UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20132016
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 | |||
001-37591 | 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:
Registrant | Title of Each Class | Name of Each Exchange on Which Registered | ||
DOMINION RESOURCES, INC. | ||||
Common Stock, no par value | New York Stock Exchange | |||
| 2014 Series A
| |||
New York Stock Exchange | ||||
New York Stock Exchange | ||||
| 2016 Series A 5.25% Enhanced Junior Subordinated Notes | New York Stock
| ||
DOMINION GAS HOLDINGS, LLC | 2014 Series C 4.6% Senior Notes | 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 ☒ 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 ☒
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 ☒ 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 ☒ 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 Company x☒ Dominion Gas Holdings, LLC ☒
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 | 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 ☒ | 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 ☒ | 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 ☒ Virginia Electric and Power Company Yes ☐ No ☒ Dominion Gas Holdings, LLC Yes ☐ No ☒
The aggregate market value of Dominion Resources, Inc. common stock held by non-affiliates of Dominion was approximately $47.9 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. At February 15, 2017, Dominion had 628,115,398 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 2017 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 |
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3 | ||||||
Part I | ||||||
1. | 8 | |||||
1A. | 25 | |||||
1B. | 32 | |||||
2. | 32 | |||||
3. | 36 | |||||
4. | 36 | |||||
37 | ||||||
Part II | ||||||
5. | 38 | |||||
6. | 39 | |||||
7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 40 | ||||
7A. | 58 | |||||
8. | 60 | |||||
9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 168 | ||||
9A. | 168 | |||||
9B. | 171 | |||||
Part III | ||||||
10. | 172 | |||||
11. | 172 | |||||
12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 172 | ||||
13. | Certain Relationships and Related Transactions, and Director Independence | 172 | ||||
14. | 173 | |||||
Part IV | ||||||
15. | 174 | |||||
16. | 181 |
2 |
The following abbreviations or acronyms used in this Form10-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 Biennial Review Order | Order issued by the Virginia Commission in November 2015 concluding the 2013—2014 biennial review of Virginia Power’s base rates, terms and conditions | |
2016 Equity Units | Dominion’s 2016 Series A Equity Units issued in August 2016 | |
2017 Proxy Statement | Dominion | |
ABO | Accumulated benefit obligation | |
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AFUDC | Allowance for funds used during construction | |
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AMI | Advanced Metering Infrastructure | |
AMR | Automated meter reading program deployed by East Ohio | |
AOCI | Accumulated other comprehensive income (loss) | |
| Appalachian Power Company | |
ARO | Asset retirement | |
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 | |
bcfe | Billion cubic feet equivalent | |
Bear Garden | A 590 MW combined cycle, naturalgas-fired power station in Buckingham County, Virginia | |
Blue Racer | Blue Racer Midstream, LLC, a joint venture | |
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BP | BP Wind Energy North America Inc. | |
Brayton Point | Brayton Point power station | |
BREDL | Blue Ridge Environmental Defense League | |
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Brunswick County | A | |
CAA | Clean Air Act | |
Caiman | Caiman Energy II, LLC | |
CAIR | Clean Air Interstate Rule | |
CAISO | California ISO | |
CAO | Chief Accounting Officer | |
CAP | IRS Compliance Assurance Process | |
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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 | |
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CNG | Consolidated Natural Gas Company | |
CNO | Chief Nuclear Officer | |
CO2 | Carbon dioxide | |
COL | Combined Construction Permit and Operating License | |
Companies | Dominion, | |
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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 or 1/40 interest in a RSN issued by Dominion | |
Cove Point | Dominion Cove Point LNG, LP | |
Cove Point Holdings | Cove Point GP Holding Company, LLC | |
CPCN | Certificate of Public Convenience and Necessity | |
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CSAPR | Cross State Air Pollution Rule | |
CWA | Clean Water Act |
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Abbreviation or Acronym | Definition | |
DCG | Dominion Carolina Gas Transmission, LLC (successor by statutory conversion to and formerly known as Carolina Gas Transmission Corporation) | |
DEI | Dominion Energy, Inc. | |
DGP | Dominion Gathering and Processing, Inc. | |
Dodd-Frank Act | The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 | |
DOE | Department of Energy |
Dominion | The legal entity, Dominion Resources, Inc., one or more of | |
Dominion Direct® | A dividend reinvestment and open enrollment direct stock purchase plan | |
Dominion Gas | The legal entity, Dominion Gas Holdings, LLC, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Gas Holdings, LLC and its consolidated subsidiaries | |
Dominion Iroquois | Dominion Iroquois, Inc., which, effective May 2016, holds a 24.07% noncontrolling partnership interest in Iroquois | |
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Dominion Questar Combination | Dominion’s acquisition of Dominion Questar completed on September 16, 2016 pursuant to | |
DRS | Dominion Resources Services, Inc. | |
DSM | Demand-side management | |
Dth | Dekatherm | |
DTI | Dominion Transmission, Inc. | |
Duke | The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries or operating segments, or the entirety of Duke Energy Corporation and its consolidated subsidiaries | |
DVP | Dominion Virginia Power operating segment | |
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East Ohio | The East Ohio Gas Company, doing business as Dominion East Ohio | |
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Elwood | Elwood power station | |
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EPA | Environmental Protection Agency | |
EPACT | Energy Policy Act of 2005 | |
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EPS | Earnings per share | |
ERISA | The Employee Retirement Income Security Act of 1974 | |
ERM | Enterprise Risk Management | |
ERO | Electric Reliability Organization | |
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Excess Tax Benefits | Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation | |
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FASB | Financial Accounting Standards Board | |
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FERC | Federal Energy Regulatory Commission | |
Fitch | Fitch Ratings Ltd. | |
Four Brothers | Four Brothers Solar, LLC, a limited liability company owned by Dominion and Four Brothers Holdings, LLC, a wholly-owned subsidiary of NRG effective November 2016 | |
Fowler Ridge |
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FTRs | Financial transmission rights | |
GAAP | U.S. generally accepted accounting principles | |
Gal | Gallon | |
GHG | Greenhouse gas | |
Granite Mountain | Granite Mountain Holdings, LLC, a limited liability company owned by Dominion and Granite Mountain Renewables, LLC, a wholly-owned subsidiary of NRG effective November 2016 | |
Green Mountain | Green Mountain Power Corporation | |
| An approximately 1,588 MW naturalgas-fired combined-cycle power station under construction in Greensville County, Virginia | |
Hastings | A natural gas processing and fractionation facility located near Pine Grove, West Virginia | |
HATFA of 2014 | Highway and Transportation Funding Act of 2014 |
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Abbreviation or Acronym | Definition | |
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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Iroquois | Iroquois Gas Transmission System, L.P. | |
IRS | Internal Revenue Service | |
ISO | Independent system operator | |
ISO-NE | ISO New England | |
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June 2006 hybrids | Dominion’s 2006 Series A Enhanced Junior Subordinated Notes due 2066 | |
June 2009 hybrids | Dominion’s 2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to extensions no later than 2079 | |
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Kewaunee | Kewaunee nuclear power station |
Keys Energy Project |
Project to provide 107,000 Dths/day of firm transportation service from Cove Point’s interconnect with Transco in Fairfax County, Virginia to Keys Energy Center, LLC’s power generating facility in Prince George’s County, Maryland
Kincaid | Kincaid power station | |
kV | Kilovolt | |
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Liability Management Exercise | Dominion exercise in 2014 to redeem certain debt and preferred securities | |
LIBOR | London Interbank Offered Rate | |
LIFO | Last-in-first-out inventory method | |
Line |
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LNG | Liquefied natural gas | |
Local 50 | International Brotherhood of Electrical Workers Local 50 | |
Local 69 | Local 69, Utility Workers Union of America, United Gas Workers | |
Lordstown Project | Project to provide 129,000 Dths/day of firm transportation service to the Lordstown power station in northeast Ohio | |
LTIP | Long-term incentive program | |
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Massachusetts Municipal | Massachusetts Municipal Wholesale Electric Company | |
MATS | Utility Mercury and Air Toxics Standard Rule | |
mcf |
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mcfe | Thousand cubic feet equivalent | |
MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
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MGD | Million gallons a day | |
Millstone | Millstone nuclear power station | |
MISO |
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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 | |
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NAV | Net asset value | |
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NedPower |
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NEIL | Nuclear Electric Insurance Limited | |
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NERC | North American Electric Reliability Corporation | |
| Collectively, North East Transmission Co., Inc. and National Grid IGTS Corp. | |
NGL | Natural gas | |
NJNR | NJNR Pipeline Company | |
NO2 | Nitrogen dioxide | |
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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 | |
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NRC | Nuclear Regulatory Commission | |
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Abbreviation or Acronym | Definition | |
NRG | The legal entity, NRG Energy, Inc., one or more of its consolidated subsidiaries (including, effective November 2016, Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of NRG Energy, Inc. and its consolidated subsidiaries | |
NSPS | New Source Performance Standards | |
NYSE | New York Stock Exchange | |
October 2014 hybrids | Dominion’s 2014 Series A Enhanced Junior Subordinated Notes due 2054 | |
ODEC | Old Dominion Electric Cooperative | |
Ohio Commission | Public Utilities Commission of Ohio | |
Order 1000 | Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development | |
Philadelphia Utility Index | Philadelphia Stock Exchange Utility Index | |
PHMSA | Pipeline and Hazardous Materials Safety Administration | |
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. | |
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ppb | Parts-per-billion | |
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| Questar Gas Company | |
Questar Pipeline | Questar Pipeline, LLC (successor by statutory conversion to and formerly known as Questar Pipeline Company), one or more of its consolidated subsidiaries, or the entirety of Questar Pipeline, LLC and its consolidated subsidiaries | |
RCC | Replacement Capital | |
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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 | |
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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 GV | A rate adjustment clause associated with the recovery of costs related to Greensville 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 | |
RiderUS-2 | A rate adjustment clause associated with Woodland, Scott Solar and Whitehouse | |
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 | |
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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 | |
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Scott Solar | A 17 MW utility-scale solar power station in Powhatan County, VA | |
SEC | Securities and Exchange Commission | |
September 2006 hybrids | Dominion’s 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. | |
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Surry | Surry nuclear power station | |
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Abbreviation or Acronym | Definition | |
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TransCanada | The legal entity, TransCanada Corporation, one or more of its consolidated subsidiaries or operating segments, or the entirety of TransCanada Corporation and its consolidated subsidiaries | |
TSR | Total shareholder return | |
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UAO | Unilateral Administrative Order | |
UEX Rider | Uncollectible Expense Rider deployed by East Ohio | |
Utah Commission | Public Service Commission of Utah | |
VDEQ | Virginia Department of Environmental Quality | |
VEBA | Voluntary Employees’ Beneficiary Association | |
VIE | Variable interest entity | |
Virginia City Hybrid Energy Center | A | |
Virginia Commission | Virginia State Corporation Commission | |
Virginia Power | The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments, or the entirety of Virginia Electric and Power Company 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 | |
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Wexpro Agreement | An agreement effective August 1981, which sets forth the rights of Questar Gas to receive certain benefits from Wexpro’s operations, including cost-of-service gas | |
Wexpro II Agreement | An agreement with the states of Utah and Wyoming modeled after the Wexpro Agreement that allows for the addition of properties under the cost-of-service methodology for the benefit of Questar Gas customers | |
Whitehouse | A 20 MW utility-scale solar power station in Louisa County, VA | |
Woodland | A 19 MW utility-scale solar power station in Isle of Wight County, VA | |
Wyoming Commission | Wyoming Public Service Commission |
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 regionand Rocky Mountain regions of the U.S. As of December 31, 2016, Dominion’s portfolio of assets includes approximately 23,60026,400 MW of generating capacity, 6,4006,600 miles of electric transmission lines, 57,00057,600 miles of electric distribution lines, 10,90014,900 miles of natural gas transmission, gathering and storage pipeline and 21,90051,300 miles of gas distribution pipeline, exclusive of service lines. As of December 31, 2016, Dominion presently serves nearlyover 6 million utility and retail energy customers in 15 states and operates one of the nation’s largest underground natural gas storage systems, with approximately 947 bcf1 trillion cubic feet of storage capacity.
In September 2016, Dominion completed the Dominion Questar Combination for total consideration of $4.4 billion and Dominion Questar became a wholly-owned subsidiary of Dominion. Dominion Questar is a Rockies-based integrated natural gas company. Questar Gas, a wholly-owned subsidiary of Dominion Questar, is consolidated by Dominion, and is a voluntary SEC filer. However, its Form10-K is filed separately and is not combined herein.
In March 2014, Dominion formed Dominion Midstream, an MLP designed to grow a portfolio of natural gas terminaling, processing, storage, transportation and related assets. In October 2014, Dominion Midstream launched its initial public offering and issued 20,125,000 common units representing limited partner interests. Dominion has recently and may continue to investigate opportunities to acquire assets that meet its strategic objective for Dominion Midstream. At December 31, 2016, Dominion owns the general partner, 50.9% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Midstream, which owns a preferred equity interest and the general partner interest in Cove Point, DCG, Questar Pipeline and a 25.93% noncontrolling partnership interest in Iroquois. Dominion Midstream is consolidated by Dominion, and is an SEC registrant. However, its Form10-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,infrastructure. 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 existing five-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-
scale solar generation are expected to gather and process natural gas production from the Utica Shale formation,be a focus in eastern Ohio and western Pennsylvania, are being made by the Blue Racer joint venture.
meeting such environmental requirements, particularly in Virginia. 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 approximately600-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, including the Dominion Questar Combination, and in infrastructure whose output is sold under long-term purchase agreements as well as dispositionsthe sale of certain merchant generation facilities during 2012 and 2013 and the ongoing exit of natural gas trading and certainelectric 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.
Dominion Gas,a limited liability company formed in September 2013,is a wholly-owned subsidiary of Dominion and a holding company. It serves as the intermediate parent company for certain 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’ principal wholly-owned subsidiaries are DTI, East Ohio, DGP 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 themid-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. In August 2016, DTI transferred its gathering and processing facilities to DGP. 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. In May 2016, Dominion Gas sold 0.65% of the noncontrolling partnership interest in Iroquois, a FERC-regulated interstate natural gas pipeline in New York and Connecticut, to TransCanada. At December 31, 2016, Dominion Gas holds a
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24.07% noncontrolling partnership interest in Iroquois. All of Dominion Gas’ membership interests are owned by Dominion.
Amounts and information disclosed for Dominion are inclusive of Virginia Power and/or Dominion Gas, where applicable.
EMPLOYEES
As ofAt December 31, 2013,2016, Dominion had approximately 14,50016,200 full-time employees, of which approximately 5,3005,200 employees are subject to collective bargaining agreements. As ofAt December 31, 2013,2016, Virginia Power had approximately 6,7006,800 full-time employees, of which approximately 3,100 employees are subject to collective bargaining agreements. At December 31, 2016, Dominion Gas had approximately 2,800 full-time employees, of which approximately 2,000 employees are subject to collective bargaining agreements.
PRINCIPAL EXECUTIVE OFFICES
Dominion and Virginia Power’s principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and their telephone number is (804) 819-2000.
WHERE YOU CAN FIND MORE INFORMATION ABOUT 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 at1-800-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 Form10-K, quarterly reports on Form10-Q, current reports on Form8-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 DOMINION QUESTAR
In September 2016, Dominion completed the Dominion Questar Combination for total consideration of $4.4 billion and Dominion Questar became a wholly-owned subsidiary of Dominion. In December 2016, Dominion contributed Questar Pipeline to Dominion Midstream. See Note 3 to the Consolidated Financial Statements andLiquidity and Capital Resources in Item 7. MD&A for additional information.
ACQUISITIONOF WHOLLY- OWNED MERCHANT SOLAR PROJECTS
Throughout 2016, Dominion completed the acquisition of various wholly-owned merchant solar projects in Virginia, North
Carolina and South Carolina for $32 million. The projects are expected to cost approximately $425 million to construct, including the initial acquisition cost, and are expected to generate approximately 221 MW.
Throughout 2015, Dominion completed the acquisition of various wholly-owned merchant solar projects in California and Virginia for $381 million. The projects cost $588 million to construct, including the initial acquisition cost, and generate 182 MW.
Throughout 2014, Dominion completed the acquisition of various wholly-owned solar development projects in California for $200 million. The projects cost $578 million to construct, including the initial acquisition cost, and generate 179 MW.
See Note 3 to the Consolidated Financial Statements for additional information.
ACQUISITIONOF NON-WHOLLY-OWNED MERCHANT SOLAR PROJECTS
In 2015, Dominion acquired 50% of the units in Four Brothers and Three Cedars from SunEdison for $107 million. In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison. The facilities began commercial operations in the third quarter of 2016, with generating capacity of 530 MW, at a cost of $1.1 billion. See Note 3 to the Consolidated Financial Statements for additional information.
SALEOF INTERESTIN MERCHANT SOLAR PROJECTS
In September 2015, Dominion signed an agreement to sell a noncontrolling interest (consisting of 33% of the equity interests) in all of its then wholly-owned merchant solar projects, 24 solar projects totaling 425 MW, to SunEdison. In December 2015, the sale of interest in 15 of the solar projects closed for $184 million with the sale of interest in the remaining projects completed in January 2016 for $117 million. Upon closing, SunEdison sold its interest in these projects to Terra Nova Renewable Partners. See Note 3 to the Consolidated Financial Statements for additional information.
DOMINION MIDSTREAM ACQUISITIONOF INTERESTIN IROQUOIS
In September 2015, Dominion Midstream acquired from NG and NJNR a 25.93% noncontrolling partnership interest in Iroquois. The investment was recorded at $216 million based on the value of Dominion Midstream’s common units at closing. The common units issued to NG and NJNR are reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. See Note 3 to the Consolidated Financial Statements for additional information.
ACQUISITIONOF DCG
In January 2015, Dominion completed the acquisition of 100% of the equity interests of DCG from SCANA Corporation for $497 million in cash, as adjusted for working capital. In April 2015, Dominion contributed DCG to Dominion Midstream. See Note 3 to the Consolidated Financial Statements for additional information.
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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.$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 $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 $84 million.
In September 2013, DTI sold LineTL-388 to Blue Racer for $75 million in cash proceeds.
In December 2012, East Ohio sold two pipeline systems to an affiliate for consideration of $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 $115 million.
See Note 9 to the Consolidated Financial Statements for additional information on sales of pipelines and pipeline systems.
ASSIGNMENTSOF SHALE DEVELOPMENT RIGHTS
In March 2015, Dominion Gas and a natural gas producer closed on an amendment to a December 2013 agreement, which included the immediate conveyance of approximately 9,000 acres of Marcellus Shale development rights and atwo-year extension of the term of the original agreement. The conveyance of development rights resulted in the recognition of $43 million of previously deferred revenue. In April 2016, Dominion Gas and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of a 32% partial interest in the remaining approximately 70,000 acres. This conveyance resulted in the recognition of the remaining $35 million of previously deferred revenue.
Also in March 2015, Dominion Gas conveyed to a natural gas producer approximately 11,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields and received proceeds of $27 million and an overriding royalty interest in gas produced from the acreage.
In September 2015, Dominion Gas closed on an agreement with a natural gas producer to convey approximately 16,000 acres of Utica and Point Pleasant Shale development rights underneath one of its natural gas storage fields. The agreement provided for a payment to Dominion Gas, subject to customary adjustments, of $52 million and an overriding royalty interest in gas produced from the acreage.
In November 2014, Dominion Gas closed on 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 Dominion Gas, 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, Dominion Gas 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 Dominion Gas, subject to customary adjustments, of approximately $200 million over a period of nine years, and an 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.
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 in allocating resources among the segments.resources.
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 in allocating resources.
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 or in allocating resources amongand the segments.effect of certain items recorded at Dominion Gas as a result of Dominion’s basis in the net assets contributed.
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.
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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 | |||||||||||
| X | |||||||||||||
Dominion Energy | Gas transmission and storage | X | (1) | X | ||||||||||
Gas distribution and storage | X | X | ||||||||||||
Gas | X | X | ||||||||||||
LNG | X | |||||||||||||
Nonregulated retail energy marketing | X |
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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 distribution (including customer service) operations, which serve approximately 2.52.6 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.
DVP announced itsDVP’s existing five-year investment plan which includes spending approximately $4.8$8.4 billion from 20142017 through 20182021 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.reliability and regulatory compliance. 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 106137 minutes at the end of 2013, down from2016, which is higher compared to the three-year average of 130 minutes.123 minutes, due to storm-related outages across all seasons. Virginia Power’s overall customer satisfaction, however, improved year over year when compared to peer utilities in the South Large segment of JD Power’s rankings.
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Based on the annual JD2015 J.D. 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.Associates’ scoring. 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, ana 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 fromnon-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 permitting approvals. This could result in additional competition to build and own transmission linesinfrastructure in Virginia Power’s service area in the future and could allow Dominion to seek opportunities to build and own facilities in other service territories.
REGULATION
DVP Operating Segment—Dominion and Virginia Power
Virginia Power’s electric retaildistribution 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.information.
