during 2014, 2013, 2012, and 20112012 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $174$193 million and $182$188 million in 20142015 and 2015,2016, respectively. In addition, capital expenditures related to environmental controls were $101 million, $64 million, and $213 million for 2014, 2013 and $403 million for 2013, 2012, and 2011, respectively. These expenditures are expected to be approximately $107$97 million and $83$60 million for 20142015 and 2015, respectively.
Virginia Power incurred approximately $150 million, $120 million and $129 million of expenses (including depreciation) during 2013, 2012 and 2011, respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $146 million and $155 million in 2014 and 2015, respectively. In addition, capital
expenditures related to environmental controls were $44 million, $34 million and $77 million for 2013, 2012 and 2011, respectively. These expenditures are expected to be approximately $89 million and $71 million for 2014 and 2015,2016, respectively.
FUTURE ENVIRONMENTAL REGULATIONS
Air
The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, 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 Dominion’s and Virginia Power’sthe Companies’ facilities are subject to the CAA’s permitting and other requirements.
In December 2012, the EPA issued a final rule that set a more stringent annual air quality standard for fine particulate matter. The EPA is expected to completeissued final air qualityattainment/nonattainment designations by December 2014. States will have until 2020 to meetin January 2015. Until states develop their implementation plans, Dominion cannot determine whether or how facilities located in areas designated nonattainment for the revised standard. The extent to which a revised particulate matter standard will impact Dominion is uncertain at this time,be impacted, but isdoes not expectedexpect 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 the Companies operate.Dominion operates. Until the states have developed implementation plans for these standards, the impact on Dominion’s or Virginia Power’s facilities that emit NOX and SO2 is uncertain. Additionally, the impact of permit limits for implementing NAAQS on Dominion’s 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, therefore NOx controls that may have been required by the rulemaking have also been delayed.rulemaking. In the interim,November 2014, the EPA is proceeding with implementation ofissued a new proposal to tighten the current ozone standard and made final attainment/nonattainmentexpects to finalize the rule in October 2015. The EPA is not expected to complete attainment designations in May 2012. Several Dominion electric generating facilities are located in areas impacted by thisfor 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, for the new NOx, SO2 and ozone standards, itDominion is not possibleunable to determine the impact on Dominion’s or Virginia Power’s facilities that emit NOX and SO2. The Companies cannot currently predict with certainty whether or to what extent the new rules will ultimately require additional controls, however,controls. However, if significant expenditures are required to implement additional controls, it could adversely affect Dominion’s results of operations and Dominion’s and Virginia Power’s cash flows.
In June 2005, the EPA finalized amendments to the Regional Haze Rule, also known as the Clean Air Visibility Rule. The rule requires the states to implement Best Available Retrofit Technologybest available retrofit technology requirements for sources to address impacts to visual air quality through regional haze state implementation plans, but allows other alternative options. The EPA is in the process of completing rulemakings on regional haze state implementation plans. Although Dominion and Virginia Power anticipateanticipates 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, additional emission reduction requirements may be imposedwith possible one- or two-year extensions. Dominion’s most recent integrated resources plan filed in August 2014 included an alternative scenario benchmarked on the Companies’ facilities.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.
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Management’s 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 and Virginia Power must comply with applicable aspects of the CWA programs at theirits operating facilities. In July 2004, the EPA published regulations under CWA Section 316(b) that govern existing utilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold. In April 2008, the U.S. Supreme Court granted an industry request to review the question of whether Section 316(b) authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. The U.S. Supreme Court ruled in April 2009 that the EPA has the authority to consider costs versus environmental benefits in selecting the best technology available for reducing impacts of cooling water intakes at power stations. It is currently unknown how the EPA will interpret the ruling in its ongoing rulemaking activity addressing cooling water intakes as well as how the states will implement this decision. In April 2011, the EPA published the proposed rule related to Section 316(b) in the Federal Register, and agreed to publish a final rule no later than July 27, 2012. The EPA has delayed the final rule on five separate occasions and has most recently announced that a final rule will be issued no later than April 2014.
The rule in its proposed form seeks to establish a uniform national standard for impingement, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA proposes to delegate entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of nine facility-specific factors, including a social cost-benefit test.
The proposed rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Under this proposal, Dominion has 16 facilities that may be subject to these proposed regulations. If finalized as proposed, Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power cannot estimate the need or potential for entrainment controls under the proposed rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. However, the impacts of this proposed rule may be material to the Companies’ results of operations, financial condition and/or cash flows.
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 May 22, 2014.September 30, 2015. Dominion and Virginia Power currently cannot predict with certainty the direct or indirect financial impact on operations from these rule
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
revisions, but believes the expenditures to comply with any new requirements could be material.
Solid and Hazardous Waste
In June 2010, the EPA proposed federal regulations under the RCRA for management of coal combustion by-products generated by power plants. The EPA is considering two possible options for the regulation of coal combustion by-products, both of which fall under the RCRA. Under the first proposal, the EPA would classify these by-products as special wastes subject to regulation under subtitle C, the hazardous waste provisions of the RCRA, when destined for disposal at landfills or surface impoundments. Under the second proposal, the EPA would regulate coal combustion by-products under subtitle D of the RCRA, the section for non-hazardous wastes. While the Companies cannot currently predict the outcome of this matter, regulation under either option will affect Dominion’s and Virginia Power’s onsite disposal facilities and coal combustion by-product management practices, and potentially require material investments.