PROPERTIES
DVP Operating Segment—Dominion and Virginia Power
Virginia Power has approximately 6,4006,600 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,facili-
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ties, 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 Virginia Power’s estimated cost):
Surry-to-SkiffesCreek-to-Whealton ($280 million); Mt. Storm-to-Dooms ($240 million); Idylwood substation ($110 million); Dooms-to-Lexington ($130 million); Cunningham-to-Elmont ($110 million); Landstown voltage regulation ($70 million); Warrenton (including RemingtonCT-to-Warrenton, VintHill-to-Wheeler-to-Gainesville, and Vint Hill and Wheeler switching stations) ($110 million); Remington/Gordonsville/Pratts Area Improvement (includingRemington-to-Gordonsville, and new Gordonsville substation transformer) ($110 million); Gainesville-to-Haymarket ($55 million); KingsDominion-to-Fredericksburg ($50 million); Loudoun-Brambleton line-to-Poland Road Substation ($60 million); Cunningham-to-Dooms ($60 million); Carson-to-Rogers Road ($55 million); Dooms-Valley rebuild ($60 million); and Mt. Storm-Valley rebuild ($225 million). Virginia Power plans to increase transmission substation physical security and expects to invest $300 million-$400 million through 2022 to strengthen its electrical system to better protect critical equipment, enhance its spare equipment process and create multiple levels of security. |
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In addition, Virginia Power’s electric distribution network includes approximately 57,00057,600 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines containrights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Whererights-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 is designed to reduce restoration outage time by moving its most outage-prone overhead distribution lines underground, has an annual investment cap of approximately $175 million and is expected to be implemented over the next decade. In August 2016, the Virginia Commission approved the first phase of the program encompassing approximately 400 miles of converted lines and $140 million in capital spending (with approximately $123 million recoverable through Rider U). In December 2016, Virginia Power filed its application with the Virginia Commission to recover costs associated with the first and second phases of this program. The second phase will convert an estimated 244 miles at a cost of $110 million.
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 relatedelectric 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 Dominion includes 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 retail energy marketing operations.assets.
Dominion Generation’s existing five-year electric utility investment plan includes spending approximately $3.3$8.0 billion from 20142017 through 20182021 to develop, finance and construct new generation capacity to meet growing electricity demand within its utility service territory. Significant projectsterritory and maintain reliability. The most significant project currently under construction include Warren County and Brunswickis Greensville County, which areis estimated to cost approximately $1.1 billion and $1.3 billion, excluding financing costs, respectively.costs. SeePropertiesand Environmental Strategy for additional information on thesethis and other utility projects.
In addition, Dominion’s merchant fleet has acquired and developed severalincludes numerous renewable generation projects,facilities, which began commercial operations during the fourth quarter of 2013. The total cost of the projects is approximately $200 million, excluding financing costs, and includesinclude a fuel cell generation facility in Connecticut and solar generation facilities in Indiana, Georgia, and Connecticut.operation or development in nine states, including Virginia. The output of these facilities is sold under long-term power purchase agreements with terms generally ranging from 15 to 25 years. See Note 3 to the Consolidated Financial Statements for additional information regarding certain solar projects.
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%82% of revenue comes from serving Virginia jurisdictional customers. Base rates for the Virginia jurisdiction are set using a modifiedcost-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
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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 Regulation in 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. Variability in earnings provided by Dominion’s renewable merchant fleet is primarily driven by weather.
Dominion’s retail energy marketing operations compete in nonregulated energy markets. The retail business requires limited capital investment and currently has approximately 190 employees. The retail customer base includes 2.1 million customer accounts and is diversified across three product lines: natural gas, electricity and energy-related products and services. Dominion has a heavy concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice. Dominion pursues customers in electricity markets where utilities have divested of generation assets and where customers are permitted and have opted to purchase from the market. Major growth drivers are net customer additions, new market penetration, product development and expanded sales channels and supply optimization. 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-ElectricElectric underState Regulations inRegulation for more information. Currently, North Carolina does not offer retail choice to electric customers.
Dominion Generation Operating Segment—Dominion
Unlike Dominion Generation’s regulatedrecently acquired and developed renewable generation fleet, its merchant generation fleetprojects are not currently subject to significant competition as the output from these facilities is dependent on its ability to operate in a competitive environmentprimarily sold under long-term power purchase agreements with terms generally lasting between 15 and does not have a predetermined rate structure that provides for a rate of return on its capital investments.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.
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 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 spotwholesale 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. 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 Commission and the North Carolina Commission.Commissions. SeeStateRegulations andFederal Regulations inRegulation, Future Issues and NoteOther Mattersin Item 7. MD&A and Notes 13 and 22 to the Consolidated Financial Statements for more information.
The Clean Power Plan and related proposed rules discussed represent a significant regulatory development affecting this segment. SeeFuture Issues and Other Mattersin Item 7. MD&A.
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 19,60021,700 MW. The generation mix is diversified and includes gas, coal, nuclear, gas, oil, hydro, renewables, biomass 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:
In March 2016, the Virginia Commission authorized the construction of Greensville County and related transmission
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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 4,0004,700 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 California, Connecticut, Georgia, Indiana, North Carolina, Tennessee, Utah and Virginia, and wind generation facilities in Indiana and West Virginia. Additional solar projects under construction are as set forth below:
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 CashPayments 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 coalnatural gas and natural gascoal in its fossil fuel plants.
All recent fossil fuel plant construction for 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.Generation, with the exception of the Virginia City Hybrid Energy Center, involves natural gas generation.
Dominion Generation’s natural gas and oil supply is obtained from various sources including purchases from major and independent producers in theMid-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.
Dominion Generation’s coal supply is obtained through long-term contracts and short-term spot agreements from domestic suppliers.
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 andISO-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 | 2016 | 2015 | 2014 | ||||||||||||||||||
Nuclear(1) | 33 | % | 33 | % | 28 | % | 31 | % | 30 | % | 33 | % | ||||||||||||
Natural gas | 31 | 23 | 15 | |||||||||||||||||||||
Coal(2) | 24 | 26 | 30 | |||||||||||||||||||||
Purchased power, net | 21 | 27 | 33 | 8 | 15 | 19 | ||||||||||||||||||
Coal(2) | 29 | 22 | 26 | |||||||||||||||||||||
Natural gas | 16 | 17 | 12 | |||||||||||||||||||||
Other(3) | 1 | 1 | 1 | 6 | 6 | 3 | ||||||||||||||||||
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. |
(3) | Includes oil, hydro, biomass and |
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SEASONALITY
Dominion Generation Operating Segment-Dominion
The supply of electricity to serve Dominion’s nonregulated retail energy marketing customers is procured through market wholesalersSegment—Dominion 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 EnergyVirginia Power for additional information.
SEASONALITY
Sales of electricity for Dominion Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the 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.
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-
termlong-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.
Under the current operating licenses, Virginia Power expectsis scheduled to decommission the Surry and North Anna units during the period 2032 to 2067.2078. NRC regulations allow licensees to apply for extension of an operating license in up to 20-year increments. Virginia Power has announced its intention to apply for an operating life extension for Surry, and may for North Anna as well.
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 stationunit in Wisconsin and commenced decommissioning activities using the SAFSTOR methodology. The planned decommissioning completion date is 2073, which is within the NRC allowed 60 year60-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.
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 (2016 dollars)(1) | Funds in trusts at December 31, 2016 | 2016 contributions to trusts | |||||||||||||||||||||||||
(dollars in millions) | ||||||||||||||||||||||||||||||||
Surry | ||||||||||||||||||||||||||||||||
Unit 1 | 2032 | $ | 497 | $ | 501 | $ | 0.6 | 2032 | $ | 600 | $ | 597 | $ | 0.6 | ||||||||||||||||||
Unit 2 | 2033 | 521 | 493 | 0.6 | 2033 | 620 | 588 | 0.6 | ||||||||||||||||||||||||
North Anna | ||||||||||||||||||||||||||||||||
Unit 1(2) | 2038 | 443 | 398 | 0.4 | 2038 | 513 | 475 | 0.4 | ||||||||||||||||||||||||
Unit 2(2) | 2040 | 456 | 373 | 0.3 | 2040 | 525 | 446 | 0.3 | ||||||||||||||||||||||||
Total (Virginia Power) | 1,917 | 1,765 | 1.9 | 2,258 | 2,106 | 1.9 | ||||||||||||||||||||||||||
Millstone | ||||||||||||||||||||||||||||||||
Unit 1(3) | n/a | 441 | 419 | — | N/A | 373 | 474 | — | ||||||||||||||||||||||||
Unit 2 | 2035 | 556 | 522 | — | 2035 | 563 | 614 | — | ||||||||||||||||||||||||
Unit 3(4) | 2045 | 596 | 512 | — | 2045 | 684 | 604 | — | ||||||||||||||||||||||||
Kewaunee | — | |||||||||||||||||||||||||||||||
Unit 1(5) | n/a | 651 | 685 | — | N/A | 467 | 686 | — | ||||||||||||||||||||||||
Total (Dominion) | $ | 4,161 | $ | 3,903 | $ | 1.9 | $ | 4,345 | $ | 4,484 | $ | 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, Inc., 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 NoteNotes 14 and Note 22 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively.
Dominion Energy
Dominion Energy includes Dominion’s regulated natural gas distribution companies, regulated gas transmission pipelinerespectively, and storage operations, natural gas gathering and by-products extraction activities, LNG operations and its investment in 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.Note 9 for information about nuclear decommissioning trust investments.
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Dominion Energy
The Dominion Energy Operating Segment of Dominion Gasincludes certain of Dominion’s regulated natural gas operations. DTI, the gas transmission pipeline and storage business, serves gas distribution businesses and other customers in the Northeast,mid-Atlantic and Midwest. Included in Dominion Energy’s gas transmission pipeline and storage business is itsDGP conducts gas gathering and extraction activity,processing activities, which sellsinclude the sale of extracted products at market rates. Dominion Energy’s LNG operations involverates, primarily in West Virginia, Ohio and Pennsylvania. East 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 itscustomers primarily in Ohio. Dominion Iroquois holds a 24.07% noncontrolling 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 businessesthis business 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.
Approximately 96% of the transmission capacity under contract on DTI’s pipeline is subscribed with long-term contracts (two years or greater). The remaining 4% is contracted on ayear-to-year basis. Less than 1% of firm transportation capacity is currently unsubscribed. Less than 1% of storage services are unsubscribed. All contracted storage is subscribed with long-term contracts.
Revenue from extractionprocessing and fractionation operations largely results from the sale of commodities at market prices. For DTI’s extraction andDGP’s processing plants, Dominion purchasesGas receives the wet gas product from producers and retains some or all ofmay retain 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 facilitiesas the majority of customers receiving these services 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 therequired to deliver minimum quantities of natural gas and NGLs supplied to DTI’s facilities and commodity prices.gas.
East Ohio utilizes a straight-fixed-variable rate design for a majority of its customers. Under this rate design, East Ohio recovers a largerlarge 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 Dominionalsoincludes LNG operations, Dominion Questar operations, Hope’s gas distribution operations in West Virginia, and nonregulated retail natural gas marketing, as well as Dominion’s investments in the Blue Racer joint venture, Atlantic Coast Pipeline and Dominion Midstream. SeeProperties and Investmentsbelow for additional information regarding the Blue Racer and Atlantic Coast Pipeline investments. 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 andmid-Atlantic and Northeast markets. Dominion has received DOE and FERC approval to export LNG from Cove Point and has begun construction on abi-directional facility, which will be able to import LNG and regasify 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 September 2016, Dominion completed the Dominion Questar Combination and Dominion Questar became a wholly-owned subsidiary of Dominion. Dominion Questar, a Rockies-based integrated natural gas company, included Questar Gas, Wexpro and Questar Pipeline at closing. Questar Gas’ regulated gas distribution operations in Utah, southwestern Wyoming and southeastern Idaho includes 29,200 miles of gas distribution pipeline. Wexpro develops and produces natural gas from reserves supplied to Questar Gas under a cost-of-service framework. Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage services in Utah, Wyoming and western Colorado through 2,200 miles of gas transmission pipeline and 56 bcf of working gas storage. SeeAcquisitions andDispositionsabove and Note 3 to the Consolidated Financial Statements for a description of the Dominion Questar Combination.
In 2014, Dominion formed Dominion Midstream, an MLP initially consisting of a preferred equity interest in Cove Point. SeeGeneral above for more information. Also seeAcquisitions and Dispositionsaboveand Note 3 to the Consolidated Financial Statements for a description of Dominion’s contribution of Questar Pipeline to Dominion Midstream in December 2016 as well as Dominion’s acquisition of DCG, which Dominion contributed to Dominion Midstream in April 2015, and Dominion Midstream’s acquisition of a 25.93% noncontrolling partnership interest in Iroquois in September 2015. DCG provides FERC-regulated interstate natural gas transportation services in South Carolina and southeastern Georgia through 1,500 miles of gas transmission pipeline.
Dominion Energy’s existing five-year investment plan includes spending approximately $8.0 billion from 2017 through 2021 to upgrade existing or add new infrastructure to meet growing energy needs within its service territory and maintain reliability. Demand for natural gas is expected to continue to grow as initiatives to transition to gas from more carbon-intensive fuels are implemented. This plan includes Dominion’s portion of spending for the Atlantic Coast Pipeline Project.
In addition to the earnings drivers noted above for Dominion Gas, earnings for theDominion Energy Operating Segment of Dominionprimarily include the results of rates established by FERC and the West Virginia, Utah, Wyoming and Idaho Commissions. Additionally, Dominion Energy receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain LNG storage and regasification services. Questar Pipeline’s and DCG’s revenues are primarily derived from reservation charges for firm transportation and storage services as provided for in their FERC-approved tariffs. Revenue provided by Questar Gas’ operations is based primarily on rates established by the Utah and Wyoming Commissions. The Idaho Commission has contracted with the Utah Commission for rate oversight of Questar Gas operations in a small area of southeastern Idaho. Hope’s gas distribution operations in West Virginia serve residential, commercial, sale for resale and
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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.
Dominion’s retail energy marketing operations compete in nonregulated energy markets. In March 2014, Dominion completed the sale of its electric retail energy marketing business; however, it still participates in the retail natural gas and energy-related products and services businesses. The remaining customer base includes approximately 1.4 million customer accounts in 17 states. Dominion has a heavy concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice, primarily in the states of Ohio and Pennsylvania.
COMPETITION
Dominion Energy Operating Segment—Dominion and Dominion Gas
Dominion Energy’sGas’ 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 extractionDGP’s processing 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, 2013,2016, 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
Questar Gas and Hope do not currently face direct competition from other distributors of natural gas for residential and commer-
cial customers in their service territories as state regulations in Utah, Wyoming and Idaho for Questar Gas, and West Virginia doesfor Hope, do not allow customers to choose their provider in its retail natural gas markets at this time. SeeRegulation-State Regulations-GasState Regulationsin Regulation for additional information.
Cove Point’s gas transportation, LNG import and storage operations, as well as the Liquefaction Project’s capacity are contracted primarily under long-term fixed reservation fee agreements. However, in the future Cove Point may compete with other independent terminal operators as well as major oil and gas companies on the basis of terminal location, services provided and price. Competition from terminal operators primarily comes from refiners and distribution companies with marketing and trading arms.
Questar Pipeline’s and DCG’s pipeline systems generate a substantial portion of their revenue from long-term firm contracts for transportation services and are therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, Questar Pipeline’s pipeline system faces competitive pressures from similar facilities that serve the Rocky Mountain region and DCG’s pipeline system faces competitive pressures from similar facilities that serve the South Carolina and southeastern Georgia area in terms of location, rates, terms of service, and flexibility and reliability of service.
Dominion’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas. Customers in these markets have the right to select a retail marketer and typically do so based upon price savings or price stability; however, incumbent utilities have the advantage of long-standing relationships with their customers and greater name recognition in their markets.
REGULATION
Dominion Energy’sEnergy Operating Segment—Dominion and Dominion Gas
Dominion Gas’ natural gas transmission pipeline,and storage and LNG operations are regulated primarily by FERC. Dominion Energy’sEast Ohio’s gas distribution service,operations, including the rates that it may charge to customers, isare regulated by the Ohio and West Virginia Commissions.Commission. SeeState Regulations andFederal Regulations inRegulation for more information.
Dominion Energy Operating Segment—Dominion
Cove Point’s, Questar Pipeline’s, and DCG’s operations are regulated primarily by FERC. Questar Gas’ distribution operations, including the rates it may charge customers, are regulated by the Utah, Wyoming and Idaho Commissions. Hope’s gas distribution operations, including the rates that it may charge customers, are regulated by the West Virginia Commission. SeeState Regulations andFederal Regulations inRegulation for more information.
PROPERTIESAND INVESTMENTS
For a description of Dominion’s and Dominion Gas’ existing facilities see Item 2.Properties.
Dominion Energy Operating Segment—Dominion and Dominion Gas
Dominion Energy’s gas distribution network is located inGas has the states of Ohio and West Virginia. This network involves approximately 21,900 miles of pipe, exclusive offollowing significant projects under construction or development to better serve customers or expand its service lines. The rights-offerings within its service territory.
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of-way grants for many natural gas pipelines have been obtained fromIn September 2014, DTI announced its intent to construct and operate 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 rightsSupply Header project which is expected to cost approximately $500 million and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.
Dominion Energy has approximately 10,900 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy owns gas processing and fractionation facilities in West Virginia with a total processing capacity of 280,000 mcfprovide 1,500,000 Dths per day of firm transportation service to various customers. In October 2014, DTI requested authorization to use FERC’spre-filing process. The application to request FERC authorization to construct and fractionation capacity of 580,000 gallons per day. Dominion Energy also operates 20 underground gas storage fields locatedoperate the project facilities was filed in New York, Ohio, Pennsylvania and West Virginia,September 2015, with almost 2,000 storage wells and approximately 349,000 acres of operated leaseholds.
The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 947 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy. The capacity of those fields owned by Dominion’s partners totals about 242 bcf. Dominion Energy also has about 15 bcf of above-ground storage capacity at Cove Point. Dominion Energy has 140 compressor stationsfacilities expected to be in service in late 2019. In December 2014, DTI entered into a precedent agreement with approximately 830,000 installed compressor horsepower.Atlantic Coast Pipeline for the Supply Header project.
In December 2013,June 2014, DTI closed onexecuted binding precedent agreements with two natural gas producers to convey approximately 100,000 acrespower generators for the Leidy South Project. In November 2014, one of Marcellus Shale development rights underneath severalthe power generators assigned a portion of its natural gas storage fields. See Note 10capacity to an affiliate, bringing the Consolidated Financial Statements for further information.
Dominion is pursuing a liquefactiontotal number of project at Cove Point, which would enable the facilitycustomers 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 gas per day for a period of 20 years.three. The DOE previously authorized Dominion to export to countries with free trade agreements. Following receipt 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 natural gas processing and fractionation facility in Natrium, West Virginia. This first phase of the project is fully contracted, was completed in the second quarter of 2013 and was contributedexpected to Blue Racer in the third quarter of 2013 resulting in an increased equity method investment in Blue Racer of $473cost approximately $210 million. In September 2013, the Natrium facility was shut down following a fire at the plant 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 barrels per day of NGLs from the Natrium facility to an interconnect with the ATEX line of Enterprise near Follansbee, West Virginia. Transportation services on the pipeline will be subject to FERC regulation pursuant to the Interstate Commerce
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,August 2016, DTI received FERC authorization to construct and operate the $42 million Natrium-to-Market project. The projectLeidy South Project facilities. Service under the20-year contracts is designedexpected to provide 185,000 dekatherms 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 becommence in service in November 2014.late 2017.
In September 2013, DTI executed binding precedent agreements with several local distribution company customers for the New Market Project.project. The project is expected to cost approximately $159$180 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 April 2016, DTI received FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service in late 2017.
In March 2016, East Ohio executed a binding precedent agreement with a power generator for the Lordstown Project. In January 2017, East Ohio commenced construction of the project, with an in-service date expected in the third quarter of 2017 at a total estimated cost of approximately $35 million.
In 2008, East Ohio began PIR, aimed at replacing approximately 4,100 miles of its pipeline system at a cost of $2.7 billion. In 2011, approval was obtained to include an additional 1,450 miles and to increase annual capital investment to meet the program goal. The program will replace approximately 25% of the pipeline system and is anticipated to take place over a total of 25 years. In March 2015, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years and to increase the annual capital investment, with corresponding increases in the annual rate-increase caps. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to settle East Ohio’s pending application. As requested, the PIR Program and associated cost recovery will continue for another five-year term, calendar years 2017 through 2021, and East Ohio will be permitted to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio. Costs associated with calendar year 2016 investment will be recovered under the existing terms.
Dominion Energy Operating Segment—Dominion
Dominion has the following significant projects under construction or development.
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 tonon-free trade agreement countries.
In May 2014, DTI expectsthe FERC staff issued its EA for the Liquefaction Project. In the EA, the FERC staff addressed a variety of topics related to filethe proposed construction and development of the Liquefaction Project and its potential impact to the environment, and determined that with the implementation of appropriate mitigation measures, the Liquefaction Project can be built and operated safely with no significant impact to the environment. In September 2014, Cove Point received the FERC order authorizing the Liquefaction Project with certain conditions. The conditions regarding the Liquefaction Project set forth in the FERC order largely incorporate the mitigation measures proposed in the EA. In October 2014, Cove Point commenced construction of the Liquefaction Project, with anin-service date anticipated in late 2017 at a total estimated cost of approximately $4.0 billion, excluding financing costs. 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 with20-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 thefront-end engineering and design work, 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.
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 October 2015, Cove Point received FERC authorization to construct the approximately $40 million Keys Energy Project. Construction on the project commenced in December 2015, and the project facilities are expected to be placed into service in March 2017.
In November 2016, Cove Point filed an application to request FERC authorization to construct the approximately $150 million Eastern Market Access Project. Construction on the project is expected to begin in the fourth quarter of 2017, and the project facilities are expected to be placed into service in late 2018.