Climate Change Legislation and Regulation
Some regions and states in which Dominion and Virginia Power operateoperates have already adopted or may adopt GHG emission reduction programs. Any of these new or contemplated regulations may affect capital costs, or create significant permitting delays, for new or modified facilities that emit GHGs.
In December 2009, the governors of 11 Northeast and mid-Atlantic states, including Connecticut, Maryland, Massachusetts, New York, Pennsylvania, and Rhode Island (RGGI states plus Pennsylvania) signed a memorandum of understanding committing their states toward developing a low carbon fuel standard to reduce GHG emissions from vehicles. The memorandum of understanding established a process to develop a regional framework by 2011 and examine the economic impacts of a low carbon fuel standard program. Although economic studies and policy options were examined in 2011, a definitive framework has yet to be established.
Dodd-Frank Act
The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The Dodd-FrankCEA, as amended by Title VII of the Dodd- Frank Act, includes provisions that will requirerequires certain over-the-counterover-the counter derivatives, or swaps, to be centrally cleared through a derivatives clearing organization and, if the swap is subject to a clearing requirement, to be executed through an exchangeon a designated contract market or other approved trading platform.swap execution facility. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can choosemay elect the end-user exception to the CEA’s clearing requirements. Dominion has elected to exempt their hedging transactionsits swaps from thesethe CEA’s clearing requirements. The CFTC may continue to adopt final rules and exchange trading requirements. Final rules for the over-the-counter derivative-relatedimplement provisions of the Dodd-Frank Act will continue to be established through theits ongoing rulemaking process, of the applicable regulators, including rules regarding margin requirements for non-cleared swaps. If, as a result of the rulemaking process, Dominion’s or Virginia Power’s derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companiesit could be subject to higher costs including from higherdue to decreased market liquidity or increased margin requirements, for their derivative activities.payments. In addition, Dominion’s swap dealer counterparties may attempt to pass-through additional trading costs in connection with the implementation of, and compliance with, the swaps provisionsTitle VII of the Dodd-Frank Act by the Companies’ counterparties could result in increased costs related to the Companies’
derivative activities.Act. Due to the ongoing rulemaking process, the Companies areDominion is currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on theirits financial condition, results of operations or cash flows.
Cove Point
Dominion is pursuing a liquefaction project at Cove Point, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. The project is expected to cost between approximately $3.4 billion and $3.8 billion, exclusive of financing costs. Subject to environmental review by FERC and final FERC and Maryland Commission approval, 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 2011, Cove Point requested authorization from the DOE to export LNG to countries that have a free trade agreement requiring trade in natural gas with the U.S. as well as countries that do not have such a free trade agreement. In October 2011, Cove Point received authorization from the DOE to export LNG to free trade agreement countries. In September 2013, the DOE conditionally authorized Dominion to export LNG from Cove Point to non-free trade agreement countries.
In April 2013, Cove Point filed with FERC for permission to build liquefaction and other facilities related to the export of natural gas. Also in April 2013, Cove Point filed an application with the Maryland Commission for a CPCN to authorize the construction of an electric generating station needed to power the proposed liquefaction equipment.
In April 2013, Dominion announced it had fully subscribed the capacity of the project with signed 20-year terminal service agreements. Pacific Summit Energy, LLC, a U.S. affiliate of Japanese trading company Sumitomo Corporation, and GAIL Global (USA) LNG LLC, a U.S. affiliate of GAIL (India) Ltd., have each contracted for half of the capacity. Dominion also announced it had awarded its engineering, procurement and construction contract for new liquefaction facilities to IHI/Kiewit Cove Point, a joint venture between IHI E&C International Corporation and Kiewit Energy Company, following completion of the front-end engineering and design work. Following receipt of regulatory and other approvals, construction of liquefaction facilities could begin in 2014 with an in-service date in late 2017.
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 Cove Point liquefaction project, which, assuming it becomes operational, will extend the economic life of Cove Point and contribute to Dominion’s overall growth plan. In total, these renegotiations reduced expected annual revenues from the import-related contracts by approximately $150 million annually from 2017 through 2028, partially offset by approximately $50 million of additional revenues in the years 2013 through 2017.
Dominion is party to an agreement with the Sierra Club restricting activities on portions of the Cove Point property. In May 2012, in response to claims by the Sierra Club, Cove Point filed a complaint for declaratory judgment to confirm its right to
construct the project. In January 2013, a Maryland circuit court issued declaratory judgment confirming Cove Point’s right to build liquefaction facilities. In February 2013, the Sierra Club filed a notice of appeal with the Maryland Court of Special Appeals. In March 2013, Cove Point filed a petition with the Maryland Court of Appeals, the highest appellate court in Maryland, requesting that the Court of Appeals take the appeal directly thus bypassing the intermediate appellate court. In April 2013, the Maryland Court of Appeals denied the petition, and the appeal remains with the Maryland Court of Special Appeals. In January 2014, oral arguments were held in the Maryland Court of Special Appeals. This case is pending. Dominion believes that the agreement with the Sierra Club permits it to locate, construct and operate a liquefaction plant at the Cove Point facility.
Undergrounding Legislation
Legislation has been proposed which would provide 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.
Electric Transmission System Security Plan
Over the next 5 to 10 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.
Solar Facilities
Dominion plans to expand its fleet of contracted solar facilities over the next 24 months by approximately 250 MW. Dominion is currently in active discussions with multiple parties for facilities expected to be placed into service in 2014 and 2015.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs
and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact Dominion and Virginia Power.the Companies.
MARKET RISK SENSITIVE INSTRUMENTSAND RISK MANAGEMENT
Dominion’s and Virginia Power’sThe 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 Dominion’s and Virginia Power’s electric operations and Dominion’s 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, theythe 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. In the second quarterproducts and Dominion Gas primarily holds commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of 2013, Dominion commenced a restructuringnatural gas and other energy-related products.
The repositioning of itsDominion’s producer services business which will resultwas completed in the terminationfirst quarter of natural gas trading and certain energy marketing activities.2014. This, combined with Dominion’s decision in January 2014 to exit thesale of its electric retail energy marketing business, will reducehas reduced Dominion’s 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 Dominion’s non-trading commodity-based financial derivative instruments would have resulted in an increase in fair value of approximately $171$101 million and $126$171 million as of December 31, 2014 and 2013, respectively. The decline in sensitivity is largely due to decreased commodity derivative activity and 2012, respectively. A hypothetical 10% unfavorable change inlower commodity prices of Dominion’s commodity-based financial derivative instruments held for trading purposes would have resulted in a decrease in fair value of approximately $17 million and $18 million as of December 31, 2013 and 2012, respectively.prices.
A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of Virginia Power’s non-trading commodity-based financial derivatives as of December 31, 2014 or 2013.
A hypothetical 10% unfavorable change in commodity prices of Dominion Gas’ commodity-based financial derivative instru-
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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, or 2012.respectively. The decline in sensitivity is largely due to decreased commodity derivative activity.
The impact of a change in energy commodity prices on Dominion’s and Virginia Power’s non-tradingthe 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
Dominion and Virginia PowerThe 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
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
agreements. For variable rate debt and interest rate swaps designated under fair value hedging and outstanding for Dominion and Virginia Power,the Companies, a hypothetical 10% increase in market interest rates would not have resulted in a material change in annual earnings as ofat December 31, 20132014 or 2012.2013.
Dominion and Virginia PowerThe 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 Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2014. As of December 31, 2013, Dominion, and Virginia Power and Dominion Gas had $1.1 billion, $600 million and $600$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 $13$8 million, respectively, in the fair value of Dominion’s, and Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2013. As of December 31, 2012, Dominion and Virginia Power had $1.8 billion and $750 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $21 million and $9 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at December 31, 2012.
The impact of a change in interest rates on Dominion’s and Virginia Power’sthe 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 $126 million in 2013, and 2012, 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 20132014 and 2012,2013, Dominion recorded, in AOCI and
regulatory liabilities, a net increase in unrealized gains on these investments of $172 million and $417 million, and $210 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 $53 million in 2013, and 2012, 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 20132014 and 2012,2013, Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $193$87 million and $89$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 Dominion’s pension and other postretirement plan assets were $706 million in 2014 and $959 million in 2013, and $743 million in 2012, versus expected returns of $610 million and $554 million, respectively. Aggregate actual returns for pension and $509other 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 Dominion’s plan assets would result in an increase in net periodic cost of approximately $14$15 million and $13$14 million as of December 31, 20132014 and 2012,2013, 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 2012,$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
Dominion and Virginia PowerThe 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.Power and Dominion Gas. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and Dominion’s and Virginia Power’sthe Companies’ December 31, 20132014 provision for credit losses, management believes that it is unlikely that a material adverse effect on Dominion’s or Virginia Power’sthe 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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REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 20132014 and 2012,2013, 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, 2013.2014. These financial statements are the responsibility of Dominion’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Resources, Inc. and subsidiaries as of December 31, 20132014 and 2012,2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013,2014, 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), Dominion’s internal control over financial reporting as of December 31, 2012,2014, based on the criteria established inInternal Control-Integrated Framework(1992) (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 20142015 expressed an unqualified opinion on Dominion’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 20142015