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DCG—In 2014, DCG executed binding precedent agreements with three customers for the Charleston project. The project is expected to cost approximately $120 million, and provide 80,000 Dths per day of firm transportation service from an existing interconnect with Transcontinental Gas Pipe Line, LLC in Spartanburg County, South Carolina to customers in Dillon, Marlboro, Sumter, Charleston, Lexington and Richland counties, South Carolina. In February 2017, DCG received FERC approval 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 dekatherms per day of firm transportation service from central West Virginia to Clarington, Ohio. In 2014, DTI expects to file 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 $17 million Sabinsville-to-Morrisville project, a pipeline to move additional Marcellus supplies from a TGP pipeline in northeast Pennsylvania to its line in upstate New York. DTI 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 provide approximately 7.5 bcf of incremental storage service and 125,000 dekatherms per day of associated year-round firm transportation service to three local distribution companies under 15-year contracts. Storage capacity for the project will be provided from storage pool enhancements at DTI and capacity leased from East Ohio. DTI intends to construct additional compression facilities and upgrade measurement and regulation in order to provide 115,000 dekatherms per day of transportation service. The remaining 10,000 dekatherms per day of transportation service will not require construction of additional facilities. The $112 million project is expected to be placed into service in the fourth quarter of 2014.2017.
Questar Gas—In 2010, Questar Gas began replacing aging high pressure infrastructure under a cost-tracking mechanism that allows it to place into rate base and earn a return on capital expenditures associated with a multi-year natural gas infrastructure-replacement program upon the completion of each project. At that time, the commission-allowed annual spending in the replacement program was approximately $55 million.
In 2008, East Ohio began PIR, aimed at replacingits 2014 Utah general rate case Questar Gas received approval to include intermediate high pressure infrastructure in the replacement program and increase the annual spending limit to approximately 20%$65 million, adjusted annually using a gross domestic product inflation factor. At that time, 420 miles of its pipeline system.high pressure pipe and 70 miles of intermediate high pressure pipe were identified to be replaced in the program over a 17-year period. Questar Gas has spent about $65 million each year through 2016 under this program. The $2.7 billion, 25-year program is ongoing.evaluated in each Utah general rate case. The next Utah general rate case is anticipated to occur in 2019.
Dominion Energy Equity Method Investments—In September 2015, Dominion, through Dominion Midstream, acquired an additional 25.93% interest in Iroquois. Dominion Gas holds a 24.07% interest with TransCanada holding a 50% interest. Iroquois owns and operates a416-mile FERC regulated interstate natural gas pipeline providing service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, through interconnecting pipelines and exchanges. Iroquois’ pipeline extends from the U.S.-Canadian border at Waddington, New York through the state of Connecticut to South Commack, Long Island, New York and continuing on from Northport, Long Island, New York through the Long Island Sound to Hunts Point, Bronx, New York. See Note 139 to the Consolidated Financial Statements for further information about PIR.Dominion’s equity method investment in Iroquois.
In July 2013, East Ohio signed long-term precedent agreementsSeptember 2014, Dominion, along with two customersDuke and Southern Company Gas (formerly known as AGL Resources Inc.), announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to move 300,000 dekatherms per dayallow Dominion an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. In October 2016, Dominion purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million. The members, which are subsidiaries of processedthe above-referenced parent companies, hold the following membership interests: Dominion, 48%; Duke, 47%; and Southern Company Gas (formerly known as AGL Resources Inc.), 5%. Atlantic Coast Pipeline is focused on constructing an approximately600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, which has a total expected cost of $5.0 billion
to $5.5 billion, excluding financing costs. In October 2014, Atlantic Coast Pipeline requested approval from FERC to utilize thepre-filing process under which environmental review for the outlet of newnatural gas processing facilitiespipeline project will commence. Atlantic Coast Pipeline filed its FERC application in September 2015 and expects to be in service in late 2019. The project is subject to FERC, state and other federal approvals. See Note 9 to the Consolidated Financial Statements for further information about Dominion’s equity method investment in Atlantic Coast Pipeline.
In December 2012, Dominion formed Blue Racer with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio 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.develop 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’s and Dominion Energy’sGas’ natural gas supply is obtained from various sources including purchases from major and independent producers in theMid-Continent and Gulf Coast regions, local producers in the Appalachian area, gas marketers and, for Questar Gas specifically, from Wexpro and other producers in the Rocky Mountain region. Wexpro’s gas marketers.development and production operations serve the majority of Questar Gas’ gas supply requirements in accordance with the Wexpro Agreement and the Wexpro II Agreement, comprehensive agreements with the states of Utah and Wyoming. 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,mid-Atlantic and mid-AtlanticRocky Mountain 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, Midwest and Midwest
Rocky Mountain regions. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transmission capacity.
The supply of gas to serve Dominion’s retail energy marketing customers is procured through Dominion’s energy marketing group and market wholesalers.
SEASONALITY
Dominion Energy’s natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March; however, implementation of the straight-fixed-variable rate design at
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mechanisms in Ohio for East Ohio, hasand Utah, Wyoming and Idaho for Questar Gas, have reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipelinegas transmission 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.
The earnings of Dominion’s producer services business is affected by seasonal changes inretail energy marketing operations also vary seasonally. Generally, the prices of commodities that it aggregates and transports.demand for gas peaks during the winter months to meet heating needs.
Corporate and Other
Corporate and Other Segment—VirginiaSegment-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 in allocating resources among the segments.resources.
Corporate and Other Segment—DominionSegment-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 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 in allocating resources among the segments.resources.
ENVIRONMENTAL STRATEGY
Dominion and Virginia Power are committed to being good environmental stewards. Their ongoing objective is to provide reliable, affordable energy for their customers while being environmentally responsible. The integrated strategy to meet this objective consists of four major elements:
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This strategy incorporates Dominion’s and Virginia Power’s efforts to voluntarily reduce GHG emissions, which are described below. SeeDominion Generation-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 Power remain committed to compliance with all applicable environmental laws, regulations and rules related to their operations. Additional information related to Dominion’s and Virginia Power’s environmental compliance matters can be found inFuture Issues and Other Mattersin Item 7. MD&A and in Note 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 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 systems. The DSM programs began in Virginia in 2010 and in North Carolina in 2011.
Virginia Power currently offers the following DSM programs 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.
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.
SeeFuture Issues and Other Mattersin Item 7. MD&A and Note 22 to the Consolidated Financial Statements for additional information.
Improvements in Other Energy Infrastructure
Virginia Power’s five-year investment plan includes significant capital expenditures to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability. These enhancements are primarily aimed at meeting Virginia 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.
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, in connection with its five-year growth plan, is also pursuing the construction or upgrade of regulated infrastructure in its natural gas business.
Dominion and Virginia Power’s Strategy for Voluntarily Reducing GHG Emissions
While Dominion and Virginia Power have not established a standalone GHG emissions reduction target or timetable, they are actively engaged in voluntary reduction efforts, as well as working toward achieving RPS standards established by existing state regulations, as set forth above. The Companies have an integrated voluntary strategy for reducing overall GHG emission intensity that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, oil, hydro and renewable energy, investing in renewable energy projects, implementing technologies to minimize natural gas releases and promoting energy conservation and efficiency efforts. Below are some of the Companies’ efforts that have or are expected to reduce the Companies’ overall carbon emissions or intensity:
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Dominion also developed a comprehensive GHG inventory for calendar year 2012. For Dominion Generation, Dominion’s and Virginia Power’s direct CO2 equivalent emissions, based on equity share (ownership), were approximately 36.2 million metric tonnes and 24.4 million metric tonnes, respectively, in 2012, compared to 42.1 million metric tonnes and 25.9 million metric tonnes, respectively, in 2011. The decrease in emissions from 2011 to 2012 is largely due to an increase in natural gas usage, less reliance on coal, and more renewable generation. For the DVP operating segment’s electric transmission and distribution operations, direct CO2 equivalent emissions for 2012 were 76,143 metric tonnes, representing a decrease of almost 50% from 2011 due to a decrease in gas leakage from insulating equipment. For 2012, DTI’s (including Cove Point) direct CO2 equivalent emissions were approximately 1.0 million metric tonnes, and Hope’s and East Ohio’s direct CO2 equivalent emissions were approximately 0.9 million metric tonnes, showing a 58% decrease from 2011. 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. Dominion 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 system 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 its EDGE® grid-side efficiency product suite. EDGE® is a modular and adaptive conservation voltage management solution enabling utilities to deploy incremental grid-side energy management that requires no behavioral changes or purchases by end customers. In February 2013, Dominion was awarded a patent relating to the EDGE® technology.
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 state commissions of Virginia, Commission, North Carolina, Commission,Ohio, West Virginia, Utah, Wyoming and Idaho, 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 and transfers of certain facilities andfacilities. The Virginia Commission also regulates the issuance of certain securities.
Electric Regulation in Virginia
Under theThe Regulation Act enacted in 2007, Virginia Power’s base rates are set byinstituted a process that allows the recoverycost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes 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.customers.
The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, underground distribution lines,
environmental compliance, conservation and energy efficiency programs and renewable energy programs;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. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.
Legislation enacted inIn February 2013 amended2015, the Regulation Act prospectively, including elimination of the 50 basis points RPS ROE incentive.Virginia Governor signed legislation into law which will keep Virginia Power’s base rates unchanged until at least December 1, 2022. 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,no biennial reviews will be conducted by the Virginia Commission hasfor the discretionfive successive12-month test periods beginning January 1, 2015, and ending December 31, 2019. The legislation states that Virginia Power’s 2015 biennial review, filed in March 2015, would proceed for the sole purpose of reviewing and determining whether any refunds are due to increase or decrease a utility’s authorized ROEcustomers based on earnings performance for generation and distribution services during the 2013 and 2014 test periods. In addition the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility’s performance consistentROE for use in connection with Virginia Commission precedent that existed priorrate adjustment clauses and requires utilities 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.file integrated resource plans annually rather than biennially.
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 decisionsit may adversely affect Virginia Power’sits results of operations, financial condition and cash flows.
See Note 13 to the Consolidated Financial Statements for additional information.information, which is incorporated herein by reference.
Electric Regulation in North Carolina
Virginia Power’s retail electric base rates in North Carolina are regulated on acost-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 being appealedSee Note 13 to the North Carolina Supreme CourtConsolidated Financial Statements for additional information, which is incorporated herein by multiple parties. In December 2012, Virginia Power established net regulatory assets of $17 million to be recovered over five to ten years in connection with these new rates.reference.
GAS
Dominion’sDominion Questar’s natural gas development, production, transportation, and distribution services, including the rates it may charge its customers, are regulated by the state commissions of Utah, Wyoming and Idaho. East 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.
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Gas Regulation in Utah, Wyoming and Idaho
Questar Gas is subject to regulation of rates and other aspects of its business by the Utah, Wyoming and Idaho Commissions. The Idaho Commission has contracted with the Utah Commission for rate oversight of Questar Gas’ operations in a small area of southeastern Idaho. When necessary, Questar Gas 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 Questar Gas 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, Questar Gas makes routine separate filings with the Utah and Wyoming Commissions to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through the Wexpro Agreement and Wexpro II Agreement. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas 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.
Questar Gas withdrew its general rate case filed in July 2016 with the Utah Commission and agreed not to file a general rate case with the Utah Commission to adjust its base distribution non-gas rates prior to July 2019, unless otherwise ordered by the Utah Commission. In addition Questar Gas agreed not to file a general rate case with the Wyoming Commission with a requested rate effective date earlier than January 2020. This does not impact Questar Gas’ ability to adjust rates through various riders. See Note 3 to the Consolidated Financial Statements for additional information.
Gas Regulation in Ohio
East Ohio is subject to regulation of rates and other aspects of its business by the Ohio Commission. When necessary, East Ohio seeks general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost-of-service by rate class. A straight-fixed-variable rate design, in which the majority of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohio’s customers pursuant to a 2008 rate case settlement.
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
Hope 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.
Legislation was passed in West Virginia authorizing a stand-alone cost recovery mechanism to recover specified costs and a return for infrastructure upgrades, replacements and expansions between general base rate cases.
Status of Competitive Retail Gas Services
BothThe states of the statesOhio and West Virginia, 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 New York Mercantile Exchangemonth-end settlement and passing that gas cost to customers under the Standard Service Offer program. Starting in April 2009, East Ohio buys natural gas under the Standard Service Offer program only for customers not eligible to participate in the Energy Choice program and places Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills.
In January 2013, the Ohio Commission granted East 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, 2013,2016, 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 providers in the retail
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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, CAISO andISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California and Utah, under Dominion’s market-based sales tariffs authorized by FERC.FERC or pursuant to FERC authority to sell as a qualified facility. 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.
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 andup to $1 million per day, per violation and can also be assessednon-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 evaluating its transmission facilities for any discrepancies between design and actual field conditions.programs. 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. NERC continues to develop additional requirements specifically regarding supply chain standards and control centers that impact the bulk electric system. 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, includingQuestar Pipeline, DTI, DCG, Iroquois and certain services performed by Cove Point. FERC also has jurisdiction over siting,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. The design, construction and operation of Cove Point’s LNG facility, including associated natural gas pipelines, the Liquefaction Project and the import and export facilitiesof LNG are also regulated by FERC.
Dominion’s and interstate natural gas pipeline and storage facilities.
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 isand Dominion Gas operate in compliance with FERC standards of conduct, which prohibit the sharing of certainnon-public transmission information or customer specific data by its interstate gas transmission and storage companies withnon-transmission function employees. Pursuant to these standards of conduct, Dominion and Dominion Gas also make certain informational postings available on Dominion’s website.
See Note 13 to the Consolidated Financial Statements for additional information.
Safety Regulations
Dominion and Dominion Gas are also subject to the Pipeline Safety ActsImprovement Act of 2002 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which mandate inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those
located in areas of high-density population. Dominion hasand Dominion Gas have evaluated itstheir 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 13
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The Companies are subject to a number of federal and state laws and regulations, including Occupational Safety and Health Administration, 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 compliance 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.
AIR
The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. Regulated emissions include, but are not limited to, carbon, methane, VOC, other GHG, mercury, other toxic metals, hydrogen chloride, NOx, SO2, and particulate matter. At a minimum, delegated states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements.
GLOBAL CLIMATE CHANGE
The national and international attention in recent years on GHG emissions and their relationship to climate change has resulted in federal, regional and state legislative and regulatory action in this area. DominionSee, for example, the discussion of the Clean Power Plan and Virginia Powerthe United Nation’s Paris Agreement inEnvironmental Matters inFuture Issues and OtherMatters in Item 7. MD&A.
The Companies support national climate change legislation that would provide a consistent, economy-wide approach to addressing this issue and are currently taking action to protect the
environment and address climate change while meeting the futuregrowing 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 Strategyabovebelow, 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.
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. The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of effluent into surface waters and require permits to be obtained from the EPA or the analogous state agency to discharge into state waters or waters of the U.S. Containment berms and similar structures may be required to help prevent accidental releases. Dominion must comply with applicable aspects of the CWA programs at its current and former operating facilities. From time to time, Dominion’s projects and operations may impact tidal and non-tidal wetlands. In these instances, Dominion must obtain authorization from the appropriate federal, state and local agencies prior to impacting a subject wetland. The authorizing agency may impose significant direct or indirect mitigation costs to compensate for such impacts to wetlands.
GASAND OIL WELLS
All wells drilled in tight-gas-sand and shale reservoirs require hydraulic-fracture stimulation to achieve economic production rates and recoverable reserves. The majority of Wexpro’s current and future production and reserve potential is derived from reservoirs that require hydraulic-fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic-fracture stimulation and management and disposal of hydraulic fracturing fluids, are regulated by federal and state agencies that review and approve all aspects of gas- and oil-well design and operation. New environmental initiatives, proposed federal and state legislation, and rule-making pertaining to hydraulic fracture stimulation could increase Wexpro’s costs, restrict its access to natural gas reserves and impose additional permitting and reporting requirements. These potential restrictions on the use of hydraulic-fracture stimulation could materially affect Dominion’s ability to develop gas and oil reserves.
OTHER REGULATIONS
Other significant environmental regulations to which the Companies are subject include the CERCLA (providing for immediate response and removal actions, and contamination clean up, in the event of releases of hazardous substances into the environment), the Endangered Species Act (prohibiting activities that can result in harm to specific species of plants and animals), and federal and state laws protecting graves, sacred sites and cultural resources, including those of Native American populations. These regulations can result in compliance costs and potential adverse effects
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on project plans and schedules such that the Companies’ businesses may be materially affected.
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.
ENVIRONMENTAL STRATEGY
Environmental stewardship is embedded in the Companies’ culture and core values and is the responsibility of all employees. They are committed to working with their stakeholders and the communities in which the Companies operate to find sustainable solutions to the energy and environmental challenges that confront the Companies and the U.S. The Companies are committed to delivering reliable, clean and affordable energy while protecting the environment and strengthening the communities they serve. The Companies are dedicated to meeting their customers’ growing energy needs with innovative, sustainable solutions. It is the Companies’ belief that sustainable solutions must balance the interdependent goals of environmental stewardship and economic prosperity. Their integrated strategy to meet this objective consists of four major elements:
This strategy incorporates the Companies’ efforts to voluntarily reduce GHG emissions, which are described below. SeeDominion Generation-Propertiesand Dominion Energy-Propertiesfor more information on certain of the projects described below.
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 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 and North Carolina Commission approval, provide important incremental steps in assisting customers to reduce energy consumption through programs that include energy audits and incentives for customers to upgrade or install certain energy efficient measures and/or systems. The DSM programs began in Virginia in 2010 and in North Carolina in 2011. Currently, there are residential andnon-residential DSM programs active in the two states. Virginia Power continues to evaluate opportunities to redesign current DSM programs and develop new DSM initiatives in Virginia and North Carolina.
In Ohio, East Ohio offers three DSM programs, approved by the Ohio Commission, designed to help customers reduce their energy consumption.
Questar Gas offers an energy-efficiency program, approved by the Utah and Wyoming Commissions, designed to help customers reduce their energy consumption.
Virginia Power continues to upgrade meters throughout Virginia to AMI, also referred to as smart meters. The AMI meter upgrades are part of an ongoing demonstration effort to help Virginia Power further evaluate the effectiveness of AMI meters in monitoring voltage stability, remotely turn off and on electric service, increase detection and reporting capabilities with respect to power outages and restorations, obtain remote daily meter readings and offer 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. Dominion 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 Renewable Portfolio Standard of 12.5% by 2021 and continues to add utility-scale solar capacity in Virginia.
SeeOperating Segments and Item 2. Properties for additional information, including Dominion’s merchant solar properties.
Improvements in Other Energy Infrastructure
Dominion’s existing five-year investment plan includes significant capital expenditures to upgrade or add new electric transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory, maintain reliability and address environmental requirements. These enhancements are primarily aimed at meeting Dominion’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. Business,Operating Segments, DVP for additional information.
Dominion and Dominion Gas, in connection with their existing five-year investment plans, are also pursuing the construction
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or upgrade of regulated infrastructure in their natural gas businesses. SeeProperties and Investments in Item 1. Business,Operating Segments,Dominion Energyfor additional information, including natural gas infrastructure projects.
The Companies’ GHG Management Strategy
The Companies have not established a standalone GHG emissions reduction target or timetable, but they are actively engaged in GHG emission reduction efforts. The Companies have an integrated strategy for reducing GHG emission intensity with diversification and lower carbon intensity as its cornerstone. The principal components of the strategy include initiatives that address electric energy management, electric energy production, electric energy delivery and natural gas storage, transmission and delivery, as follows:
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 2015 to annual year 2000, the entire electric generating fleet (based on ownership percentage) reduced its average CO2 emissions rate per MWh of energy produced from electric generation by approximately 43%. Comparing annual year 2015 to annual year 2000, the regulated electric generating fleet (based on ownership percentage) reduced its average CO2 emissions rate per MWh of energy produced from electric generation by approximately 23%. Dominion and Virginia Power do not yet have final 2016 emissions data.
Dominion also develops a comprehensive GHG inventory annually. For Dominion Generation, Dominion’s and Virginia Power’s direct CO2 equivalent emissions, based on ownership percentage, were 34.3 million metric tons and 30.9 million metric tons, respectively, in 2015, compared to 33.6 million metric tons and 30.1 million metric tons, respectively, in 2014. For the DVP operating segment’s electric transmission and distribution operations, direct CO2 equivalent emissions for 2015 were 53,819 metric tons, compared to 75,671 metric tons in 2014. For 2015,
DTI’s and Cove Point’s direct CO2 equivalent emissions together were 1.0 million metric tons, decreasing from 1.3 million metric tons in 2014, and Hope’s and East Ohio’s direct CO2 equivalent emissions together remained unchanged since 2014 at 0.9 million metric tons. The Companies’ GHG inventory follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations Part 98 for calculating emissions.
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
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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 adjustedupdated on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism, Virginia Power’s wholesale rates for electric transmission cost of servicereflect the estimated cost-of-service for each calendar year. The difference in the estimated cost-of-service and actual cost-of-service for each calendar year is estimated and thereafter adjustedincluded as an adjustment to reflect Virginia Power’s actualthe wholesale rates for electric transmission costs incurred.service in a subsequent calendar year. 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. They are also subject to retroactive corrections to the extent that the formula rate was not properly populated with the actual costs.
Similarly, various rates and charges assessed by Dominion’s and Dominion Gas’ gas transmission businesses are subject to review by FERC. 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 proceeding that involves the determination of Virginia Power’s actual earned ROE during a combinedtwo-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 successive12-month test periods beginning January 1, 2015 and ending December 31, 2019, and no changes will be made to Virginia Power’s existing base raterates until at least December 1, 2022. During this period, Virginia Power bears the risk of any severe weather events and natural disasters, the risk of asset impairments related to the early retirement of any generation facilities due to the implementation of the Clean Power Plan regulations, as well as an increase or reduction during the biennial review. As a result,in general operating and financing costs, 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 additional 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 acost-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.
DominionGovernmental officials, stakeholders and Virginia Poweradvocacy groups may challenge these regulatory reviews. Such challenges may lengthen the time, complexity and costs associated with such regulatory reviews.
The Companies are subject to complex governmental regulation, including tax regulation, that could adversely affect their results of operations and subject the Companies to monetary penalties.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 fornon-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 couldchange market design in the wholesale markets or affect pricingrules 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.