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Consolidated Statements of Income
Year Ended December 31, | 2013 | 2012(1) | 2011(1) | |||||||||
(millions, except per share amounts) | ||||||||||||
Operating Revenue | �� | $ | 13,120 | $ | 12,835 | $ | 13,765 | |||||
Operating Expenses | ||||||||||||
Electric fuel and other energy-related purchases | 3,885 | 3,645 | 3,942 | |||||||||
Purchased electric capacity | 358 | 387 | 454 | |||||||||
Purchased gas | 1,331 | 1,177 | 1,764 | |||||||||
Other operations and maintenance | 2,459 | 3,091 | 3,178 | |||||||||
Depreciation, depletion and amortization | 1,208 | 1,127 | 1,018 | |||||||||
Other taxes | 563 | 550 | 529 | |||||||||
Total operating expenses | 9,804 | 9,977 | 10,885 | |||||||||
Income from operations | 3,316 | 2,858 | 2,880 | |||||||||
Other income | 265 | 223 | 178 | |||||||||
Interest and related charges | 877 | 816 | 796 | |||||||||
Income from continuing operations including noncontrolling interests before income taxes | 2,704 | 2,265 | 2,262 | |||||||||
Income tax expense | 892 | 811 | 778 | |||||||||
Income from continuing operations including noncontrolling interests | 1,812 | 1,454 | 1,484 | |||||||||
Loss from discontinued operations(2) | (92 | ) | (1,125 | ) | (58 | ) | ||||||
Net income including noncontrolling interests | 1,720 | 329 | 1,426 | |||||||||
Noncontrolling interests | 23 | 27 | 18 | |||||||||
Net income attributable to Dominion | 1,697 | 302 | 1,408 | |||||||||
Amounts attributable to Dominion: | ||||||||||||
Income from continuing operations, net of tax | 1,789 | 1,427 | 1,466 | |||||||||
Loss from discontinued operations, net of tax | (92 | ) | (1,125 | ) | (58 | ) | ||||||
Net income attributable to Dominion | 1,697 | 302 | 1,408 | |||||||||
Earnings Per Common Share-Basic: | ||||||||||||
Income from continuing operations | $ | 3.09 | $ | 2.49 | $ | 2.56 | ||||||
Loss from discontinued operations | (0.16 | ) | (1.96 | ) | (0.10 | ) | ||||||
Net income attributable to Dominion | $ | 2.93 | $ | 0.53 | $ | 2.46 | ||||||
Earnings Per Common Share-Diluted: | ||||||||||||
Income from continuing operations | $ | 3.09 | $ | 2.49 | $ | 2.55 | ||||||
Loss from discontinued operations | (0.16 | ) | (1.96 | ) | (0.10 | ) | ||||||
Net income attributable to Dominion | $ | 2.93 | $ | 0.53 | $ | 2.45 | ||||||
Dividends declared per common share | $ | 2.25 | $ | 2.11 | $ | 1.97 |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Consolidated Statements of Comprehensive Income
Year Ended December 31, | 2013 | 2012 | 2011 | |||||||||
(millions) | ||||||||||||
Net income including noncontrolling interests | $ | 1,720 | $ | 329 | $ | 1,426 | ||||||
Other comprehensive income (loss), net of taxes: | ||||||||||||
Net deferred gains (losses) on derivatives-hedging activities, net of $161, $5 and $48 tax | (243 | ) | (8 | ) | (67 | ) | ||||||
Changes in unrealized net gains on investment securities, net of $(136), $(68) and $(7) tax | 203 | 108 | 11 | |||||||||
Changes in net unrecognized pension and other postretirement benefit costs, net of $(341), $209 and $147 tax | 516 | (330 | ) | (231 | ) | |||||||
Amounts reclassified to net income: | ||||||||||||
Net derivative (gains) losses-hedging activities, net of $(53), $34 and $28 tax | 77 | (60 | ) | (38 | ) | |||||||
Net realized (gains) losses on investment securities, net of $35, $16 and $(4) tax | (55 | ) | (25 | ) | 6 | |||||||
Net pension and other postretirement benefit costs, net of $(39), $(32) and $(25) tax | 55 | 48 | 39 | |||||||||
Total other comprehensive income (loss) | 553 | (267 | ) | (280 | ) | |||||||
Comprehensive income including noncontrolling interests | 2,273 | 62 | 1,146 | |||||||||
Comprehensive income attributable to noncontrolling interests | 23 | 27 | 18 | |||||||||
Comprehensive income attributable to Dominion | $ | 2,250 | $ | 35 | $ | 1,128 |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Consolidated Balance Sheets
At December 31, | 2013 | 2012 | ||||||
(millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 316 | $ | 248 | ||||
Customer receivables (less allowance for doubtful accounts of $25 and $28) | 1,695 | 1,621 | ||||||
Other receivables (less allowance for doubtful accounts of $4 at both dates) | 141 | 96 | ||||||
Inventories: | ||||||||
Materials and supplies | 689 | 684 | ||||||
Fossil fuel | 393 | 467 | ||||||
Gas stored | 94 | 108 | ||||||
Derivative assets | 687 | 518 | ||||||
Margin deposit assets | 620 | 212 | ||||||
Prepayments | 192 | 326 | ||||||
Deferred income taxes | 778 | 573 | ||||||
Other | 335 | 287 | ||||||
Total current assets | 5,940 | 5,140 | ||||||
Investments | ||||||||
Nuclear decommissioning trust funds | 3,903 | 3,330 | ||||||
Investment in equity method affiliates | 916 | 558 | ||||||
Other | 283 | 303 | ||||||
Total investments | 5,102 | 4,191 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 46,969 | 43,364 | ||||||
Property, plant and equipment, VIE | — | 957 | ||||||
Accumulated depreciation, depletion and amortization | (14,341 | ) | (13,548 | ) | ||||
Total property, plant and equipment, net | 32,628 | 30,773 | ||||||
Deferred Charges and Other Assets | ||||||||
Goodwill | 3,086 | 3,130 | ||||||
Pension and other postretirement benefit assets | 942 | 702 | ||||||
Intangible assets, net | 560 | 536 | ||||||
Regulatory assets | 1,228 | 1,717 | ||||||
Other | 610 | 649 | ||||||
Total deferred charges and other assets | 6,426 | 6,734 | ||||||
Total assets | $ | 50,096 | $ | 46,838 |
At December 31, | 2013 | 2012 | ||||||
(millions) | ||||||||
LIABILITIESAND EQUITY | ||||||||
Current Liabilities | ||||||||
Securities due within one year | $ | 1,519 | $ | 1,363 | ||||
Securities due within one year, VIE | — | 860 | ||||||
Short-term debt | 1,927 | 2,412 | ||||||
Accounts payable | 1,168 | 1,137 | ||||||
Accrued interest, payroll and taxes | 609 | 636 | ||||||
Derivative liabilities | 828 | 510 | ||||||
Other | 943 | 845 | ||||||
Total current liabilities | 6,994 | 7,763 | ||||||
Long-Term Debt | ||||||||
Long-term debt | 16,877 | 15,478 | ||||||
Junior subordinated notes | 1,373 | 1,373 | ||||||
Remarketable subordinated notes | 1,080 | — | ||||||
Total long-term debt | 19,330 | 16,851 | ||||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes and investment tax credits | 7,114 | 5,800 | ||||||
Asset retirement obligations | 1,484 | 1,641 | ||||||
Pension and other postretirement benefit liabilities | 481 | 1,831 | ||||||
Regulatory liabilities | 2,001 | 1,514 | ||||||
Other | 793 | 556 | ||||||
Total deferred credits and other liabilities | 11,873 | 11,342 | ||||||
Total liabilities | 38,197 | 35,956 | ||||||
Commitments and Contingencies (see Note 22) | ||||||||
Subsidiary Preferred Stock Not Subject To Mandatory Redemption | 257 | 257 | ||||||
Equity | ||||||||
Common stock-no par(1) | 5,783 | 5,493 | ||||||
Other paid-in capital | — | 162 | ||||||
Retained earnings | 6,183 | 5,790 | ||||||
Accumulated other comprehensive loss | (324 | ) | (877 | ) | ||||
Total common shareholders’ equity | 11,642 | 10,568 | ||||||
Noncontrolling interest | — | 57 | ||||||
Total equity | 11,642 | 10,625 | ||||||
Total liabilities and equity | $ | 50,096 | $ | 46,838 |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
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, 2010 | 581 | $ | 5,715 | $ | 194 | $ | 6,418 | $ | (330 | ) | $ | 11,997 | $ | — | $ | 11,997 | ||||||||||||||||
Net income including noncontrolling interests | 1,425 | 1,425 | 1 | 1,426 | ||||||||||||||||||||||||||||
Consolidation of noncontrolling interests(2) | — | 61 | 61 | |||||||||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 1 | 49 | 49 | 49 | ||||||||||||||||||||||||||||
Stock repurchases | (13 | ) | (601 | ) | (601 | ) | (601 | ) | ||||||||||||||||||||||||
Other stock issuances(3) | 1 | 17 | (17 | ) | — | — | ||||||||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 2 | 2 | 2 | |||||||||||||||||||||||||||||
Dividends | (1,146 | )(1) | (1,146 | ) | (5 | ) | (1,151 | ) | ||||||||||||||||||||||||
Other comprehensive loss, net of tax | (280 | ) | (280 | ) | (280 | ) | ||||||||||||||||||||||||||
December 31, 2011 | 570 | 5,180 | 179 | 6,697 | (610 | ) | 11,446 | 57 | 11,503 | |||||||||||||||||||||||
Net income including noncontrolling interests | 318 | 318 | 11 | 329 | ||||||||||||||||||||||||||||
Issuance of stock-employee and direct stock purchase plans | 4 | 246 | 246 | 246 | ||||||||||||||||||||||||||||
Stock awards and stock options exercised (net of change in unearned compensation) | 1 | 26 | 26 | 26 | ||||||||||||||||||||||||||||
Other stock issuances(3) | 1 | 41 | (27 | ) | 14 | 14 | ||||||||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 10 | 10 | 10 | |||||||||||||||||||||||||||||
Dividends | (1,225 | )(1) | (1,225 | ) | (11 | ) | (1,236 | ) | ||||||||||||||||||||||||
Other comprehensive 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(4) | 1 | 15 | (8 | ) | 7 | 7 | ||||||||||||||||||||||||||
Present value of stock purchase contract payments related to RSNs(5) | (154 | ) | (2 | ) | (156 | ) | (156 | ) | ||||||||||||||||||||||||
Fairless lease buyout(6) | (15 | ) | (15 | ) | (57 | ) | (72 | ) | ||||||||||||||||||||||||
Dividends | (1,319 | )(1) | (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 |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements
Consolidated Statements of Cash Flows
Year Ended December 31, | 2013 | 2012 | 2011 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net income including noncontrolling interests | $ | 1,720 | $ | 329 | $ | 1,426 | ||||||
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: | ||||||||||||
Impairment of generation assets | 48 | 2,089 | 283 | |||||||||
Net reserves (payments) related to rate refunds | (5 | ) | (151 | ) | 3 | |||||||
Depreciation, depletion and amortization (including nuclear fuel) | 1,390 | 1,443 | 1,288 | |||||||||
Deferred income taxes and investment tax credits | 737 | 246 | 756 | |||||||||
Gains on the sale of assets | (122 | ) | (81 | ) | — | |||||||
Other adjustments | (129 | ) | (164 | ) | (207 | ) | ||||||
Changes in: | ||||||||||||
Accounts receivable | (98 | ) | 292 | 365 | ||||||||
Inventories | (29 | ) | 33 | (185 | ) | |||||||
Deferred fuel and purchased gas costs, net | 102 | 368 | (3 | ) | ||||||||
Prepayments | 123 | (85 | ) | (19 | ) | |||||||
Accounts payable | 50 | (61 | ) | (413 | ) | |||||||
Accrued interest, payroll and taxes | (27 | ) | (12 | ) | (216 | ) | ||||||
Margin deposit assets and liabilities | (414 | ) | 45 | (71 | ) | |||||||
Other operating assets and liabilities | 87 | (154 | ) | (24 | ) | |||||||
Net cash provided by operating activities | 3,433 | 4,137 | 2,983 | |||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions (including nuclear fuel) | (4,104 | ) | (4,145 | ) | (3,652 | ) | ||||||
Proceeds from sales of securities | 1,476 | 1,356 | 1,757 | |||||||||
Purchases of securities | (1,493 | ) | (1,392 | ) | (1,824 | ) | ||||||
Proceeds from the sale of Brayton Point, Kincaid and equity method investment in Elwood | 465 | — | — | |||||||||
Proceeds from Blue Racer | 160 | 115 | — | |||||||||
Restricted cash equivalents | 25 | 108 | 259 | |||||||||
Other | 13 | 118 | 139 | |||||||||
Net cash used in investing activities | (3,458 | ) | (3,840 | ) | (3,321 | ) | ||||||
Financing Activities | ||||||||||||
Issuance (repayment) of short-term debt, net | (485 | ) | 598 | 429 | ||||||||
Issuance of short-term notes | 400 | 400 | — | |||||||||