Dominion and For example, in July 2015, FERC approved changes to PJM’s Reliability Pricing Model capacity market establishing a new Capacity Performance Resource product. This product offers the potential for higher capacity prices but can also impose significant economic penalties on generator owners such as Virginia Power for failure to perform during periods when electricity is in high demand. 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.
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The Companies’ infrastructure build and expansion 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 theymay 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. The Companies compete for projects with companies of varying size and financial capabilities, including some that may have competitive advantages. Commencing construction on announced plants requiresand future projects may require approvals from applicable state and federal agencies.agencies, and such approvals could include mitigation costs which may be material to the Companies. 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 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 Supply Header project, Greensville County and regulations designedmultiple DTI 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 $24 billion in capital expenditures planned by the Companies through 2021. 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 interventions, litigation or other activities of stakeholder and advocacy groups, some of which oppose naturalgas-related and energy infrastructure projects. For example, certain landowners and stake-
holder groups oppose the Atlantic Coast Pipeline Project, which could impede the acquisition ofrights-of-way and other land rights on a timely basis or on acceptable terms. Given that these projects provide the foundation for the Companies’ strategic growth plan, if the Companies are unable to obtain or maintain 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. For example, while Dominion has received the required approvals to commence construction of the Liquefaction Project from the DOE, 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. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could adversely affect the Companies’ ability to execute their business plan.
The Companies are dependent on their contractors for the successful and timely completion of large-scale infrastructure projects. The construction of such projects is expected to take several years, is typically confined within a limited geographic area or difficult terrain 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 the Companies’ financial performance and/or impair the Companies’ ability to execute the business plan for the project as scheduled.
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.
Any additional federal and/or state requirements imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements 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 Clean Power Plan is targeted at reducing CO2 emissions from existing fossil fuel-fired power generation facilities.
Compliance with the Clean Power Plan may require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon reduction programs, purchase of allowances and/or emission rate credits, 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, and expanding renewable resources. 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 higher electric rates, which could affect consumer demand. The cost of compliance with the Clean Power Plan 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 reduc-
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tions, 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 regulations may require GHG emission reductions from the natural gas sector which, in addition to resulting in increased costs, could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products, which could impact the natural gas businesses.
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.
ExistingWe expect that existing environmental laws and regulations may be revised and/or new laws may be adopted or become applicable, including regulation of GHG emissions which could have an impact on the Companies’ business. Risks relating to Dominion or Virginia Power. The EPA is expected to issue additional regulations with respect to air quality under the CAA, including revised NAAQS and regulations governing theregulation of GHG emissions of GHGs from existing fossil fuel-fired electric generating units. Additionalunits are discussed above. In addition, further regulation of air quality and GHG emissions under the CAA maywill 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 combustionby-product handling and disposal practices, that are expected to be applicable to at least somewastewater discharges from steam electric generating stations, management and disposal of its generating facilities.hydraulic fracturing fluids and the potential further regulation of polychlorinated biphenyls.
Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new environmental rules or regulations. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimatingclean-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’sthe Companies’ results of operations, financial performance or liquidity.
If additional federal and/Virginia Power is subject to risks associated with the disposal and storage of coal ash.Virginia Power historically produced and continues to produce coal ash, or state requirements are imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements, such requirementsCCRs, as aby-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 result in compliancecosts that alone or in combinationface litigation regarding alleged CWA violations at Possum Point power station, and is facing litigation regarding alleged CWA violations at Chesapeake power station and 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 stateincur settlement expenses and other federal agencies are focusing considerable attentioncosts, depending on GHG emissions from power generation facilitiesthe outcome of any such litigation, including costs associated with closing, corrective action and their potential role in climate change. Dominionongoing monitoring of certain ash ponds. In addition, the EPA and Virginia recently issued regulations concerning the management and storage of CCRs and West Virginia may impose additional regulations that would apply to the facilities noted above. These regulations would require Virginia Power expect thatto make additional EPAcapital expenditures and increase its operating and maintenance expenses.
Further, while Virginia Power operates its ash ponds and landfills in compliance with applicable state safety regulations, and possibly additional state legislation and/or regulations, may be issued resulting ina release of coal ash with a significant environmental impact, such as 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 requirementsDan River ash basin release by a neighboring utility, 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 allowancesremediation costs, civil and/or offsets, fuel switching, and/or retirement of high-emitting generation facilitiescriminal penalties, claims, litigation, increased regulation 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 tocosts, and reputational damage, and could impact 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 theof Virginia Power.
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’s and Virginia Power’s operations are subject to operational hazards, equipment failures, supply chain disruptions and personnel issues which could negatively affect the Companies.Operation of the Companies’ facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply, pipeline integrity or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. The Companies’ businesses are dependent upon sophisticated information technology systems and network infrastructure, the failure of which could prevent
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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
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market to satisfy forward energy and capacity or other contractual obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.
In addition, there are many risks associated with the Companies’ operations and the transportation, storage and processing of natural gas and NGLs, including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environmental hazards, pole strikes, electric contact cases, the collision of third party equipment with pipelines and avian and other wildlife impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk. Further, the location of pipelines and storage facilities, or generation, transmission, substations and distribution facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.
Dominion and Virginia Power have substantial ownership interests in and operate nuclear generating units; as a result, each may incursubstantial costs and liabilities.Dominion’s and Virginia Power’s nuclear facilities are subject to operational, environmental, health and financial risks such as theon-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. Dominion and Virginia Power maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If Dominion’s and Virginia Power’s decommissioning trust funds are insufficient, and they are not allowed to recover the additional costs incurred through insurance, or in the case of Virginia Power through regulatory mechanisms, their results of operations could be negatively impacted.
Dominion’s and Virginia Power’s nuclear facilities are also subject to complex government regulation which could negatively impact their results of operations. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose
fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending on its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require Dominion and Virginia Power to make substantial expenditures at their nuclear plants. In addition, although the Companies have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could materially and adversely affect their results of operations and/or financial condition. A major incident at a nuclear facility anywhere in the world, such as the nuclear events in Japan in 2011, could cause
the NRC to adopt increased safety regulations or otherwise limit or restrict the operation or licensing of domestic nuclear units.
Dominion depends on third parties to produce theSustained declines in natural gas it gathers and processes,NGL prices have resulted in, and could result in further, curtailments of third-party producers’ drilling programs, delaying the production of volumes of natural gas and NGLs that Dominion and Dominionto provideGas gather, process, and transport and reducing the value of NGLsthat itseparates into marketable products. A reduction in thesequantities could reduce Dominion’s revenues. retained by Dominion obtains itsGas, which may adversely affect Dominion and Dominion Gas’ revenues and earnings.Dominion and 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 other 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 could result in reductions in drilling for new natural gas processingwells, which could decrease the volumes of natural gas supplied to Dominion and fractionation facility are subjectDominion Gas. Producers with direct commodity price exposure face liquidity constraints, which could present a credit risk to contractual minimum fee payments. Natrium is owned by Blue Racer.Dominion and Dominion Gas. Producers could shift their production activities to 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 In addition, Dominion Gas’ revenue from processing and operationfractionation operations largely results from the sale of commodities at market prices. Dominion Gas receives the wet gas product from producers and may retain the extracted NGLs as compensation for its services. This exposes Dominion Gas to commodity price risk for the value of the Cove Point liquefaction project would involve significant risks.As describedspread between the NGL products and natural gas, and relative changes 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 courtthese prices could adversely affect Dominion’s ability to execute its business plan.impact Dominion Gas’ results.
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 operoperationsations 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 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.
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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 inend-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, or the impact of additional compliance obligations, 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 and Dominion Gas may not be able to maintain, renew or replace their existing portfolio of customer contracts successfully,or on favorable terms.Upon contract expiration, customers may not elect tore-contract with Dominion and 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’s and Dominion Gas’ services, the extent to which Dominion and Dominion Gas are able to successfully execute their 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 and Dominion Gas and related decreases in their earnings and cash flows.
Certain of Dominion and Dominion Gas’ gas pipeline services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if the cost toperform such services exceeds the revenues received from such contracts. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other
factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as result of these “negotiated rate” contracts could decrease Dominion and Dominion Gas’ earnings and cash flows.
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. Some of Dominion’s operations are conducted through less than wholly-owned subsidiaries. In such arrangements, Dominion is dependent on third parties to fund their required share of capital expenditures. 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 or failure to perform by customers, suppliers, joint venture partners, financial institutions or other third parties may adversely affect the Companies’ financial results.
Dominion will also be exposed to counterparty credit risk relating to the terminal services agreements for the Liquefaction Project. 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.
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’sDominion’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 additionalNRC-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,
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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, currency 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,
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.purposes.
The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The Dodd-Frank Act includes provisions that will require certainover-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform.Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can choose to exempt their hedging transactions from these clearing and exchange trading requirements. Final rules for theover-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 fornon-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, 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.
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.
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’sthe 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 disastersintentional acts 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, including projects under construction, 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,intentional acts, 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 confidentialinformation, 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.
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,
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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 retainattract and attractretain key executive officers and other skilled professional and technical employeesan appropriately qualified workforce 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 highhigh. Certain events, such as an aging workforce, mismatch of skill set or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base and the length of time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or future availability and cost of contract labor may adversely affect the ability to manage and operate the Companies’ business. In addition, certain specialized knowledge is required of the Companies’ technical employees for transmission, generation and distribution operations. The Companies’ inability to retainattract and attractretain these employees could adversely affect their business and future operating results. An aging workforce
The Questar Combination may not achieve its intended results.The Questar Combination is expected to result in various benefits, including, among other things, being accretive to earnings. Achieving the anticipated benefits of the transaction is subject to a number of uncertainties, including whether the business of Dominion Questar is integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy, industry necessitates recruiting, retaining and developingall of which could have an adverse effect on the next generationcombined company’s financial position, results of leadership.operations or cash flows.
Item 1B. Unresolved Staff Comments
None.
As of December 31, 2013,2016, 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 buildingsbuild-
ings 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 allCertain 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;2016; 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 capacityand Dominion Gas
East Ohio’s gas distribution network is located in Ohio. This network involves approximately 18,900 miles of approximately 1.8 bcf and an aggregate LNG storage capacitypipe, exclusive 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.
service lines. The Cove Point Pipeline is a 36-inch diameter underground, interstateright-of-way grants for many natural gas pipelinepipelines have been obtained from the actual owners of real estate, as underlying titles have been examined. Whererights-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 acase-by-case basis, with results that extendsrange from reimbursed relocation to revocation of permission to operate.
Dominion Gas has approximately 8810,400 miles, from Cove Point to interconnections with Transcontinental Gas Pipe Line Company, LLCexcluding interests held by others, of gas transmission, gathering and storage pipelines located in Fairfax County,the states of Maryland, New York, Ohio, Pennsylvania, Virginia and with ColumbiaWest Virginia. Dominion 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 parallel to the original pipeline.
Dominion Energy 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. Dominion Gas also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with approximately 2,000 storage wells and approximately 399,000 acres of operated leaseholds.
The total designed capacity of the underground storage fields operated by Dominion Gas is approximately 929 bcf. Certain storage fields are jointly-owned and operated by Dominion Gas. The capacity of those fields owned by Dominion Gas’ partners totals approximately 220 bcf.
Dominion
Cove Point’s LNG facility has an operational peak regasification dailysend-out capacity of approximately 1.8 million Dths and an aggregate LNG storage capacity of approximately 14.6 bcfe. In addition, Cove Point has a liquefier that has the potential to create approximately 15,000 Dths/day.
The Cove Point pipeline is a36-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
32 |
Columbia Gas Transmission, LLC and DTI in Loudoun County, Virginia. In 2009, the original pipeline was expanded to include a36-inch diameter expansion that extends approximately 48 miles, roughly 75% of which is parallel to the original pipeline.
Questar Gas distributes gas to customers in Utah, Wyoming and Idaho. Questar Gas owns and operates distribution systems and has a total of 29,200 miles of street mains, service lines and interconnecting pipelines. Questar Gas has a major operations center in Salt Lake City, and has operations centers, field offices and service-center facilities in other parts of its service area.
Questar Pipeline operates 2,200 miles of natural gas transportation pipelines that interconnect with other pipelines in Utah, Wyoming and western Colorado. Questar Pipeline’s system ranges in diameter from lines that are less than four inches to36-inches. Questar Pipeline owns the Clay Basin storage facility in northeastern Utah, which has a certificated capacity of 120 bcf, including 54 bcf of working gas.
DCG’s interstate natural gas pipeline system in South Carolina and southeastern Georgia is comprised of nearly 1,500 miles of transmission pipeline.
In total, Dominion has 170 compressor stations with approximately 1,175,000 installed compressor horsepower.
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, 2013,2016, Dominion Generation’s total utility and merchant generating capacity was approximately 23,60026,400 MW.
29
33 |
The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2013:2016:
VIRGINIA POWER UTILITY GENERATION(1)
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 | ||||||||||||||||||||||
Brunswick County (CC) | Brunswick County, VA | 1,376 | ||||||||||||||||||||
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 | 573 | ||||||||||||||||||
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 | 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 | 7,548 | 35 | % | |||||||||||||||||
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 | (2) | |||||||||||||||||||
Yorktown(3) | Yorktown, VA | 323 | ||||||||||||||||||||
Mecklenburg | Clarksville, VA | 138 | ||||||||||||||||||||
Total Coal | 4,406 | 21 | ||||||||||||||||||||
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 | 15 | ||||||||||||||||||
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 | 10 | ||||||||||||||||||
Hydro | ||||||||||||||||||||||
Bath County | Warm Springs, VA | 1,802 | (5) | Warm Springs, VA | 1,808 | (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 | 2,126 | 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 | Southampton, VA | 51 | ||||||||||||||||||||
Total Biomass | 236 | 1 | 236 | 1 | ||||||||||||||||||
Solar | ||||||||||||||||||||||
Whitehouse Solar | Louisa County, VA | 20 | ||||||||||||||||||||
Woodland Solar | Isle of Wight County, VA | 19 | ||||||||||||||||||||
Scott Solar | Powhatan County, VA | 17 | ||||||||||||||||||||
Total Solar | 56 | — | ||||||||||||||||||||
Various | ||||||||||||||||||||||
Other | Various | 11 | — | |||||||||||||||||||
Mt. Storm (CT) | Mt. Storm, WV | 11 | — | |||||||||||||||||||
17,680 | 19,891 | |||||||||||||||||||||
Power Purchase Agreements | 1,926 | 10 | 1,764 | 8 | ||||||||||||||||||
Total Utility Generation | 19,606 | 100 | % | 21,655 | 100 | % |
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) | The table excludes Virginia Power’s Morgans Corner solar facility located in Pasquotank County, NC which has a net summer capacity of 20 MW, as the facility is dedicated to serving anon-jurisdictional customer. |
Excludes 50% undivided interest owned by ODEC. |
(3) | Coal-fired units are expected to be retired at |
(4) | Excludes 11.6% undivided interest owned by ODEC. |
(5) | Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc. |
DOMINION MERCHANT GENERATION
Plant | Location | Net Summer Capability (MW) | Percentage Net Summer Capability | 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 | 43 | % | ||||||||||||||||
Gas | ||||||||||||||||||||||
Fairless (CC) | Fairless Hills, PA | 1,196 | Fairless Hills, PA | 1,240 | ||||||||||||||||||
Manchester (CC) | Providence, RI | 446 | Providence, RI | 468 | ||||||||||||||||||
Total Gas | 1,642 | 41 | 1,708 | 36 | ||||||||||||||||||
Solar(2) | ||||||||||||||||||||||
Escalante I, II and III | Beaver County, UT | 120 | (3) | |||||||||||||||||||
Amazon Solar Farm U.S. East | Oak Hall, VA | 80 | ||||||||||||||||||||
Granite Mountain East and West | Iron County, UT | 65 | (3) | |||||||||||||||||||
Summit Farms Solar | Moyock, NC | 60 | ||||||||||||||||||||
Enterprise | Beaver County, UT | 40 | (3) | |||||||||||||||||||
Iron Springs | Iron County, UT | 40 | (3) | |||||||||||||||||||
Pavant Solar | Holden, UT | 34 | (4) | |||||||||||||||||||
Camelot Solar | Mojave, CA | 30 | (4) | |||||||||||||||||||
Indy I, II and III | Indianapolis, IN | 20 | (4) | |||||||||||||||||||
Cottonwood Solar | Kings and Kern counties, CA | 16 | (4) | |||||||||||||||||||
Alamo Solar | San Bernardino, CA | 13 | (4) | |||||||||||||||||||
Maricopa West Solar | Kern County, CA | 13 | (4) | |||||||||||||||||||
Imperial Valley 2 Solar | Imperial, CA | 13 | (4) | |||||||||||||||||||
Richland Solar | Jeffersonville, GA | 13 | (4) | |||||||||||||||||||
CID Solar | Corcoran, CA | 13 | (4) | |||||||||||||||||||
Kansas Solar | Lenmore, CA | 13 | (4) | |||||||||||||||||||
Kent South Solar | Lenmore, CA | 13 | (4) | |||||||||||||||||||
Old River One Solar | Bakersfield, CA | 13 | (4) | |||||||||||||||||||
West Antelope Solar | Lancaster, CA | 13 | (4) | |||||||||||||||||||
Adams East Solar | Tranquility, CA | 13 | (4) | |||||||||||||||||||
Catalina 2 Solar | Kern County, CA | 12 | (4) | |||||||||||||||||||
Mulberry Solar | Selmer, TN | 11 | (4) | |||||||||||||||||||
Selmer Solar | Selmer, TN | 11 | (4) | |||||||||||||||||||
Columbia 2 Solar | Mojave, CA | 10 | (4) | |||||||||||||||||||
Azalea Solar | Davisboro, GA | 5 | (4) | |||||||||||||||||||
Somers Solar | Somers, CT | 3 | (4) | |||||||||||||||||||
Total Solar | 687 | 15 | ||||||||||||||||||||
Wind | ||||||||||||||||||||||
Fowler Ridge(1) | Benton County, IN | 150 | (3) | |||||||||||||||||||
NedPower Mt. Storm(1) | Grant County, WV | 132 | (4) | |||||||||||||||||||
Fowler Ridge(5) | Benton County, IN | 150 | (6) | |||||||||||||||||||
NedPower(5) | Grant County, WV | 132 | (7) | |||||||||||||||||||
Total Wind | 282 | 7 | 282 | 6 | ||||||||||||||||||
Solar | ||||||||||||||||||||||
Indy Solar (AC) | Indianapolis, IN | 29 | ||||||||||||||||||||
Azalea Solar (AC) | Washington, GA | 8 | ||||||||||||||||||||
Somers Solar (AC) | Somers, CT | 5 | ||||||||||||||||||||
Total Solar | 42 | 1 | ||||||||||||||||||||
Fuel Cell | ||||||||||||||||||||||
Bridgeport Fuel Cell | Bridgeport, CT | 15 | Bridgeport, CT | 15 | ||||||||||||||||||
Total Fuel Cell | 15 | — | 15 | — | ||||||||||||||||||
Total Merchant Generation | 3,982 | 100 | % | 4,693 | 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) | All solar facilities are alternating current. |
(3) | Excludes 50% noncontrolling interest owned by NRG. |
(4) | Excludes 33% noncontrolling interest owned by Terra Nova Renewable Partners. Dominion’s interest is subject to a lien securing SBL Holdco’s debt. |
(5) | Subject to a lien securing the facility’s debt. |
(6) | Excludes 50% membership interest owned by BP. |
Excludes 50% membership interest owned by Shell. |
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 January 2016, Virginia Power self-reported a release of mineral oil from the Crystal City substation and began extensive cleanup. In February 2016, Virginia Power received a notice of violation from the VDEQ relating to this matter. Virginia Power has assumed the role of responsible party and is continuing to cooperate with ongoing requirements for investigative and corrective action. In September 2016, Virginia Power received a proposed consent order from the VDEQ related to this matter. The order was signed by Virginia Power in October 2016 and approved by the Virginia State Water Control Board in December 2016. The order included a penalty of $260,000, which is inclusive of both the Crystal City substation oil release and an oil release from another Virginia Power facility in 2016. The portion of the penalty attributable to the other facility represents less than $100,000 of the total proposed penalty.
In December 2016, Wexpro received a notice of violation from the Wyoming Division of Air Quality in connection with an alleged non-compliance with an air quality permit and certain air quality regulations relating to Wexpro’s Church Buttes #63 well. The notice did not include a proposed penalty. Dominion is unable to evaluate the final outcome of this matter but it could result in a penalty in excess of $100,000.
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, President and CEO of Dominion from April 2007 to date; | |
Mark F. McGettrick | Executive Vice President and CFO of Dominion | |
Paul D. Koonce (57) | Executive Vice President and President & CEO—Dominion Generation Group of Dominion from January 2017 to date; Executive Vice President and CEO—Dominion Generation Group of Dominion from January 2016 to December 2016; Executive Vice President and CEO—Energy Infrastructure Group of Dominion from February 2013 to December 2015; Executive Vice President of Dominion from April 2006 to | |
| 2013; Executive Vice President | |
| ||
| ||
| December 2015; President of Virginia Power from January 2014 to | |
| ||
Diane Leopold | Senior Vice President and President & CEO—Dominion Energy of Dominion and Dominion Midstream GP, LLC from January 2017 to date; President of Dominion Gas from January 2017 to date; President of DTI, East Ohio and Dominion Cove Point, Inc. | |
Mark O. Webb | Senior Vice President—Corporate Affairs and Chief Legal Officer of Dominion, Virginia Power, Dominion Gas, Dominion Midstream GP, LLC, and Questar Gas from January 2017 to date; Senior Vice President, General Counsel and Chief Risk Officer of Dominion, | |
Michele L. Cardiff (49) | Vice President, Controller and CAO of Dominion and Virginia Power from April 2014 to date, Dominion Gas and Dominion Midstream GP, LLC from March 2014 to date and Questar Gas from September 2016 to date; Vice President—Accounting of DRS from | |
David A. Heacock (59) | President of Virginia Power from June 2009 to date and CNO from June 2009 to September 2016. Mr. Heacock will retire effective March 1, 2017. |
(1) | Any service listed for Virginia Power, Dominion Midstream GP, LLC, Dominion Gas, DTI, |
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, 2014,2017, there were approximately 135,000126,500 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.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 20132016 and 2012.2015. 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 2013:2016:
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) | ||||||||||||
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 | ||||||||||
Total | 3,839 | $ | 62.51 | N/A | 19,629,059 shares/$ | 1.18 billion |
DOMINION PURCHASES OF EQUITY SECURITIES | ||||||||||||||||
Period | Total Number of Shares Purchased(1) | Average Price Paid per Share(2) | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased under the Plans or Programs(3) | ||||||||||||
10/1/2016-10/31/16 | 233 | $ | 74.27 | N/A | 19,629,059 shares/$ | 1.18 billion | ||||||||||
11/1/2016-11/30/16 | — | — | N/A | 19,629,059 shares/$ | 1.18 billion | |||||||||||
12/1/2016-12/31/16 | 2,728 | 73.31 | N/A | 19,629,059 shares/$ | 1.18 billion | |||||||||||
Total | 2,961 | $ | 73.38 | 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 atwo-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. RestrictionsPotential 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. In the first through fourth quarters of 2015, Virginia Power declared and paid quarterly cash dividends of $149 million, $121 million, $146 million and $75 million. In 2016, no dividends were declared or paid given the sufficiency of operating and other cash flows at Dominion. Virginia Power intends to pay quarterly cash dividends in 2017 but is neither required to nor restricted from making such payments.
Dominion Gas
All of Dominion Gas’ membership interests are owned by Dominion. Potential restrictions on its common stock as follows:Dominion Gas’ payment of distributions are discussed in Note 20 to the Consolidated Financial Statements. In the first through fourth quarters of 2015, Dominion Gas declared and paid quarterly cash distributions of $96 million, $68 million, $80 million and $448 million. Dominion Gas declared and paid cash distributions of $150 million in the second quarter of 2016.
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year | ||||||||||||||||
(millions) | ||||||||||||||||||||
2013 | $ | 148 | $ | 120 | $ | 195 | $ | 116 | $ | 579 | ||||||||||
2012 | 149 | 120 | 110 | 180 | 559 |
Item 6. Selected Financial Data
The following table should be read in conjunction with the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.
DOMINION
Year Ended December 31, | 2013 | 2012 | 2011 | 2010 | 2009 | 2016(1) | 2015 | 2014(2) | 2013(3) | 2012(4) | ||||||||||||||||||||||||||||||
(millions, except per share amounts) | ||||||||||||||||||||||||||||||||||||||||
Operating revenue | $ | 13,120 | $ | 12,835 | $ | 13,765 | $ | 14,392 | $ | 14,032 | $ | 11,737 | $ | 11,683 | $ | 12,436 | $ | 13,120 | $ | 12,835 | ||||||||||||||||||||
Income from continuing operations, net of tax | 1,789 | 1,427 | 1,466 | 3,056 | 1,301 | 2,123 | 1,899 | 1,310 | 1,789 | 1,427 | ||||||||||||||||||||||||||||||
Loss from discontinued operations, net of tax | (92 | ) | (1,125 | ) | (58 | ) | (248 | ) | (14 | ) | — | — | — | (92 | ) | (1,125 | ) | |||||||||||||||||||||||
Net income attributable to Dominion | 1,697 | 302 | 1,408 | 2,808 | 1,287 | 2,123 | 1,899 | 1,310 | 1,697 | 302 | ||||||||||||||||||||||||||||||
Income from continuing operations before loss from discontinued operations per common share-basic | 3.09 | 2.49 | 2.56 | 5.19 | 2.19 | 3.44 | 3.21 | 2.25 | 3.09 | 2.49 | ||||||||||||||||||||||||||||||
Net income attributable to Dominion per common share-basic | 2.93 | 0.53 | 2.46 | 4.77 | 2.17 | 3.44 | 3.21 | 2.25 | 2.93 | 0.53 | ||||||||||||||||||||||||||||||
Income from continuing operations before loss from discontinued operations per common share-diluted | 3.09 | 2.49 | 2.55 | 5.18 | 2.19 | 3.44 | 3.20 | 2.24 | 3.09 | 2.49 | ||||||||||||||||||||||||||||||
Net income attributable to Dominion per common share-diluted | 2.93 | 0.53 | 2.45 | 4.76 | 2.17 | 3.44 | 3.20 | 2.24 | 2.93 | 0.53 | ||||||||||||||||||||||||||||||
Dividends declared per common share | 2.25 | 2.11 | 1.97 | 1.83 | 1.75 | 2.80 | 2.59 | 2.40 | 2.25 | 2.11 | ||||||||||||||||||||||||||||||
Total assets | 50,096 | 46,838 | 45,614 | 42,817 | 42,554 | 71,610 | 58,648 | 54,186 | 49,963 | 46,711 | ||||||||||||||||||||||||||||||
Long-term debt | 19,330 | 16,851 | 17,394 | 15,758 | 15,481 | 30,231 | 23,468 | 21,665 | 19,199 | 16,736 |
(1) | Includes a $122 millionafter-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities. |
(2) | Includes $248 million ofafter-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 millionafter-tax charge related to Dominion’s restructuring of its producer services business and a $174 millionafter-tax charge associated with the Liability Management Exercise. |
(3) | Includes a $109 millionafter-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 millionafter-tax net loss from the discontinued operations of Brayton Point and Kincaid. |
(4) | Includes a $1.1 billionafter-tax loss from discontinued operations, including impairment charges, of Brayton Point and Kincaid and a $303 millionafter-tax charge primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013. |
(5) | Amounts attributable to Dominion’s common shareholders. |
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.
(6) | As discussed in Note 2 to the Consolidated Financial Statements, prior period amounts have been reclassified to conform to the 2016 presentation. |
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:
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FORWARD-L-OOKINGLOOKING 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:
Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; |
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Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities; Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations; Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances; Cost of environmental compliance, including those costs related to climate change; Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals; Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities; Unplanned outages at facilities in which the Companies have an ownership interest; Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s and Dominion Gas’ earnings and the Companies’ liquidity position and the underlying value of their assets; Counterparty credit and performance risk; Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants; Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion and Dominion Gas; Fluctuations in interest rates or foreign currency exchange rates; Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; Changes in financial or regulatory accounting principles or policies imposed by governing bodies; Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; Risks of operating businesses in regulated industries that are subject to changing regulatory structures; Impacts of acquisitions, including the recently completed Dominion Questar Combination, divestitures, transfers of assets to joint ventures or Dominion Midstream, including the recently completed contribution of Questar Pipeline to Dominion Midstream, and retirements of assets based on asset portfolio reviews; Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; The timing and execution of Dominion Midstream’s growth strategy; 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; Political and economic conditions, including inflation and deflation; Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity; Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion and Dominion Gas’ pipeline and processing systems, failure to maintain or replace customer
Additional competition in industries in which the Companies operate, including in electric markets in which Dominion’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers; Competition in the development, construction and ownership of certain electric transmission facilities in Virginia Power’s service territory in connection with FERC Order 1000; Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies; Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion and Dominion Gas; Changes in operating, maintenance and construction costs; Timing and receipt of regulatory approvals necessary for planned construction or expansion projects and compliance with conditions associated with such regulatory approvals; The inability to complete planned construction, conversion or expansion projects at all, or with the outcomes or within the terms and time frames initially anticipated; Adverse outcomes in litigation matters or regulatory proceedings; and The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events. Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors. The Companies’ forward-looking statements are based on beliefs and assumptions using information available at the time the statements are made. The Companies caution the reader not to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. The Companies undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.
ACCOUNTING MATTERS Critical Accounting Policies and Estimates Dominion ACCOUNTINGFOR REGULATED OPERATIONS The accounting for
ASSET RETIREMENT OBLIGATIONS Dominion ARO liability with such changes recognized in income. In
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued AROs as an adjustment to A significant portion of
INCOME TAXES Judgment and the use of estimates are required in developing the provision for income taxes and reporting oftax-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 totax-related assets and liabilities could be material.
Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy amore-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, 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 realized. At December 31, ACCOUNTINGFOR DERIVATIVE CONTRACTSAND OTHER INSTRUMENTS A Dominion Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, future price information and use of statistical methods, including regression analysis, that reflect
USEOF ESTIMATESIN GOODWILL IMPAIRMENT TESTING As of December 31, 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 wouldmore-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 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 Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about operating the long-lived assets and the 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,
Expected inflation and risk-free interest rate assumptions; Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes; Expected future risk premiums, asset volatilities and correlations; Forecasts of an independent investment advisor; Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; and Investment allocation of plan assets. The strategic target asset allocation for Dominion’s pension funds is 28% U.S. equity, 18%non-U.S. equity, 35% fixed income, 3% real estate and 16% 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 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 2.87% to 4.99% for pension plans and 3.56% to 4.94% for other postretirement benefit plans in 2016, were 4.40%
Management’s Discussion and ranged from 5.20% to 5.30% 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, Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate. During 2016, Dominion conducted a new experience study as scheduled and, as a result, updated its mortality assumptions. The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed, while holding all other assumptions constant:
In addition to the effects on cost, at December 31, See Note 21 to the Consolidated Financial Statements for additional
Dominion RESULTSOF OPERATIONS Presented below is a summary of Dominion’s consolidated results:
Overview 2016VS. 2015 Net income attributable to Dominion increased 12%, primarily due to higher renewable energy investment tax credits and the new PJM capacity performance market effective June 2016. These increases were partially offset by a decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields and charges related to future ash pond and landfill closure costs at certain utility generation facilities. 2015VS. 2014 Net income attributable to Dominion increased 45%, primarily due to the absence of 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, the absence of losses related to the repositioning of Dominion’s producer services business in the first quarter of 2014, and the absence of charges related to Dominion’s Liability Management Exercise. See Note 13 to the Consolidated Financial Statements for more information on legislation related to North Anna and offshore wind facilities. SeeLiquidity and Capital Resources for more information on the Liability Management Exercise. Analysis of Consolidated Operations Presented below are selected amounts related to Dominion’s results of operations:
An analysis of Dominion’s results of operations follows: 2016VS. 2015 Net revenue increased 10%, primarily reflecting: A $544 million increase from electric utility operations, primarily reflecting: A $225 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($155 million) and the expiration ofnon-utility generator contracts in 2015 ($58 million); An increase from rate adjustment clauses ($183 million); and The A $305 million increase due to the Dominion Questar Combination. These increases were partially offset by: A $47 million decrease from merchant generation operations, primarily due to lower realized prices at certain merchant generation facilities ($64 million) and an increase in planned and unplanned outage days in 2016 ($26 million), partially offset by additional solar generating facilities placed into service ($37 million); A $19 million decrease from regulated natural gas transmission operations, primarily due to: A $14 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by expansion projects placed in service ($18 million) and increased regulated gas sales ($20 million); and A $17 million decrease in NGL activities, due to decreased prices ($15 million) and volumes ($2 million); partially offset by A $12 million increase in other revenues, primarily due to an increase in services performed for Atlantic Coast Pipeline ($21 million), partially offset by decreased amortization of deferred revenue associated with conveyed shale development rights ($4 million); and A $12 million decrease from regulated natural gas distribution operations, primarily due to a decrease in rate adjustment clause revenue related to low income assistance programs ($26 million) and a decrease in sales to Other operations and maintenance increased 18%, primarily reflecting: A $148 million increase due to the Dominion Questar Combination, including $58 million of transaction and transition costs; A $98 million increase in charges related to future ash pond and landfill closure costs at certain utility generation facilities; A $78 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields; Organizational design initiative costs ($64 million); A $50 million increase in storm damage and service restoration costs, including $23 million for Hurricane Matthew; A $20 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income; and A $16 million increase due to labor contract renegotiations as well as costs resulting from a union workforce temporary work stoppage; partially offset by A $26 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 do not impact net income. Depreciation, depletion and amortizationincreased 12%, primarily due to various expansion projects being placed into service. Other incomeincreased 28%, primarily due to an increase in earnings from equity method investments ($55 million) and an increase in AFUDC associated with rate-regulated projects ($12 million), partially offset by lower realized gains (net of investment income) on nuclear decommissioning trust funds ($19 million). Interest and related chargesincreased 12%, primarily due to higher long-term debt interest expense resulting from debt issuances in 2016 ($134 million), partially offset by an increase in capitalized interest associated with the Cove Point Liquefaction Project ($45 million). Income tax expense decreased 28%, primarily due to higher renewable energy investment tax credits ($189 million) and the impact of a state legislative change ($14 million), partially offset by higherpre-tax income ($15 million). 2015VS. 2014 Net revenue increased 10%, primarily reflecting: The absence of losses related to the repositioning of Dominion’s producer services business in the first quarter of 2014, reflecting the termination of natural gas trading and certain energy marketing activities ($313 million); A $159 million increase from electric utility operations, primarily reflecting: An increase from rate adjustment clauses ($225 million); An increase in sales to retail customers, primarily due to a net increase in cooling degree days ($38 million); and A decrease in capacity related expenses ($33 million); partially offset by An $85 millionwrite-off of deferred fuel costs associated with Virginia legislation enacted in February 2015; A decrease in sales to customers due to the effect of changes in customer usage and other factors ($24 million); and A decrease due to a charge based on the The absence of A $77 million increase from merchant generation operations, primarily due to
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
A $38 million increase from regulated natural gas distribution operations, primarily due to an increase in A $30 million increase from regulated natural gas transmission operations, primarily reflecting: A $61 million increase in gas transportation and
A $46 million net increase primarily due to services performed for Atlantic Coast Pipeline and Blue Racer; partially offset by Other operations and maintenance decreased
The absence of 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 ($370 million); An increase in gains from agreements to convey shale development rights underneath several natural gas storage fields ($63 million); A $97 million decrease in planned outage costs primarily due to a decrease in scheduled outage days at certain merchant generation facilities ($59 million) andnon-nuclear utility generation facilities ($38 million); and A $22 million decrease in charges related to future ash pond and landfill closure costs at certain utility generation facilities. These decreases were partially offset by:
An $80 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income; The absence of gains on the sale of assets to Blue Racer ($59 million); A $53 million increase in utility nuclear refueling outage costs primarily due to the amortization of outage costs that were previously deferred pursuant to Virginia legislation enacted in April 2014; A $46 million net increase due to services performed for Atlantic Coast Pipeline and Blue Racer. These expenses are billed to these entities and do not significantly impact net income; and A $22 million increase due to the acquisition of DCG. Other incomedecreased 22%, primarily reflecting lower tax recoveries associated with contributions in aid of construction ($17 million), a decrease in Interest and related chargesdecreased 24%, primarily as a result of the absence of charges associated with Dominion’s Liability Management Exercise in 2014. Income tax expense increased
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 Dominion’s 2017 net income is expected to remain substantially consistent on a per share basis as compared to 2016. Dominion’s 2017 results are expected to be positively impacted by the following: Decreased charges related to future ash pond and landfill closure costs at certain utility generation facilities; The inclusion of operations acquired from Dominion Questar for the entire year; Decreased transaction and transition costs associated with the Dominion Questar Combination; Growth in weather-normalized electric utility sales of approximately 1%; Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue; and Construction and operation of growth projects in gas transmission and distribution. Dominion’s 2017 results are expected to be negatively impacted by the following: Lower power prices and an additional planned refueling outage at Millstone; Decreased Cove Point import contract revenues; An increase in depreciation, depletion, and amortization; A higher effective tax rate, driven primarily by a decrease in investment tax credits; and Share dilution. Additionally, in 2017, Dominion expects to focus on meeting new and developing environmental requirements, including making investments in utility-scale solar generation, particularly in Virginia. In
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:
DVP Presented below are operating statistics related to DVP’s operations:
Presented below, on anafter-tax basis, are the key factors impacting DVP’s net income contribution:
Dominion Generation Presented below are operating statistics related to Dominion Generation’s operations:
Presented below, on anafter-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued Dominion Energy Presented below are selected operating statistics related to Dominion Energy’s operations.
Presented below, on anafter-tax basis, are the key factors impacting Dominion Energy’s net income contribution:
2015VS. 2014
Corporate and Other Presented below are the Corporate and Other segment’safter-tax results:
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 VIRGINIA POWER RESULTSOF OPERATIONS Presented below is a summary of Virginia Power’s consolidated results:
Overview 2016VS. 2015 Net income increased 12%, primarily due to the new PJM capacity performance market effective June 2016, an increase in rate adjustment clause revenue and the absence of awrite-off of deferred fuel costs associated with the Virginia legislation enacted in February 2015. These increases were partially offset by charges related to future ash pond and landfill closure costs at certain utility generation facilities. 2015VS. 2014 Net income increased 27%, primarily due to the absence of 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.