Repayment of short-term notes | (400 | ) | — | — | ||||||||
Issuance and remarketing of long-term debt | 4,135 | 1,500 | 2,320 | |||||||||
Repayment and repurchase of long-term debt, including redemption premiums | (1,245 | ) | (1,675 | ) | (637 | ) | ||||||
Repayment of junior subordinated notes | (258 | ) | — | — | ||||||||
Acquisition of Juniper noncontrolling interest in Fairless | (923 | ) | — | — | ||||||||
Issuance of common stock | 278 | 265 | 38 | |||||||||
Repurchase of common stock | — | — | (601 | ) | ||||||||
Common dividend payments | (1,302 | ) | (1,209 | ) | (1,129 | ) | ||||||
Subsidiary preferred dividend payments | (17 | ) | (16 | ) | (17 | ) | ||||||
Other | (90 | ) | (14 | ) | (25 | ) | ||||||
Net cash provided by (used in) financing activities | 93 | (151 | ) | 378 | ||||||||
Increase in cash and cash equivalents | 68 | 146 | 40 | |||||||||
Cash and cash equivalents at beginning of year | 248 | 102 | 62 | |||||||||
Cash and cash equivalents at end of year | $ | 316 | $ | 248 | $ | 102 | ||||||
Supplemental Cash Flow Information | ||||||||||||
Cash paid (received) during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts | $ | 852 | $ | 913 | $ | 920 | ||||||
Income taxes | 56 | (58 | ) | 166 | ||||||||
Significant noncash investing and financing activities: | ||||||||||||
Accrued capital expenditures | 375 | 388 | 328 | |||||||||
Consolidation of VIE—assets at fair value | — | — | 957 | |||||||||
Consolidation of VIE—debt | — | — | 896 |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Virginia Electric and Power Company
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (“Virginia Power”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of Virginia Power’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Virginia Power’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 27, 2014
Virginia Electric and Power Company
Consolidated Statements of Income
Year Ended December 31, | 2013 | 2012 | 2011 | |||||||||
(millions) | ||||||||||||
Operating Revenue | $ | 7,295 | $ | 7,226 | $ | 7,246 | ||||||
Operating Expenses | ||||||||||||
Electric fuel and other energy-related purchases | 2,304 | 2,368 | 2,506 | |||||||||
Purchased electric capacity | 358 | 386 | 452 | |||||||||
Other operations and maintenance: | ||||||||||||
Affiliated suppliers | 290 | 305 | 306 | |||||||||
Other | 1,161 | 1,161 | 1,437 | |||||||||
Depreciation and amortization | 853 | 782 | 718 | |||||||||
Other taxes | 249 | 232 | 222 | |||||||||
Total operating expenses | 5,215 | 5,234 | 5,641 | |||||||||
Income from operations | 2,080 | 1,992 | 1,605 | |||||||||
Other income | 86 | 96 | 88 | |||||||||
Interest and related charges | 369 | 385 | 331 | |||||||||
Income from operations before income tax expense | 1,797 | 1,703 | 1,362 | |||||||||
Income tax expense | 659 | 653 | 540 | |||||||||
Net Income | 1,138 | 1,050 | 822 | |||||||||
Preferred dividends | 17 | 16 | 17 | |||||||||
Balance available for common stock | $ | 1,121 | $ | 1,034 | $ | 805 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Comprehensive Income
Year Ended December 31, | 2013 | 2012 | 2011 | |||||||||
(millions) | ||||||||||||
Net income | $ | 1,138 | $ | 1,050 | $ | 822 | ||||||
Other comprehensive income (loss), net of taxes: | ||||||||||||
Net deferred gains (losses) on derivatives-hedging activities, net of $(3), $3 and $3 tax | 6 | (5 | ) | (6 | ) | |||||||
Changes in unrealized net gains on nuclear decommissioning trust funds, net of $(13), $(7) and $(1) tax | 20 | 13 | �� | 2 | ||||||||
Amounts reclassified to net income: | ||||||||||||
Net derivative (gains) losses-hedging activities, net of $—, $(2) and $— tax | — | 2 | (1 | ) | ||||||||
Net realized gains on nuclear decommissioning trust funds, net of $2, $2 and $— tax | (3 | ) | (4 | ) | — | |||||||
Other comprehensive income (loss) | 23 | 6 | (5 | ) | ||||||||
Comprehensive income | $ | 1,161 | $ | 1,056 | $ | 817 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Balance Sheets
At December 31, | 2013 | 2012 | ||||||
(millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 16 | $ | 28 | ||||
Customer receivables (less allowance for doubtful accounts of $11 and $10) | 946 | 849 | ||||||
Other receivables (less allowance for doubtful accounts of $2 and $3) | 78 | 51 | ||||||
Inventories (average cost method): | ||||||||
Materials and supplies | 418 | 385 | ||||||
Fossil fuel | 390 | 404 | ||||||
Prepayments | 32 | 23 | ||||||
Regulatory assets | 128 | 119 | ||||||
Deferred income taxes | 87 | 92 | ||||||
Other | 68 | 30 | ||||||
Total current assets | 2,163 | 1,981 | ||||||
Investments | ||||||||
Nuclear decommissioning trust funds | 1,765 | 1,515 | ||||||
Other | 12 | 14 | ||||||
Total investments | 1,777 | 1,529 | ||||||
Property, Plant and Equipment | ||||||||
Property, plant and equipment | 32,848 | 30,631 | ||||||
Accumulated depreciation and amortization | (10,580 | ) | (10,014 | ) | ||||
Total property, plant and equipment, net | 22,268 | 20,617 | ||||||
Deferred Charges and Other Assets | ||||||||
Intangible assets, net | 193 | 181 | ||||||
Regulatory assets | 417 | 396 | ||||||
Other | 143 | 107 | ||||||
Total deferred charges and other assets | 753 | 684 | ||||||
Total assets | $ | 26,961 | $ | 24,811 |
At December 31, | 2013 | 2012 | ||||||
(millions) | ||||||||
LIABILITIESAND SHAREHOLDER’S EQUITY | ||||||||
Current Liabilities | ||||||||
Securities due within one year | $ | 58 | $ | 418 | ||||
Short-term debt | 842 | 992 | ||||||
Accounts payable | 479 | 430 | ||||||
Payables to affiliates | 69 | 67 | ||||||
Affiliated current borrowings | 97 | 435 | ||||||
Accrued interest, payroll and taxes | 218 | 204 | ||||||
Derivative liabilities | 12 | 33 | ||||||
Customer deposits | 95 | 100 | ||||||
Regulatory liabilities | 41 | 32 | ||||||