Analysis of Consolidated Operations Presented below are selected amounts related to Virginia Power’s results of operations:
An analysis of Virginia Power’s results of operations follows: 2016VS. 2015 Net revenue increased 11%, primarily reflecting: A $225 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($155 million) and the expiration ofnon-utility generator contracts in 2015 ($58 million); An increase from rate adjustment clauses ($183 million); and The absence of an $85 millionwrite-off of deferred fuel costs associated with Virginia legislation enacted in February 2015. Other operations and maintenance increased 14%, primarily reflecting: A $98 million increase in charges related to future ash pond and landfill closure costs at certain utility generation facilities; A $50 million increase in storm damage and service restoration costs, including $23 million for Hurricane Matthew; A $37 million increase in salaries, wages and benefits and general administrative expenses; and Organizational design initiative costs ($32 million). Income tax expenseincreased 10%, primarily reflecting higherpre-tax income. 2015VS. 2014 Net revenue increased 3%, primarily reflecting: An increase from rate adjustment clauses ($225 million); An increase in sales to retail customers, primarily due to a net increase in cooling degree days ($38 million); and A decrease in capacity related expenses ($33 million); partially offset by An $85 millionwrite-off of deferred fuel costs associated with Virginia legislation enacted in February 2015; A decrease in sales to customers due to the effect of changes in customer usage and other factors ($24 million); and A decrease due to a charge based on the 2015 Biennial Review Order to refund revenues to customers ($20 million). Other operations and maintenance decreased 15%, primarily reflecting: The absence of $370 million in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities; and A $38 million decrease in planned outage costs primarily due to a decrease in scheduled outage days at certainnon-nuclear utility generation facilities. These decreases were partially offset by: An $80 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income; and A $53 million increase in utility nuclear refueling outage costs primarily due to the amortization of outage costs that were previously deferred pursuant to Virginia legislation enacted in April 2014. Other incomedecreased 27%, primarily reflecting lower tax recoveries associated with contributions in aid of construction. Income tax expenseincreased 20%, primarily reflecting higherpre-tax income. DOMINION GAS RESULTSOF OPERATIONS Presented below is a summary of Dominion Gas’ consolidated results:
Overview 2016VS. 2015 Net income decreased 14%, primarily due a decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields. 2015VS. 2014 Net income decreased 11%, primarily due to the absence of gains on the indirect sale of assets to Blue Racer, a decrease in income from NGL activities and higher interest expense, partially offset by increased gains from agreements to convey shale development rights underneath several natural gas storage fields.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Analysis of Consolidated Operations Presented below are selected amounts related to
An analysis of
Net
A $34 million decrease from regulated natural gas transmission operations, primarily reflecting: A $36 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($28 million), increased fuel costs ($13 million), contract rate changes ($11 million) and decreased revenue from gathering and extraction services ($8 million), partially offset by increased regulated gas sales ($16 million) and expansion projects placed in service ($9 million); and An $18 million decrease from NGL activities, due to decreased prices ($16 million) and volumes ($2 million); partially offset by A $21 million increase in services performed for Atlantic Coast Pipeline; and A $12 million decrease from regulated natural gas distribution operations, primarily reflecting: A decrease in rate adjustment clause revenue related to low income assistance programs ($26 million); and A $9 million decrease in other revenue primarily due to a decrease in pooling and metering activities ($3 million), a decrease in Blue Racer management fees ($3 million) and a decrease in gathering activities ($2 million); partially offset by An $18 million increase in AMR and PIR program revenues; and An $8 million increase inoff-system sales. Other operations and maintenance increased 22%, primarily reflecting: A $78 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields; and A $20 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income; partially offset by A $26 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 do not impact net income. Other incomeincreased $10 million, primarily due to a gain on the sale of 0.65% of the noncontrolling partnership interest in Iroquois ($5 million) and an increase in AFUDC associated with rate-regulated projects ($5 million). Interest and related chargesincreased 29%, primarily due to higher interest expense resulting from the issuances of senior notes in November 2015 and the second quarter of 2016 ($28 million), partially offset by an increase in deferred rate adjustment clause interest expense ($7 million). Income tax expensedecreased 24% primarily reflecting lowerpre-tax income. 2015VS. 2014 Net revenue increased 1%, primarily reflecting:
A $43 million increase from regulated natural gas distribution operations, primarily due to an increase in AMR and PIR program revenues ($24 million) and various expansion projects placed into service ($22 million); partially offset
A $27 million decrease from regulated natural gas transmission operations, primarily reflecting: A $62 million decrease from NGL activities, primarily due to decreased prices; partially offset by A $2 million increase in gas transportation and storage activities, primarily due to decreased fuel costs ($24 million) and various expansion projects placed into service ($24 million), partially offset by decreased regulated gas sales ($46 million); and A $33 million net increase in other revenue primarily due to services performed for Atlantic Coast Pipeline and Blue Racer ($47 million), partially offset by a decrease innon-regulated
Other operations and maintenance
Interest and related chargesincreased Income tax expense
LIQUIDITYAND CAPITAL RESOURCES Dominion At December 31, A summary of Dominion’s cash flows is presented below:
Operating Cash Flows
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
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,
Investing Cash Flows
Financing Cash Flows and Liquidity Dominion
Net cash provided by Dominion’s financing activities increased $3.9 billion, primarily reflecting higher net debt issuances and higher issuances of common stock and Dominion Midstream common and convertible preferred units in connection with the Dominion Questar Combination.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
During 2014, Dominion elected to
CREDIT FACILITIESAND SHORT Dominion In connection with commodity hedging activities,
Dominion Questar’s revolving multi-year and
SHORT-TERM NOTES In November In In September 2016, Dominion borrowed $1.2 billion under a term loan agreement that bore interest at a variable rate. The net proceeds were used to finance the Dominion Questar Combination. In December 2016, the loan was repaid with cash received from Dominion Midstream in connection with the contribution of Questar Pipeline. The loan would have otherwise matured in September 2017. See Note 3 to the Consolidated Financial Statements for more information. LONG-TERM DEBT During 2016, Dominion issued
During 2016, Dominion also issued the following long-term private debt: In February 2016, Dominion issued $500 million of 2.125% senior notes in a private placement. The notes mature in 2018. The proceeds were used to repay or repurchase short-term debt, including commercial paper and short-term notes, and for general corporate purposes. In May 2016, Dominion Gas issued $150 million of private placement
In September 2016, Dominion issued $300 million of private placement 1.50% senior notes that mature in 2018. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper. In December 2016, Questar Gas issued $50 million of 3.62% private placement senior notes, and $50 million of 3.67% private placement senior notes, that mature in 2046 and 2051, respectively. The proceeds were used for general corporate purposes. In December 2016, Dominion issued $250 million of private placement 1.875% senior notes that mature in 2018. The proceeds were used for general corporate purposes and to repay short-term debt, including commercial paper. During
In March 2016 and May 2016, Dominion successfully remarketed the $550 million 2013 Series A 1.07% RSNs due 2021 and the $550 million 2013 Series B 1.18% RSNs due 2019, respectively, pursuant to the terms of the related 2013 Equity Units. In connection with the remarketings, the interest rates on the Series A and Series B junior subordinated notes were reset to 4.104% and 2.962%, respectively. Dominion did not receive any proceeds from the remarketings. See Note 17 to the Consolidated Financial Statements for more information. In December 2016, Virginia Power
During 2016, Dominion also borrowed the following under term loan agreements: In December 2016, Dominion Midstream borrowed $300 million under a term loan agreement that matures in
In December 2016, SBL Holdco borrowed $405 million under a term loan agreement
During 2016, Dominion repaid $1.8 billion of short-term notes and repaid and repurchased In January 2017, Dominion issued $400 million of 1.875% senior notes and $400 million of 2.75% senior notes 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 During
In During 2017, Dominion plans to issue shares for employee savings plans, direct stock purchase
REPURCHASEOF COMMON STOCK Dominion did not repurchase any shares in
ACQUISITIONOF DOMINION QUESTAR In accordance with the terms of the Dominion Questar Combination, at closing, each share of issued and outstanding Dominion Questar common stock was converted into the right to receive $25.00 per share in cash. The total consideration was $4.4 billion based on 175.5 million shares of Dominion Questar outstanding at closing. Dominion also acquired Dominion Questar’s outstanding debt of approximately $1.5 billion. Dominion financed the Dominion Questar Combination through the: (1) August 2016 issuance of $1.4 billion of 2016 Equity Units, (2) August
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued 2016 issuance of $1.3 billion of senior notes, (3) September 2016 borrowing of $1.2 billion under a term loan agreement, which was repaid with cash received from Dominion
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold
securities. Dominion 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 In In March 2016, Fitch and Standard & Poor’s changed the rating for Dominion’s Credit ratings as of February
As of February A downgrade in an individual company’s credit rating Debt Covenants As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion 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 Some of the typical covenants include:
The timely payment of principal and interest; Information requirements, including submitting financial reports filed with the SEC and information about changes in Dominion’s credit ratings to lenders; Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation and restrictions on disposition of all or substantially all assets; Compliance with collateral minimums or requirements related to mortgage bonds; and Limitations on liens. Dominion As of December 31,
If Dominion or Dominion executed RCCs in connection with its issuance of the following hybrid securities:
June 2006 hybrids; September 2006 hybrids; and 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,
Dominion
Dividend Restrictions
Certain agreements associated with Dominion’s 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 and contract adjustment payments on certain junior subordinated notes and equity units, initially in the form of corporate units, which information is incorporated herein by reference. Future Cash Payments for Contractual Obligations and Planned Capital Expenditures CONTRACTUAL OBLIGATIONS Dominion 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
PLANNED CAPITAL EXPENDITURES Dominion’s planned capital expenditures are expected to total approximately
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion
These estimates are based on a capital expenditures plan reviewed and endorsed by Dominion’s Board of Directors in late Use ofOff-Balance Sheet Arrangements LEASING ARRANGEMENT In July 2016, Dominion signed an agreement with a lessor to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $365 million, to fund the estimated project costs. The project is expected to be completed bymid-2019. Dominion has been appointed to act as the construction agent for the lessor, during which time Dominion will request cash draws from the lessor and debt investors to fund all project costs, which totaled $46 million as of December 31, 2016. If the project is terminated under certain events of default, Dominion could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion could be required to pay up to 100% of the then funded amount. The five-year lease term will commence once construction is substantially complete and the facility is able to be occupied. At the end of the initial lease term, Dominion can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion may be required to make a payment to the lessor, up to 87% of project costs, for the difference between the project costs and sale proceeds. The respective transactions have been structured so that Dominion is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. The financial accounting treatment of the lease agreement will be impacted by the new accounting standard issued in February 2016. See Note 2 to the Consolidated Financial Statements for additional information. Dominion will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense. GUARANTEES Dominion primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not ject 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. Environmental Matters Dominion ENVIRONMENTAL PROTECTIONAND MONITORING EXPENDITURES Dominion incurred
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 In August 2015, the EPA issued final carbon standards for existing fossil fuel power plants. Known as the Clean Power Plan, the rule 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 and expanding renewable resources. The new rule requires states to impose standards of performance limits for existing fossil fuel-fired electric generating units or equivalent statewide intensity-based or mass-based CO2 binding goals or limits. States are required to submit final plans identifying how they will comply with the rule by September 2018. The EPA also issued a proposed federal plan and model trading rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. Virginia Power’s most recent integrated resources plan filed in April 2016 includes four
alternative plans that represent plausible compliance strategies with the rule as proposed, and which include additional coal unit retirements and additional low orzero-carbon resources. The final rule has been challenged in the U.S. Court of Appeals for the D.C. Circuit. In February 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan until the disposition of the petitions challenging the rule now before the Court of Appeals, and, if such petitions are filed in the future, before the U.S. Supreme Court. Dominion does not know whether these legal challenges will impact the submittal deadlines for the state implementation plans. In June 2016, the Governor of Virginia signed an executive order directing the Virginia Natural Resources Secretary to convene a workgroup charged with recommending concrete steps to reduce carbon pollution which include the Clean Power Plan as an option. Unless the rule survives the court challenges and 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 December 2012, the EPA issued a final rule that set a more stringent annual air quality standard for fine particulate matter. The EPA The EPA has finalized rules establishing a new1-hour NAAQS for NO2 and a new1-hour NAAQS for SO2, which could require additional NOX and SO2 controls in certain areas where Climate Change In A key element of the In March 2016, as part of its Climate Action Plan, the EPA began development of regulations for reducing methane emissions from existing sources in the oil and natural gas sectors. In November 2016, the EPA issued an Information Collection Request to collect information on existing sources upstream of local distribution companies in this
PHMSA Regulation The most recent reauthorization of PHMSA included new provisions on historical records research, maximum-allowed operating pressure validation, use of automated or remote-controlled valves on new or replaced lines, increased civil penalties and evaluation of expanding integrity management beyond high-consequence areas. PHMSA has not yet issued new rulemaking on most of these items. Legal Matters Collective Bargaining Agreement In
Dodd-Frank Act The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The CEA, as amended by Title VII of the Dodd-Frank Act,
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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
MARKET RISK SENSITIVE INSTRUMENTSAND RISK MANAGEMENT
Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt and future issuances of debt. In addition, The 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% Commodity Price Risk To manage price risk, Dominion and Virginia Power 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% A hypothetical 10% decrease in commodity prices would have resulted in a decrease in the fair value of $62 million and $42 million of Virginia Power’s commodity-based derivative instruments as of December 31, 2016 and December 31, 2015, respectively. The increase in sensitivity is largely due to an increase in commodity derivative activity and higher commodity prices. A hypothetical 10% increase in commodity prices of Dominion Gas’ commodity-based financial derivative instruments would have resulted in a decrease in fair value of $4 million and $5 million as of December 31,
The impact of a change in energy commodity prices on Interest Rate Risk
agreements. For variable rate debt and interest rate swaps designated under fair value hedging and outstanding for
In June 2016, Dominion Gas entered into foreign currency swaps with the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of December 31, The impact of a change in interest rates on 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 Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of 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. Risk Management Policies
Item 8. Financial Statements and Supplementary Data
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, 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, 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, /s/ Deloitte & Touche LLP Richmond, Virginia February
Consolidated Statements of
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Consolidated
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Consolidated Balance Sheets
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Consolidated Statements of Equity
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements
Consolidated Statements of Cash Flows
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, 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, /s/ Deloitte & Touche LLP Richmond, Virginia February
Virginia Electric and Power Company Consolidated Statements of Income
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company Consolidated Balance Sheets
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
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company Consolidated Statements of Cash Flows
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
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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, 2016 and 2015, 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, 2016. These financial statements are the responsibility of Dominion Gas’ management. Our responsibility is to express an opinion on the 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Richmond, Virginia February 28, 2017
Consolidated Statements of Income
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
Consolidated Balance Sheets
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
Consolidated Statements of Equity
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
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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 Dominion’s operations also include the Cove Point LNG import, transport and storage facility in Maryland, an equity investment in Atlantic Coast Pipeline and regulated gas transportation and distribution operations in 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. Dominion received $392 million in net proceeds from the 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) 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 in allocating resources. 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 or in allocating resources See Note 25 for further discussion of
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES General
subsidiaries and
Dominion maintains pension and other postretirement benefit plans. Virginia Power Certain amounts in the 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.
Combined Notes to Consolidated Financial Statements, Continued customers. Virginia Power’s customer receivables at December 31, The primary types of sales and service activities reported as operating revenue for Dominion are as follows:
Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity; Regulated gas sales consist primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity; Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity; Gas transportation and storage consists primarily of FERC-regulated sales of transmission and storage services. Also included are state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; and Other revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes miscellaneous service revenue from electric and gas distribution operations, sales of energy-related products and services from Dominion’s retail energy marketing operations and gas processing and handling revenue. The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:
Other revenue consists primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities. The primary types of sales and service activities reported as operating revenue for Dominion Gas are as follows: Regulated gas sales consist primarily of state- and FERC-regulated natural gas sales and related distribution services; Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices and sales of gas purchased from third parties. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties; Gas transportation and storage consists primarily of FERC- regulated sales of transmission and storage services. Also included are state-regulated gas distribution charges to retail
NGL revenueconsists primarily of sales of NGL production and condensate, extracted products and associated derivative activity; and Other revenue consists primarily of miscellaneous service revenue, gas processing and handling revenue. Electric Fuel, Purchased Energy and PurchasedGas-Deferred Costs Where permitted by regulatory authorities, the differences between Dominion’s and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion’s and Dominion Gas’ purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability. Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 84% is currently subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms. Virtually all of Dominion Gas’, Cove Point’s, Questar Gas’ and Hope’s natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale. Income Taxes A consolidated federal income tax return is filed for Dominion and its subsidiaries, including Virginia Although Dominion Gas is disregarded for income tax purposes, a provision for income taxes is recognized to reflect the inclusion of its business activities in the tax returns of its parent, Dominion. Virginia Power Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized. Effective January 2016, deferred tax liabilities and assets are classified as noncurrent in the Consolidated Balance Sheets. For prior years, the Companies presented deferred taxes in either the current or noncurrent sections of the Consolidated Balance Sheets based on the classification of the related financial accounting assets or liabilities, or, for items such as operating loss carryforwards, the period in which the deferred taxes were expected to reverse. Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided,
representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes.
If it is notmore-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the payables are included in accrued interest, payroll and taxes on the
Dominion’s, Virginia Power’s and Dominion
At December 31, In addition, Virginia Power’s Consolidated Balance Sheet at December 31, 2016 included $2 million of noncurrent federal income taxes payable, $6 million of state income taxes receivable and $13 million of noncurrent state income taxes receivable. Dominion Gas’ Consolidated Balance Sheet at December 31, 2016 included $1 million of noncurrent federal income taxes payable, $1 million of state income taxes receivable and $7 million of noncurrent state income taxes payable. At December 31, 2015, Virginia Power’s Consolidated Balance Sheet included current state income taxes payable. In March 2016, Virginia Power received a $300 million refund of its 2015 income tax payments. At December 31, Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold. Cash and Cash Equivalents Current banking arrangements generally do not require checks to be funded until they are presented for payment.
For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less. Derivative Instruments Dominion
All derivatives,
Combined Notes to Consolidated Financial Statements, Continued The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion had margin assets of To manage price risk, offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity Statement of Income Presentation:
Derivatives Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis. Derivatives Not Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses, interest and related charges or other income based on the nature of the underlying risk.
DERIVATIVE INSTRUMENTS DESIGNATEDAS HEDGING INSTRUMENTS
such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows. Cash Flow Hedges Dominion entered into interest rate derivative instruments to hedge its forecasted interest payments related to planned debt issuances in 2014. These interest rate derivatives were designated by Dominion as cash flow hedges prior to the formation of Dominion Gas. For the purposes of the Dominion Gas financial statements, the derivative balances, AOCI balance, and any income statement impact related to these interest rate derivative instruments entered into by Dominion have been, and will continue to be, included in the Dominion Gas’ Consolidated Financial Statements as the forecasted interest payments related to the debt issuances now occur at Dominion Gas. Fair Value Hedges See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives. Property, Plant and Equipment Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject tocost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred. In
2014, Virginia Power capitalized AFUDC to property, plant and equipment of Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In For property subject tocost-of-service rate regulation, including Virginia Power electric distribution, electric transmission, and generation property, Dominion Gas natural gas distribution and transmission property, and for certain Dominion natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject tocost-of-service rate regulation that will be For Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives.
In 2014, Virginia Power made aone-time adjustment to depreciation expense as ordered by the Virginia Commission. This adjustment resulted in an increase of $38 million ($23 millionafter-tax) in depreciation and amortization expense in Virginia Power’s Consolidated Statements of Income. Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved gas and oil reserves, at a rate of $2.08 per mcfe in 2016. Dominion’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:
Depreciation and amortization related to Virginia Power’s and Dominion Gas’ nonutility property, plant and equipment and exploration and production properties was immaterial for the years ended December 31, 2016, 2015 and 2014, except for Dominion Gas’ nonutility gas gathering and processing properties which are depreciated using the straight-line method over estimated useful lives between 10 and 50 years. Nuclear fuel used in electric generation is amortized over its estimated service life on aunits-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows. Long-Lived and Intangible Assets
Regulatory Assets and Liabilities The accounting for Dominion’s and Dominion Gas’ regulated gas and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or statecost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator. The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions, legislation or historical experience, as well as discussions
Combined Notes to Consolidated Financial Statements, Continued with applicable regulatory Asset Retirement Obligations
relevant market information is not available, fair value is estimated using discounted cash flow analyses.
Investments MARKETABLE EQUITYAND DEBT SECURITIES Dominion accounts for and classifies investments in marketable equity and debt securities as trading oravailable-for-sale securities. Virginia Power classifies investments in marketable equity and debt securities asavailable-for-sale securities.
In determining realized gains and losses for marketable equity and debt securities, the cost basis of the security is based on the specific identification method. NON-MARKETABLE INVESTMENTS
OTHER Dominion and Virginia Power periodically review their investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period. Decommissioning Trust Investments—Special Considerations The recognition provisions of the FASB’s other-than-temporary impairment guidance apply only to debt securities classified asavailable-for-sale orheld-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities.
Inventories Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory Gas Imbalances Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion Goodwill Dominion New Accounting Standards REVENUE RECOGNITION In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. The core principle of this revised accounting guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amendments in this update also require disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For the Companies, the revised accounting guidance is effective for interim and annual periods beginning January 1, 2018. The Companies have completed their preliminary evaluations of the impact of this guidance and, pending evaluation of the items discussed below, expect no significant impact on their results of operations. Now that their preliminary evaluations are complete, the Companies will expand the scope of their assessment to include all contracts with customers. In addition, the Companies are considering certain issues that could potentially change the accounting for certain transactions. Among the issues being considered are accounting for contributions in aid of construction, recognition of revenue when collectability is in question, recognition of revenue in contracts with variable consideration, accounting for alternative revenue programs, and the capitalization of costs to acquire new contracts. The Companies plan on applying the standard using the modified retrospective method as opposed to the full retrospective method. FINANCIAL INSTRUMENTS In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. Most notably the update revises the accounting for equity securities, except for those accounted for under the equity method of accounting or resulting in consolidation, by requiring equity securities to be measured at fair value with the changes in fair value recognized in net income. However, an entity may measure equity investments that do not have a readily determinable fair value at cost minus impairment, if any, plus changes from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. The guidance also simplifies the impairment assessment of equity investments without readily determinable fair values, revises the presentation of financial assets and liabilities and amends certain disclosure requirements associated with the fair value of financial instruments. The guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, with a cumulative-effect adjustment to the balance sheet. Amendments related to equity securities without readily determinable fair values are to be applied prospectively to such investments that exist as of the date of adoption. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on equity securities subject to cost-based regulation will not be impacted by the adoption of this standard. For all other available for sale equity securities, unrealized gains and losses currently recorded through other comprehensive income will be recognized in net income upon the adoption of this standard.
Combined Notes to Consolidated Financial Statements, Continued
LEASES In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged. The guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2019, although it can be early adopted, with a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented for leases that commenced prior to the date of adoption. The Companies are currently in the preliminary stages of evaluating the impact of this guidance on their financial position and plan to complete their initial assessment in 2017. The Companies expect to elect the practical expedients, which would require no reassessment of whether existing contracts are or contain leases as well as no reassessment of lease classification for existing leases. While the Companies cannot quantify the impact until their assessment is complete, the Companies believe the adoption could have a material impact to the Companies’ financial position. DERECOGNITIONAND PARTIAL SALESOF NONFINANCIAL ASSETS In February 2017, the FASB issued revised accounting guidance clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The guidance is effective for Dominion’s interim and annual reporting periods beginning January 1, 2018, and Dominion may elect to apply the update under the full retrospective method or the modified retrospective method. Dominion is currently evaluating the impacts of the revised accounting guidance on its consolidated financial statements and disclosures. NOTE 3. ACQUISITIONSANDDISPOSITIONS DOMINION ACQUISITIONOF DOMINION QUESTAR In September 2016, Dominion completed the Dominion Questar Combination and Dominion Questar became a wholly-owned subsidiary of Dominion. Dominion Questar, a Rockies-based integrated natural gas company, included Questar Gas, Wexpro and Questar Pipeline at closing. Questar Gas has regulated gas distribution operations in Utah, southwestern Wyoming and southeastern Idaho. Wexpro develops and produces natural gas from reserves supplied to Questar Gas under a cost-of-service framework. Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage services in Utah, Wyoming and western Colorado. The Dominion Questar Combination provides Dominion with pipeline infrastructure that provides a principal source of gas supply to Western states. Dominion Questar’s regulated businesses also provide further balance between Dominion’s electric and gas operations. In accordance with the terms of the Dominion Questar Combination, at closing, each share of issued and outstanding Dominion Questar common stock was converted into the right to receive $25.00 per share in cash. The total consideration was $4.4 billion based on 175.5 million shares of Dominion Questar outstanding at closing. Dominion financed the Dominion Questar Combination through the: (1) August 2016 issuance of $1.4 billion of 2016 Equity Units, (2) August 2016 issuance of $1.3 billion of senior notes, (3) September 2016 borrowing of $1.2 billion under a term loan agreement and (4) $500 million of the proceeds from the April 2016 issuance of common stock. See Notes 17 and 19 for more information. Purchase Price Allocation Dominion Questar’s assets acquired and liabilities assumed were measured at estimated fair value at the closing date and are included in the Dominion Energy operating segment. The majority of operations acquired are subject to the rate-setting authority of FERC, as well as the Utah Commission and/or the Wyoming Commission and therefore are accounted for pursuant to ASC 980,Regulated Operations. The fair values of Dominion Questar’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts. The fair value of Dominion Questar’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions discussed above was determined using the income approach. In addition, the fair value of Dominion Questar’s 50% interest in White River Hub, accounted for under the equity method, was determined using the market approach and income approach. The valuations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future cash flows and future market prices. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill at the closing date. The goodwill reflects the value associated with enhancing Dominion’s regulated portfolio of businesses, including the expected increase in demand forlow-carbon, naturalgas-fired generation in the Western states and the expected continued growth of rate-regulated businesses located in a defined service area with a stable regulatory environment. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill.