Other | 306 | 296 | ||||||
Total current liabilities | 2,217 | 3,007 | ||||||
Long-Term Debt | 7,974 | 6,251 | ||||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes and investment tax credits | 4,137 | 3,879 | ||||||
Asset retirement obligations | 689 | 705 | ||||||
Regulatory liabilities | 1,597 | 1,285 | ||||||
Other | 292 | 194 | ||||||
Total deferred credits and other liabilities | 6,715 | 6,063 | ||||||
Total liabilities | 16,906 | 15,321 | ||||||
Commitments and Contingencies (see Note 22) | ||||||||
Preferred Stock Not Subject to Mandatory Redemption | 257 | 257 | ||||||
Common Shareholder’s Equity | ||||||||
Common stock-no par(1) | 5,738 | 5,738 | ||||||
Other paid-in capital | 1,113 | 1,113 | ||||||
Retained earnings | 2,899 | 2,357 | ||||||
Accumulated other comprehensive income | 48 | 25 | ||||||
Total common shareholder’s equity | 9,798 | 9,233 | ||||||
Total liabilities and shareholder’s equity | $ | 26,961 | $ | 24,811 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Common Shareholder’s Equity
Common Stock | Other Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||||||
Shares | Amount | |||||||||||||||||||||||
(millions, except for shares) | (thousands) | |||||||||||||||||||||||
Balance at December 31, 2010 | 275 | $ | 5,738 | $ | 1,111 | $ | 1,634 | $ | 24 | $ | 8,507 | |||||||||||||
Net income | 822 | 822 | ||||||||||||||||||||||
Dividends | (574 | ) | (574 | ) | ||||||||||||||||||||
Other comprehensive loss, net of tax | (5 | ) | (5 | ) | ||||||||||||||||||||
Balance at December 31, 2011 | 275 | 5,738 | 1,111 | 1,882 | 19 | 8,750 | ||||||||||||||||||
Net income | 1,050 | 1,050 | ||||||||||||||||||||||
Dividends | (575 | ) | (575 | ) | ||||||||||||||||||||
Tax benefit from stock awards and stock options exercised | 2 | 2 | ||||||||||||||||||||||
Other comprehensive income, net of tax | 6 | 6 | ||||||||||||||||||||||
Balance at December 31, 2012 | 275 | 5,738 | 1,113 | 2,357 | 25 | 9,233 | ||||||||||||||||||
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 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Cash Flows
Year Ended December 31, | 2013 | 2012 | 2011 | |||||||||
(millions) | ||||||||||||
Operating Activities | ||||||||||||
Net income | $ | 1,138 | $ | 1,050 | $ | 822 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization (including nuclear fuel) | 1,016 | 927 | 838 | |||||||||
Deferred income taxes and investment tax credits, net | 240 | 502 | 496 | |||||||||
Impairment of generation assets | — | — | 228 | |||||||||
Net reserves (payments) related to rate refunds | (5 | ) | (151 | ) | 3 | |||||||
Other adjustments | (63 | ) | (70 | ) | (93 | ) | ||||||
Changes in: | ||||||||||||
Accounts receivable | (124 | ) | 126 | 76 | ||||||||
Affiliated accounts receivable and payable | 3 | (2 | ) | (7 | ) | |||||||
Inventories | (19 | ) | 8 | (200 | ) | |||||||
Deferred fuel expenses, net | 93 | 378 | 12 | |||||||||
Prepayments | (9 | ) | 18 | 24 | ||||||||
Accounts payable | 15 | 19 | (117 | ) | ||||||||
Accrued interest, payroll and taxes | 14 | (22 | ) | 12 | ||||||||
Other operating assets and liabilities | 30 | (77 | ) | (70 | ) | |||||||
Net cash provided by operating activities | 2,329 | 2,706 | 2,024 | |||||||||
Investing Activities | ||||||||||||
Plant construction and other property additions | (2,394 | ) | (2,082 | ) | (1,885 | ) | ||||||
Purchases of nuclear fuel | (139 | ) | (206 | ) | (205 | ) | ||||||
Purchases of securities | (603 | ) | (638 | ) | (1,057 | ) | ||||||
Proceeds from sales of securities | 572 | 626 | 1,030 | |||||||||
Restricted cash equivalents | 2 | 22 | 137 | |||||||||
Other | (39 | ) | (4 | ) | 33 | |||||||
Net cash used in investing activities | (2,601 | ) | (2,282 | ) | (1,947 | ) | ||||||
Financing Activities | ||||||||||||
Issuance (repayment) of short-term debt, net | (151 | ) | 98 | 294 | ||||||||
Issuance (repayment) of affiliated current borrowings, net | (338 | ) | 248 | 85 | ||||||||
Issuance and remarketing of long-term debt | 1,835 | 450 | 235 | |||||||||
Repayment and repurchase of long-term debt | (470 | ) | (641 | ) | (91 | ) | ||||||
Common dividend payments | (579 | ) | (559 | ) | (557 | ) | ||||||
Preferred dividend payments | (17 | ) | (16 | ) | (17 | ) | ||||||
Other | (20 | ) | (5 | ) | (2 | ) | ||||||
Net cash provided by (used in) financing activities | 260 | (425 | ) | (53 | ) | |||||||
Increase (decrease) in cash and cash equivalents | (12 | ) | (1 | ) | 24 | |||||||
Cash and cash equivalents at beginning of year | 28 | 29 | 5 | |||||||||
Cash and cash equivalents at end of year | $ | 16 | $ | 28 | $ | 29 | ||||||
Supplemental Cash Flow Information | ||||||||||||
Cash paid (received) during the year for: | ||||||||||||
Interest and related charges, excluding capitalized amounts | $ | 328 | $ | 376 | $ | 376 | ||||||
Income taxes | 427 | 225 | (27 | ) | ||||||||
Significant noncash investing activities: | ||||||||||||
Accrued capital expenditures | 276 | 242 | 199 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Combined Notes to Consolidated Financial Statements
NOTE 1. NATUREOF OPERATIONS
Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion’s operations are conducted through various subsidiaries, including Virginia Power, a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s common stock is owned by Dominion. Dominion’s operations also include a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, an LNG import, transport and storage facility in Maryland and regulated gas transportation and distribution operations in Ohio and West Virginia. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations.