The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at closing. The allocation is subject to change during the remainder of the measurement period, which ends one year from the closing date, as additional information is obtained about the facts and circumstances that existed at the closing date. Any material adjustments to provisional amounts identified during the measurement period will be recognized and disclosed in the reporting period in which the adjustment amounts are determined. During the fourth quarter, certain modifications were made to preliminary valuation amounts for acquired property, plant and equipment, current liabilities, and deferred income taxes, resulting in a $6 million net decrease to goodwill, which relate primarily to the sale of Questar Fueling Company in December 2016 as further described in theSale of
Regulatory Matters The transaction required approval of Dominion Questar’s shareholders, clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act and approval from both the Utah Commission and the Wyoming Commission. In February 2016, the Federal Trade Commission granted antitrust approval of the Dominion Questar Combination under the Hart-Scott-Rodino Act. In May 2016, Dominion Questar’s shareholders voted to approve the Dominion Questar Combination. In August 2016 and September 2016, approvals were granted by the Utah Commission and the Wyoming Commission, respectively. Information regarding the transaction was also provided to the Idaho Public Utilities Commission, who acknowledged the Dominion Questar Combination in October 2016, and directed Dominion Questar to notify the Idaho Public Utilities Commission when it makes filings with the Utah Commission. With the approval of the Dominion Questar Combination in Utah and Wyoming, Dominion agreed to the following: Contribution of $75 million to Dominion Questar’s qualified andnon-qualified defined-benefit pension plans and its other post-employment benefit plans within six months of the closing date. This contribution was made in January 2017. Increasing Dominion Questar’s historical level of corporate contributions to charities by $1 million per year for at least five years. Withdrawal of Questar Gas’ general rate case filed in July 2016 with the Utah Commission and agreement to not file a general rate case with the Utah Commission to adjust its base distributionnon-gas rates prior to July 2019, unless otherwise ordered by the Utah Commission. In addition, Questar Gas Results of Operations and Pro Forma Information The impact of the Dominion Questar Combination on Dominion’s operating revenue and net income attributable to Dominion in the Consolidated Statements of Income for the twelve months ended December 31, 2016 was an increase of $379 million and $73 million, respectively. Dominion incurred transaction and transition costs, of which $58 million was recorded in other operations and maintenance expense for the twelve months ended December 31, 2016, and $16 million was recorded in interest and related charges for the twelve months ended December 31, 2016, in Dominion’s Consolidated Statements of Income. These costs consist of the amortization of financing costs, the charitable contribution commitment described above, employee-related expenses, professional fees, and other miscellaneous costs. The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion assuming the Dominion Questar Combination had taken place on January 1, 2015. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.
Contribution of Questar Pipeline to Dominion Midstream In
Combined Notes to Consolidated Financial Statements, Continued all of the issued and outstanding membership interests of Questar Pipeline in exchange for consideration consisting of Dominion Midstream common and convertible preferred units with a combined value of $467 million and cash payment of $823 million, $300 million of which is considered a debt-financed distribution, for a total of $1.3 billion. In addition, under the terms of the Contribution Agreement, Dominion Midstream repurchased 6,656,839 common units from Dominion, and repaid its $301 million promissory note to Dominion in December 2016. The cash proceeds from these transactions were utilized in December 2016 to repay the $1.2 billion term loan agreement borrowed in September 2016. Since Dominion consolidates Dominion Midstream for financial reporting purposes, the trans- actions associated with the Contribution Agreement were eliminated upon consolidation. See Note 5 for the tax impacts of the transactions. Sale of Questar Fueling Company In December 2016, Dominion completed the sale of WHOLLY-OWNED MERCHANT SOLAR PROJECTS Acquisitions The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion. Long-term power purchase, interconnection and operation and maintenance agreements have been executed for all of the projects. Dominion has claimed federal investment tax credits on the projects. These projects are included in the Dominion Generation operating segment.
In addition during 2016, Dominion acquired 100% of the equity interests of seven solar projects in Virginia, North Carolina and South Carolina for an aggregate purchase price In August 2016, Dominion entered into an agreement to acquire 100% of the equity interests of two solar projects in California from Solar Frontier Americas Holding LLC for approximately $128 million in cash. The acquisition is expected to close prior to both projects commencing operations, which is expected by the end of 2017. The projects are expected to cost approximately $130 million once constructed, including the initial acquisition cost, and to generate approximately 50 MW combined. In September 2016, Dominion entered into an agreement to acquire 100% of the equity interests of a solar project in Virginia from Community Energy Solar, LLC. The acquisition is expected to close during the first quarter of 2017, prior to the project commencing operations by the end of 2017, for an amount to be determined based on the costs incurred through closing. The project is expected to cost approximately $210 million once constructed, including the initial acquisition cost, and to generate approximately 100 MW. In January 2017, Dominion entered into an agreement to acquire 100% of the equity interests of a solar project in North Carolina from Cypress Creek Renewables, LLC for $154 million in cash. The acquisition is expected to close during the second quarter of 2017, prior to the project commencing commercial operations, which is expected by the end of the third quarter of 2017. The project is expected to cost $160 million once constructed, including the initial acquisition cost, and to generate approximately 79 MW.
Sale of Interest in Merchant Solar Projects In September 2015, Dominion signed an agreement to sell a noncontrolling interest (consisting of 33% of the equity interests) in all of its then currently wholly-owned merchant solar projects, 24 solar projects totaling 425 MW, to SunEdison, including projects discussed in the table above. In December 2015, the sale of interest in 15 of the solar projects closed for $184 million with the sale of interest in the remaining projects completed in January 2016 for $117 million. Upon closing, SunEdison sold its interest in these projects to Terra Nova Renewable Partners. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion’s remaining 67% ownership in the projects upon the occurrence of certain events, none of which are expected to occur in 2017. NON-WHOLLY-OWNED MERCHANT SOLAR PROJECTS Acquisitions of Four Brothers and Three Cedars In June 2015, Dominion acquired 50% of the units in Four Brothers from SunEdison for $64 million of consideration, consisting of $2 million in cash and a $62 million payable. Dominion has no remaining obligation related to this payable as of December 31, 2016. Four Brothers operates four solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, generating 320 MW, at a cost of approximately $670 million. In September 2015, Dominion acquired 50% of the units in Three Cedars from SunEdison for $43 million of consideration, consisting of $6 million in cash and a $37 million payable. As of December 31, 2016, a $2 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Three Cedars operates three solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, generating 210 MW, at a cost of approximately $450 million. The Four Brothers and Three Cedars facilities operate under long-term power purchase, interconnection and operation and maintenance agreements. Dominion will claim 99% of the federal investment tax credits on the projects. Dominion owns 50% of the voting interests in Four Brothers and Three Cedars and has a controlling financial interest over the entities through its rights to control operations. The allocation of the $64 million purchase price for Four Brothers resulted in $89 million of property, plant and equipment and $25 million of noncontrolling interest. The allocation of the $43 million purchase price for Three Cedars resulted in $65 million of property, plant and equipment and $22 million of noncontrolling interest. The noncontrolling interest for each entity was measured at fair value using the discounted cash flow method, with the primary components of the valuation being future cash flows (both incoming and outgoing) and the discount rate. Dominion determined its discount rate based on the cost of capital a utility-scale investor would expect, as well as the cost of capital an individual project developer could achieve via a combination of nonrecourse project financing and outside equity partners. The acquired assets of Four Brothers and Three Cedars are included in the Dominion Generation operating segment. Dominion has assumed the majority of the agreements to provide administrative and support services in connection with operations and maintenance of the facilities and technical management services of the solar facilities. Costs related to services to be provided under these agreements were immaterial for the years ended December 31, 2016 and 2015. Subsequent to Dominion’s acquisition of Four Brothers and Three Cedars, SunEdison made contributions to Four Brothers and Three Cedars of $292 million in aggregate through December 31, 2016, which are reflected as noncontrolling interests in the Consolidated Balance Sheets. In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison. DOMINION MIDSTREAM ACQUISITIONOF INTERESTIN IROQUOIS In September 2015, Dominion Midstream acquired from NG and NJNR a 25.93% noncontrolling partnership interest in Iroquois, which owns and operates a416-mile, FERC-regulated natural gas transmission pipeline in New York and Connecticut. In exchange for this partnership interest, Dominion Midstream issued 8.6 million common units representing limited partnership interests in Dominion Midstream (6.8 million common units to NG for its 20.4% interest and 1.8 million common units to NJNR for its 5.53% interest). The investment was recorded at $216 million based on the value of Dominion Midstream’s common units at closing. These common units are reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. Dominion Midstream’s noncontrolling partnership interest is reflected in the Dominion Energy operating segment. In addition to this acquisition, Dominion Gas currently holds a 24.07% noncontrolling partnership interest in Iroquois. Dominion Midstream and Dominion Gas each account for their interest in Iroquois as an equity method investment. See Notes 9 and 15 for more information regarding Iroquois. ACQUISITIONOF DCG In January 2015, Dominion completed the acquisition of 100% of the equity interests of DCG from SCANA Corporation for $497 million in cash, as adjusted for working capital. DCG owns and operates nearly 1,500 miles of FERC-regulated interstate natural gas pipeline in South Carolina and southeastern Georgia. This acquisition supports Dominion’s natural gas expansion into the southeastern U.S. The allocation of the purchase price resulted in $277 million of net property, plant and equipment, $250 million of goodwill, of which approximately $225 million is expected to be deductible for income tax purposes, and $38 million of regulatory liabilities. The goodwill reflects the value associated with enhancing Dominion’s regulated gas position, economic value attributable to future expansion projects as well as increased opportunities for synergies. The acquired assets of DCG are included in the Dominion Energy operating segment. On March 24, 2015, DCG converted to a limited liability company under the laws of South Carolina and changed its name from Carolina Gas Transmission Corporation to DCG. On April 1, 2015, Dominion contributed 100% of the issued and
Combined Notes to Consolidated Financial Statements, Continued outstanding membership interests of DCG to Dominion Midstream in exchange for total consideration of $501 million, as adjusted for working capital. Total consideration to Dominion consisted of the issuance of atwo-year, $301 million senior unsecured promissory note payable by Dominion Midstream at an annual interest rate of 0.6%, and 5,112,139 common units, valued at $200 million, representing limited partner interests in Dominion Midstream. The number of units was based on the volume weighted average trading price of Dominion Midstream’s common units for the ten trading days prior to April 1, 2015, or $39.12 per unit. Since Dominion consolidates Dominion Midstream for financial reporting purposes, this transaction was eliminated upon consolidation and did not impact Dominion’s financial position or cash flows. SALEOF ELECTRIC RETAIL ENERGY MARKETING BUSINESS In March 2014, Dominion completed the sale of its electric retail energy marketing business. The proceeds were $187 million, net of transaction costs. The sale resulted in a gain, subject to post-closing adjustments, of
ACQUISITIONOF SOLAR PROJECT In extend for an additional ten years. In October 2015, the
Dominion and BLUE RACER See Note
shale development rights.
NOTE 4. OPERATING REVENUE
NOTE 5. INCOME TAXES Judgment and the use of estimates are required in developing the provision for income taxes and reporting oftax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently.
Continuing Operations Details of income tax expense for continuing operations including noncontrolling interests were as follows:
In 2016, Dominion realized a taxable gain resulting from the contribution of Questar Pipeline to Dominion Midstream. The contribution and related transactions resulted in increases in the tax basis of Questar Pipeline’s assets and the number of Dominion Midstream’s common and convertible preferred units held by noncontrolling interests. The direct tax effects of the transactions included a provision for current income taxes ($212 million) and an offsetting benefit for deferred income taxes ($96 million) and were charged to common shareholders’ equity. The federal tax liability was reduced by $129 million of tax credits generated in 2016 that otherwise would have resulted in additional credit carryforwards and a $17 million benefit provided by the domestic production activities deduction. These benefits, as indirect effects of the contribution transaction, are reflected in Dominion’s current federal income tax expense. In 2015, Dominion’s current federal income tax benefit includes the recognition of a $20 million benefit related to a carryback to be filed for nuclear decommissioning expenditures included in its 2014 net operating loss. For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to
In 2016, Dominion’s effective tax rate
Combined Notes to Consolidated Financial Statements, Continued
At December 31, 2016, Dominion had the following deductible loss and
At December 31, 2016, Dominion Gas had the
A reconciliation of changes in the Companies’ unrecognized tax benefits follows:
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. For Dominion and its subsidiaries, these unrecognized tax benefits were
Effective for its 2014 tax year, Dominion
Otherwise, with regard to For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows:
NOTE 6. FAIR VALUE MEASUREMENTS Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of amid-market pricing convention (themid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments, and other investments including those held in nuclear decommissioning, Dominion’s rabbi, pension and other postretirement benefit plan trusts, in accordance with the requirements discussed above. Virginia Power Inputs and Assumptions The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services,
Combined Notes to Consolidated Financial Statements, Continued For options and contracts with option-like characteristics where observable pricing information is not available from external sources, The inputs and assumptions used in measuring fair value include the following: For commodity
Transaction prices Price volatility Price correlation Volumes Commodity location Interest rates Credit quality of counterparties and the Companies Credit enhancements Time value For interest rate derivative contracts:
Interest rate curves Credit quality of counterparties and the Companies Notional value Credit enhancements Time value For foreign currency derivative contracts: Foreign currency forward exchange rates Interest rates Credit quality of counterparties and the Companies Notional value Credit enhancements Time value For investments:
Securities trading information including volume and restrictions Maturity Interest rates Credit quality The Companies regularly evaluate and validate the inputs used to estimate fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities and investments in which the Companies transact. Levels The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:
Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, certain natural gas and power options and other modeled commodity derivatives. The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. Alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments held in nuclear decommissioning and benefit plan trust funds, are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date. Alternative investments recorded at NAV are not classified in the fair value hierarchy.
For derivative contracts, Level 3 Valuations Fair value measurements are categorized as Level 3 when
The following table presents Dominion’s
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Nonrecurring Fair Value Measurements
Natural Gas Assets In
Combined Notes to Consolidated Financial Statements, Continued
Recurring Fair Value Measurements Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion’s and Dominion Gas’ pension and other postretirement benefit plans are presented in Note 21. DOMINION The following table presents Dominion’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
The following table presents the net change in Dominion’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
The following table presents Dominion’s gains and losses included in earnings in the Level 3 fair value category:
VIRGINIA POWER The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2016. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility and credit spreads.
Combined Notes to Consolidated Financial Statements, Continued Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
The gains and losses included in earnings in the Level 3 fair value category DOMINION GAS The following table presents Dominion Gas’ quantitative information about Level 3 fair value measurements at December 31, 2016. The range and weighted average are presented in dollars for market price inputs.
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
The following table presents Dominion Gas’ assets and liabilities for commodity, interest rate, and foreign currency derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
The following table presents the net change in Dominion Gas’ derivative assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
The gains and losses included in earnings in the Level 3 fair value category were classified in operating revenue in Dominion Gas’ Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 2014. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2016, 2015 and 2014. Fair Value of Financial Instruments Substantially all of
Combined Notes to Consolidated Financial Statements, Continued
NOTE 7. DERIVATIVES A
Derivative assets and liabilities are presented gross on transactions.Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certainover-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions. In general, mostover-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral forover-the-counter and exchange contracts include cash, letters of credit, and, in some cases, other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on
DOMINION Balance Sheet Presentation The tables below present Dominion’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:
Combined Notes to Consolidated Financial Statements, Continued
Volumes The following table presents the volume of Dominion’s derivative activity as of December 31,
Ineffectiveness and AOCI For the years ended December 31, The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at December 31,
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices, interest rates and
Fair Value and Gains and Losses on Derivative Instruments The following tables present the fair values of Dominion’s derivatives and where they are presented in its Consolidated Balance Sheets:
The following tables present the gains and losses on Dominion’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
Combined Notes to Consolidated Financial Statements, Continued
VIRGINIA POWER Balance Sheet Presentation The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:
Volumes The following table presents the volume of Virginia Power’s derivative activity at December 31,
Ineffectiveness and AOCI For the years ended December 31, The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at December 31, 2016:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of interest rates contemplated by the underlying risk management strategies and
Combined Notes to Consolidated Financial Statements, Continued
Fair Value and Gains and Losses on Derivative Instruments The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:
The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
DOMINION GAS Balance Sheet Presentation The tables below present Dominion Gas’ derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:
Combined Notes to Consolidated Financial Statements, Continued Volumes The following table presents the volume of Dominion Gas’ derivative activity at December 31, 2016. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.
Ineffectiveness and AOCI For the years ended December 31, 2016, 2015 and 2014, gains or losses on hedging instruments determined to be ineffective were not material. The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Gas’ Consolidated Balance Sheet at December 31, 2016:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices, interest rates, and foreign currency exchange rates. Fair Value and Gains and Losses on Derivative Instruments The following tables present the fair values of Dominion Gas’ derivatives and where they are presented in its Consolidated Balance Sheets:
The following tables present the gains and losses on Dominion Gas’ derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
NOTE 8. EARNINGS PER SHARE The following table presents the calculation of Dominion’s basic and diluted EPS:
Combined Notes to Consolidated Financial Statements, Continued
NOTE 9. INVESTMENTS DOMINION Equity and Debt Securities RABBI TRUST SECURITIES Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled DECOMMISSIONING TRUST SECURITIES Dominion holds marketable equity and debt securities (classified asavailable-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below:
The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at December 31,
Presented below is selected information regarding Dominion’s marketable equity and debt securities held in nuclear decommissioning trust funds:
Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:
VIRGINIA POWER Virginia Power holds marketable equity and debt securities (classified as
The fair value of Virginia Power’s marketable debt securities at December 31, 2016, by contractual maturity is as follows:
Presented below is selected information regarding Virginia Power’s marketable equity and debt securities held in nuclear decommissioning trust funds.
Virginia Power recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:
EQUITY METHOD INVESTMENTS Dominion and Dominion Gas Investments that Dominion
Combined Notes to Consolidated Financial Statements, Continued Dominion’s equity earnings on Dominion Gas’ equity earnings on its investment totaled $21 million, $23 million and $21 million in 2016, 2015 and 2014, respectively. Dominion Gas received distributions from its investment of $22 million, $28 million and $20 million in 2016, 2015, and 2014, respectively. As of December 31, 2016 and 2015, the carrying amount of Dominion Gas’ investment exceeded its share of underlying equity in net assets by $8 million. The Equity earnings are recorded in other income in Dominion’s and Dominion Gas’ Consolidated Statements of Income. BLUE RACER In December 2012, Dominion formed a joint venture with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. In In Dominion ATLANTIC COAST PIPELINE In September 2014, Dominion, along with Duke and Southern Company Gas (formerly known as AGL Resources Inc.), announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. In October 2016, Dominion purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million. The members, which are subsidiaries of the above-referenced parent companies, hold the following membership interests: Dominion, 48%; Duke, 47%; and Southern Company Gas (formerly known as AGL Resources Inc.), 5%. Atlantic Coast Pipeline is focused on constructing an approximately
NOTE 10. PROPERTY, PLANTAND EQUIPMENT Major classes of property, plant and equipment and their respective balances for the Companies are as follows:
Jointly-Owned Power Stations Dominion’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31,
Theco-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.