In the second quarter of 2013, Dominion commenced a restructuring of its producer services business. The restructuring will result in the termination of natural gas trading and certain energy marketing activities. The restructuring is intended to reduce producer services’ earnings volatility, and is not expected to have a material impact on Dominion’s business.
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. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 25 for further discussion of Dominion’s and Virginia Power’s operating segments.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
General
Dominion and Virginia Power make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses and cash flows for the periods presented. Actual results may differ from those estimates.
Dominion’s and Virginia Power’s Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of their respective majority-owned
subsidiaries and those VIEs where Dominion has been determined to be the primary beneficiary.
Dominion and Virginia Power report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.
Dominion maintains pension and other postretirement benefit plans. Virginia Power participates in certain of these plans. See Note 21 for further information on these plans.
Certain amounts in the 2012 and 2011 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2013 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.
Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.
Year Ended December 31, | 2014 | 2013 | 2012 | |||||||||
(millions, except per share amounts) | ||||||||||||
Operating Revenue | $ | 12,436 | $ | 13,120 | $ | 12,835 | ||||||
Operating | ||||||||||||
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 | 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 |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
58 |
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 Dominion’s Consolidated Financial Statements.
59 |
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 |
60 |
At December 31, | 2014 | 2013 | ||||||
(millions) | ||||||||
LIABILITIESAND 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 Dominion’s Consolidated Financial Statements.
61 |
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, |
(3) | Primarily includes $28 million |
(4) | See Note 17 for further information. |
(5) | See Note 15 for further information. |
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements
62 |
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 Dominion’s Consolidated Financial Statements.
63 |
REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Virginia Electric and Power Company
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (“Virginia Power”) as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, common shareholder’s 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 Power’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Virginia Power’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company and subsidiaries as of December 31, 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
64 |
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 |
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
65 |
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 Power’s Consolidated Financial Statements.
66 |
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.
67 |
At December 31, | 2014 | 2013 | ||||||
(millions) | ||||||||
LIABILITIESAND SHAREHOLDER’S 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 Shareholder’s 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 shareholder’s equity | 10,055 | 9,798 | ||||||
Total liabilities and shareholder’s 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 Power’s Consolidated Financial Statements.
68 |
Virginia Electric and Power Company
Consolidated Statements of Common Shareholder’s 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 Power’s Consolidated Financial Statements.
69 |
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 Power’s Consolidated Financial Statements.
70 |
REPORTOF 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
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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, |
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
72 |
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.
73 |
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.
74 |
At December 31, | 2014 | 2013 | ||||||
(millions) | ||||||||
LIABILITIESAND 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.
75 |
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.
76 |
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.
77 |
Combined Notes to Consolidated Financial Statements
NOTE 1. NATUREOF OPERATIONS
Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion’s operations are conducted through various subsidiaries, including Virginia Power 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 Power’s 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.
Dominion’s 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. Dominion’s 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 public’s ownership interest in Dominion Midstream is reflected as non-controlling interest in Dominion’s 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 Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
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 segment’s performance and the effect of certain items recorded at Dominion Gas as a result of the recognition of Dominion’s 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. Dominion’s 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 Power’s 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.
78 |
The primary types of sales and service activities reported as operating revenue for Dominion are as follows:
Ÿ | Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; |
Ÿ | Nonregulated electric sales consist primarily of sales of electricity |
Ÿ |
|