In December 2013, In November 2014, Dominion Gas 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
Combined Notes to Consolidated Financial Statements, Continued
Dominion Gas, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas produced from the acreage. In November 2014, Dominion Gas closed on the agreement and received proceeds of $60 million associated with an initial conveyance of approximately 12,000 acres, resulting in a $60 million ($36 millionafter-tax) gain, recorded to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. In connection with that agreement, in 2016, Dominion Gas conveyed approximately 4,000 acres of Marcellus Shale development rights and received proceeds of $10 million and an overriding royalty interest in gas produced from the acreage. These transactions resulted in a $10 million ($6 million after-tax) gain. The gains are included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. In March 2015, Dominion Gas conveyed to a natural gas producer approximately 11,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields and received proceeds of $27 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in a $27 million ($16 millionafter-tax) gain, included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. In September 2015, Dominion Gas closed on an agreement with a natural gas producer to convey approximately 16,000 acres of Utica and Point Pleasant Shale development rights underneath one of its natural gas storage fields. The agreement provided for a payment to Dominion Gas, subject to customary adjustments, of $52 million and an overriding royalty interest in gas produced from the acreage. In September 2015, Dominion Gas received proceeds of $52 million associated with the conveyance of the acreage, resulting in a $52 million ($29 millionafter-tax) gain, included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. NOTE 11. GOODWILLAND INTANGIBLE ASSETS Goodwill The changes in Dominion’s and Dominion Gas’ carrying amount and segment allocation of goodwill are presented below:
Other Intangible Assets
Annual amortization expense for these intangible assets is estimated to be as follows:
NOTE 12. REGULATORY ASSETSAND LIABILITIES Regulatory assets and liabilities include the following:
Combined Notes to Consolidated Financial Statements, Continued
At December 31,
NOTE 13. REGULATORY MATTERS Regulatory Matters Involving Potential Loss Contingencies As a result of issues generated in the ordinary course of business, is based on currently available information, FERC— Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Dominion’s merchant generators sell electricity in the PJM, MISO, CAISO andISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California and Utah, under Dominion’s market-based sales tariffs authorized by
Rates In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure. In
In March 2014, FERC issued an order excluding from Virginia Power’s transmission rates for wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable fornon-Virginia wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities PJM Transmission Rates In April 2007, FERC issued an order regarding its transmission rate design for the allocation of costs among PJM transmission customers, including Virginia Power, for transmission service provided by PJM. For new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a PJM regional rate design where customers pay according to each customer’s share of the region’s load. For recovery of costs of existing facilities, FERC approved the existing methodology whereby a customer pays the cost of facilities located in the same zone as the customer. A number of parties appealed the order to the U.S. Court of Appeals for the Seventh Circuit. In August 2009, the court issued its decision affirming the FERC order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above for further consideration by FERC. On remand, FERC reaffirmed its earlier decision to allocate the costs of new facilities 500 kV and above according to the customer’s share of the region’s load. A number of parties filed appeals of the order to the U.S. Court of Appeals for the Seventh Circuit. In June 2014, the court again remanded the cost allocation issue to FERC. In December 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the cost allocation issue. The hearing only concerns the costs of new facilities approved by PJM prior to February 1, 2013. Transmission facilities approved after February 1, 2013 are allocated on a hybrid cost allocation method approved by FERC and not subject to any court review. In June 2016, PJM, the PJM transmission owners and state commissions representing substantially all of the load in the PJM market submitted a settlement to FERC to resolve the outstanding issues regarding this matter. Under the terms of the settlement, Virginia Power would be required to pay approximately $200 million to PJM over the next 10 years. Although the settlement agreement has not been accepted by FERC, and the settlement is opposed by a small group of parties to the proceeding, Virginia Power believes it is probable it will be required to make payment as an outcome of the settlement. Accordingly, as of December 31, 2016, Virginia Power has a contingent liability of $200 million in other deferred credits and other liabilities, which is offset by a $192 million regulatory asset for the amount that will be recovered through retail rates in Virginia. The remaining $8 million was recorded in other operations and maintenance expense, during 2015, in the Consolidated Statements of Income. Other Regulatory Matters
The Regulation Act enacted in 2007 instituted acost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers. The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs and renewable energy programs, and also If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows. Regulation Act Legislation 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. In addition, no biennial reviews will be conducted by the Virginia Commission for the five successive
Combined Notes to Consolidated Financial Statements, Continued 12-month test periods beginning January 1, 2015, and ending December 31, 2019. The legislation states that Virginia Power’s 2015 biennial review, filed in March 2015, would proceed for the sole purpose of reviewing and determining whether any refunds are due to customers based on earnings performance for generation and distribution services during the 2013 and 2014 test periods. In addition the legislation requires the Virginia Commission to conduct proceedings in 2017 and 2019 to determine the utility’s ROE for use in connection with rate adjustment clauses and requires utilities to file integrated resource plans annually rather than biennially. In November 2015, the Virginia Commission ordered testimony, briefs and a separate bifurcated hearing in Virginia Power’s then-pending Rider B, R, S, and W cases on whether the Virginia Commission can adjust the ROE applicable to these rate adjustment clauses prior to 2017. In February 2016, the Virginia Commission issued final orders in these cases, stating that it could adjust the ROE and setting a base ROE of 9.6% for the projects. After separate, additional bifurcated hearings, the Virginia Commission issued final orders setting base ROEs of 9.6% in March 2016 for Rider GV, in April 2016 for Riders C1A and C2A, in June 2016 for Riders BW and US-2, and in August 2016 for Rider U. In February 2017, the Virginia Commission issued final orders setting base ROEs of 9.4% for Riders B, R, S, W, and GV effective April 1, 2017. In February 2016, certain industrial customers of APCo petitioned the Virginia Commission to issue a declaratory judgment that Virginia legislation enacted in 2015 keeping APCo’s base rates unchanged until at least 2020 (and Virginia Power’s base rates unchanged until at least 2022) is unconstitutional, and to require APCo to make biennial review filings in 2016 and 2018. Virginia Power intervened to support the constitutionality of this legislation. In July 2016, the Virginia Commission held in a divided opinion that this legislation is constitutional, and the industrial customers appealed this order to the Supreme Court of Virginia. In November 2016, the Supreme Court of Virginia granted the appeal as a matter of right and consolidated it for oral argument with other similar appeals from the Virginia Commission’s order. These appeals are pending.
Pursuant to the Regulation Act, in March period, and determining whether credits are due to customers in the event Virginia Power’s earnings exceeded the earnings band determined in the 2013 Biennial Review Order. In November After deciding 2014 over asix-month period beginning within 60 days of the 2015 Biennial Review Order. Based upon 2015 legislation keeping Virginia Power’s base rates unchanged until at least December 1, 2022, the Virginia Commission did not order certain existing rate adjustment clauses to be
Virginia Fuel Expenses In May
Solar Facility Projects In February 2017, Virginia Power received approval from the Virginia Commission for a CPCN to In October 2015, Virginia Power filed an application with the Virginia Commission for CPCNs to
December 2016, and increased Dominion’s renewable generation by a combined 56 MW at a total cost of approximately $130 million, excluding financing costs. See below for further information on Rider US-2. In August 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate the Oceana solar facility and related distribution interconnection facilities on land owned by the U.S. Navy. The facility would begin commercial operations in late 2017 and increase Dominion’s renewable generation by approximately 18 MW at an estimated cost of approximately $40 million, excluding financing costs. The facility is the subject of a public-private partnership whereby the Commonwealth of Virginia, anon-jurisdictional customer, will compensate Virginia Power for the facility’s net electrical energy output. Virginia Power will retire renewable energy certificates on the Commonwealth’s behalf in an amount equal to those generated by the facility. There is no rate adjustment clause associated with this CPCN filing, nor will any costs of the project be recovered from jurisdictional customers. This case is pending. Rate Adjustment Clauses Below is a discussion of significant riders associated with various Virginia Power projects: The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2016, Virginia Power proposed a $639 million total revenue requirement for the rate year beginning September 1, 2016, which represents a $1 million increase over the revenues projected to be produced during the rate year under current rates. In July 2016, the Virginia Commission approved Virginia Power’s proposed total revenue requirement. The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In February 2016, the Virginia Commission approved a $251 million revenue requirement, subject totrue-up, for the rate year beginning April 1, 2016. It also established a 10.6% ROE for Rider S effective April 1, 2016. In June 2016, Virginia Power proposed a $254 million revenue requirement for the rate year beginning April 1, 2017, which represents a $3 million increase over the previous year. In February 2017, the Virginia Commission established a 10.4% ROE for Rider S effective April 1, 2017. This case is pending. The Virginia Commission previously approved Rider W in conjunction with Warren County. In February 2016, the Virginia Commission approved a $118 million revenue requirement, subject totrue-up, for the rate year beginning April 1, 2016. It also established a 10.6% ROE for Rider W effective April 1, 2016. In June 2016, Virginia Power proposed a $126 million revenue requirement for the rate year beginning April 1, 2017, which represents an $8 million increase over the previous year. In February 2017, the Virginia Commission established a 10.4% ROE for Rider W effective April 1, 2017. This case is pending. The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In February 2016, the Virginia Commission approved a $74 million revenue requirement, subject totrue-up, for the rate year beginning
The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In February 2016, the Virginia Commission approved a $30 million revenue requirement for the rate year beginning April 1, 2016. It also established an 11.6% ROE for Rider B effective April 1, 2016. In June 2016, Virginia Power proposed a $28 million revenue requirement for the rate year beginning April 1, 2017, which represents a $2 million decrease versus the previous year. In February 2017, the Virginia Commission established an 11.4% ROE for Rider B effective April 1, 2017. This case is pending. The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by prior Virginia legislation. In August 2016, the Virginia Commission approved a net $20 million revenue requirement and a 9.6% ROE for the rate year beginning September 1, 2016, and an additional $2 million in credits to offset approved revenue requirements for Phase One for each of the 2017-2018 and 2018-2019 rate years. The order limited the total investment in Phase One of Virginia Power’s proposed program to $140 million, with $123 million recoverable through Rider U. In December 2016, Virginia Power proposed a total $31 million revenue requirement for Phase One and Phase Two costs for the rate year beginning September 1, 2017. Virginia Power’s estimated total investment in Phase Two is $110 million. This case is pending. The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In April 2016, the Virginia Commission approved a $46 million revenue requirement, subject totrue-up, for the rate year beginning May 1, 2016. It also established a 9.6% ROE for Riders C1A and C2A effective May 1, 2016. The Virginia Commission approved one new energy efficiency program at a reduced cost cap, denied a second energy efficiency program, and approved the extension of an existing peak shaving program recovered in base rates at no additional incremental cost. In October 2016, Virginia Power proposed a total revenue requirement of $45 million for the rate year beginning July 1, 2017. Virginia Power also proposed two new energy efficiency programs for Virginia Commission approval with a requested five-year cost cap of $178 million. Virginia Power further proposed to extend an existing energy efficiency program for an additional two years under current funding, and an existing peak shaving program for an additional five years with an additional $5 million cost cap. This case is pending. The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In June 2016, the Virginia Commission approved a $119 million revenue requirement for the rate year beginning September 1, 2016. It also established a 10.6% ROE for Rider BW effective September 1, 2016. In October 2016, Virginia Power proposed a
Combined Notes to Consolidated Financial Statements, Continued
Electric Transmission Projects In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry Virginia Power previously filed an application with the Virginia Commission for a CPCN to construct and operate in Loudoun County, Virginia, a new approximately 230 kV Poland Road substation, and a new approximately four mile overhead 230 kV double circuit transmission line between the existing 230 kV Loudoun-Brambleton line and the Poland Road substation. In August 2016, the Virginia Commission granted a CPCN to construct and operate the project along a revised route. The total estimated cost of the project is approximately $55 million. In November 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to convert an existing transmission line to 230 kV in Prince William County, Virginia, and Loudoun County, Virginia, and to construct and operate a new approximately five mile overhead 230 kV double circuit transmission line between a tap point near the Gainesville substation and a newto-be-constructed Haymarket substation. The total estimated cost of the project is approximately $55 million. This case is pending. In November 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate in multiple Virginia counties an approximately 38 mile overhead 230 kV transmission line between the Remington and Gordonsville substations, along with associated facilities. The total estimated cost of the project is approximately $105 million. This case is pending. In February 2016, the Virginia Commission issued an order granting Virginia Power a CPCN to construct and operate the RemingtonCT-Warrenton 230 kV double circuit transmission line, the Vint Hill-Wheeler and Wheeler-Gainesville 230 kV lines and the 230 kV Vint Hill and Wheeler switching stations along Virginia Power’s proposed route. The total estimated cost of the project is approximately $110 million. In March 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 33 miles of the existing 500 kV transmission line between the Cunningham switching station and the Dooms substation, along with associated station work. The total estimated cost of the project is approximately $60 million. This case is pending. In August 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 28 miles of the existing 500 kV transmission line between the Carson switching station and a terminus located near the Rogers Road switching station under construction in Greensville County, Virginia, along with associated work at the Carson switching station. The total estimated cost of the project is approximately $55 million. This case is pending. In January 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and rearrange its Idylwood substation in Fairfax County, Virginia. The total estimated cost of the project is approximately $110 million. This case is pending. North Anna Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna nuclear power station. If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. The COL is
expected in 2017. Virginia Power has not yet committed to building a new Requests by BREDL for a contested NRC hearing on Virginia Power’s COL application have been dismissed, and in September 2016, the U.S. Court of Appeals for the D.C. Circuit dismissed with prejudice petitions for judicial review that BREDL and other organizations had filed challenging the NRC’s reliance on a rule generically assessing the environmental impacts of continued onsite storage of spent nuclear fuel in various licensing proceedings, including Virginia Power’s COL proceeding. This dismissal followed the Court’s June 2016 decision in New York v. NRC, upholding the NRC’s continued storage rule and August 2016 denial of requests for rehearing en banc. Therefore, the contested portion of the COL proceeding is closed. The NRC is required to conduct a hearing in all COL proceedings. This mandatory NRC hearing is anticipated to occur in the first half of 2017 and will be uncontested. In August 2016, Virginia Power received a60-day notice of intent to sue from the Sierra Club alleging Endangered Species Act violations. The notice alleges that the U.S. Army Corps of Engineers failed to conduct adequate environmental and consultation reviews, related to a potential third nuclear unit located at North Anna, prior to issuing a CWA section 404 permit to Virginia Power in September 2011. No lawsuit has been filed and in November 2016, the Army Corps of Engineers suspended the section 404 permit while it gathers additional information. This permitting issue is not expected to affect the NRC’s issuance of the COL. Virginia Power is currently unable to make an estimate of the potential impacts to its consolidated financial statements related to this matter. NORTH CAROLINA REGULATION In March 2016, Virginia Power filed its base rate case and schedules with the North Carolina Commission. Virginia Power proposed anon-fuel, base rate increase of $51 million effective November 1, 2016 with an ROE of 10.5%. In October 2016, Virginia Power entered into a stipulation and settlement agreement for anon-fuel, base rate increase of $35 million with an ROE of 9.9% effective November 1, 2016, on a temporary basis subject to refund, with any permanent rates ordered by the North Carolina Commission effective January 1, 2017. In December 2016, the North Carolina Commission approved the stipulation and settlement agreement. In August 2016, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $36 million decrease to the fuel component of its electric rates for the rate year beginning January 1, 2017. In December 2016, the North Carolina Commission approved the requested decrease and an additional $1 million reduction to Virginia Power’s
PIR Program In 2008, East Ohio began PIR, aimed at replacing approximately of the Ohio Commission to settle East Ohio’s pending application. As requested, the PIR Program and associated cost recovery will continue for another five-year term, calendar years 2017 through 2021, and East Ohio will be permitted to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery In AMR Program In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. The AMR program approved by the Ohio Commission was completed in 2012. Although no further capital investment will be added, East Ohio is approved to recover depreciation, property taxes, carrying charges and a return until East Ohio has another rate case. In February 2016, East Ohio filed an PIPP Plus Program Under the Ohio PIPP Plus Program, eligible customers can UEX Rider East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In August 2016, the Ohio Commission approved an increase to East Ohio’s UEX Rider, which reflects a refund of over-recovered accumulated bad debt expense of approximately $8 million as of March 31, 2016, and recovery of prospective net bad debt expense projected to total approximately $19 million for the twelve-month period from April
In
Combined Notes to Consolidated Financial Statements, Continued
WEST VIRGINIA REGULATION In May 2016, Hope filed a PREP application with the West Virginia Commission requesting approval of a projected capital investment for 2017 of $27 million as part of a total five-year projected capital investment of $152 million. In September 2016, Hope reached a settlement with all parties to the case agreeing to new PREP customer rates, for the year beginning November 1, 2016, that provide for annual projected revenue of $2 million related to capital investments of $20 million and $27 million for 2016 and 2017, respectively. In October 2016, the West Virginia Commission approved the settlement. FERC—GAS Cove Point In November 2016, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with 23 proposed rates to be effective January 1, 2017. Cove Point proposed an annual cost-of-service of approximately $140 million. In December 2016, FERC accepted a January 1, 2017 effective date for all proposed rates but five which were suspended to be effective June 1, 2017. NOTE 14. ASSET RETIREMENT OBLIGATIONS AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of The Companies have also identified, but not recognized, AROs related to the retirement of Dominion’s LNG facility, Dominion’s
Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31,
NOTE 15. VARIABLE INTEREST ENTITIES The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE. Dominion At December 31, 2016, Dominion owns the general partner, 50.9% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Midstream, which owns a preferred equity interest and the general partner interest in Cove Point. Additionally, Dominion owns the manager and 67% of the membership interest in certain merchant solar facilities, as discussed in Note 2. Dominion has concluded that these entities are VIEs due to the limited partners or members lacking the characteristics of a controlling financial interest. In addition, in 2016 Dominion created a wholly owned subsidiary, SBL Holdco, as a holding company of its interest in the VIE merchant solar facilities and accordingly SBL Holdco is a VIE. Dominion is the primary beneficiary of Dominion Midstream, SBL Holdco and the merchant solar facilities, and Dominion Midstream is the primary beneficiary of Cove Point, as they have the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Dominion’s securities due within one year and long-term debt include $17 million and $377 mil- lion, respectively, of debt issued in 2016 by SBL Holdco net of issuance costs that is nonrecourse to Dominion and is secured by SBL Holdco’s interest in the merchant solar facilities. Dominion owns a 48% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the nature of this entity. Dominion concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion has concluded that it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. Dominion is obligated to provide capital contributions based on its ownership percentage. Dominion’s maximum exposure to loss is limited to its current and future investment. Dominion and Virginia Power Dominion’s and Virginia Power’s nuclear decommissioning trust funds and Dominion’s rabbi trusts hold investments in limited partnerships or similar type entities (see Note 9 for further details). Dominion and Virginia Power Dominion and Dominion Gas Dominion previously concluded that Iroquois was a VIE because anon-affiliated Iroquois equity holder had the ability during a limited period of time to transfer its ownership interests to another Iroquois equity holder or its affiliate. At the end of the first quarter of 2016, such right no longer existed and, as a result, Dominion concluded that Iroquois is no longer a VIE. Virginia Power Virginia Power had long-term power and capacity contracts with
Combined Notes to Consolidated Financial Statements, Continued dates ranging from Dominion Gas DTI has been engaged to oversee the construction of, and to subsequently operate and maintain, the projects undertaken by Atlantic Coast Pipeline based on the overall direction and oversight of Atlantic Coast Pipeline’s members. An affiliate of DTI holds a membership interest in Atlantic Coast Pipeline, therefore DTI is considered to have a variable interest in Atlantic Coast Pipeline. The members of Atlantic Coast Pipeline hold the power to direct the construction, operations and maintenance activities of the entity. DTI has concluded it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance. DTI has no obligation to absorb any losses of the VIE. See Note 24 for information about associated related party receivable balances. Virginia Power and Dominion Gas Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of
NOTE 16. SHORT
Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:
In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which have a stated maturity date of December 2017 with automatic one-year renewals through the maturity of the SBL Holdco term loan agreement in 2023. As of December 31, 2016, no amounts were outstanding under these facilities.
Virginia Power’s short-term financing is supported
Virginia Power’s share of commercial paper and letters of credit outstanding
In addition to the credit facility commitments mentioned above, Virginia Power also has a $100 million credit facility. In May 2016, the maturity date for this credit facility was extended from April 2019 to April 2020. In October 2016, this facility was reduced from $120 million to $100 million. As of December 31, 2016, this facility supports $100 million of certain variable ratetax-exempt financings of Virginia Power. Dominion Gas Dominion Gas’ short-term financing is supported by its access asco-borrower to the two joint revolving credit facilities. These credit facilities can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes. Dominion Gas’ share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion, Virginia Power and Questar Gas were as follows:
NOTE 17. LONG
Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31,
The Companies short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, In Senior Note Redemptions As part of Dominion’s Liability Management Exercise, in December 2014, Dominion redeemed five outstanding series of senior notes with an aggregate outstanding principal of $1.9 billion. The aggregate redemption price paid in December 2014 was $2.2 billion and represents the principal amount outstanding, accrued and unpaid interest and the applicable make-whole premium of $263 million. Total charges for the Liability Management Exercise of $284 million, including the make-whole premium, were recognized and recorded in interest expense in Dominion’s Consolidated Statements of Income. Proceeds from Dominion’s issuance of senior notes in November 2014 were used to offset the payment of the redemption price. Also see Convertible Securities called for redemption below.
As part of Dominion’s Liability Management Exercise, in November 2014, Dominion
$26 million of common stock.
Enhanced Junior Subordinated Notes In June 2006 and September 2006, Dominion issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. In June 2009, Dominion issued $685 million of 8.375% June 2009 hybrids. The June 2009 hybrids In October 2014, Dominion issued $685 million of October 2014 hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly. Dominion may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids. Dominion executed RCCs in connection with its issuance of
Combined Notes to Consolidated Financial Statements, Continued 2009 hybrids. Under the terms of the RCCs, Dominion covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. In September 2011, Dominion amended the RCCs of the June 2006 hybrids and September 2006 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock issuances from 180 days to 365 days. In July 2014, Dominion amended the RCC of the June 2009 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock or other equity-like issuances from 180 days to 365 days. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price. As part of Dominion’s Liability Management Exercise, in October 2014, Dominion redeemed all $685 million of the June 2009 hybrids plus accrued interest with the net proceeds from the issuance of the October 2014 hybrids. In From time to time, Dominion may reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity and repurchases in the open market, in privately negotiated transactions, through additional tender offers or otherwise. Remarketable Subordinated Notes In June 2013, Dominion issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B Each Corporate Unit consisted of a stock purchase contract and 1/20 interest in a RSN issued by Dominion. The stock purchase contracts obligated the holders to purchase shares of Dominion common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price paid under the stock purchase contracts was $50 per Corporate Unit and the number of shares purchased was determined under a formula based upon the average closing price of Dominion common stock near the settlement date. The RSNs were pledged as collateral to secure the purchase of common stock under the related stock purchase contracts. In March 2016 and May 2016, Dominion successfully remarketed the $550 million 2013 Series A 1.07% RSNs due 2021 and the $550 million 2013 Series B 1.18% RSNs due 2019, respectively, pursuant to the terms of the related 2013 Equity Units. In connection with the remarketings, the interest rate on the Series A and Series B junior subordinated notes was reset to 4.104% and 2.962%, respectively, payable on a semi-annual basis and Dominion ceased to have the ability to redeem the notes at its option or defer interest payments. At December 31, 2016, the securities are included in junior subordinated notes in Dominion’s Consolidated Balance Sheets. Dominion did not receive any proceeds from the remarketings. Remarketing proceeds belonged to the investors holding the related 2013 Equity Units and were temporarily used to purchase a portfolio of treasury securities. Upon maturity of each portfolio, the proceeds were applied on behalf of investors on the related stock purchase contract settlement date to pay the purchase price to Dominion for issuance of 8.5 million shares of its common stock on both April 1, 2016 and July 1, 2016. See Issuance of Common Stock below for a description of common stock issued by Dominion in April 2016 and July 2016 under the stock purchase contracts. In July 2014, Dominion issued $1.0 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. In August 2016, Dominion issued $1.4 billion of 2016 Series A 6.75% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbols Each 2014 Series A Corporate Unit consists of a stock purchase contract and 1/20 interest in a 2014 Series A RSN issued by Dominion. Each 2016 Series A Corporate Unit consists of a stock purchase contract, a 1/40 interest in a 2016 SeriesA-1 RSN issued by Dominion and a 1/40 interest in a 2016 SeriesA-2 RSN issued by Dominion. The stock purchase contracts obligate the holders to purchase shares of Dominion common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is $50 per Corporate Unit and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion common stock near the settlement date. The RSNs are pledged as collateral to secure the purchase of common stock under the related stock purchase contracts. Dominion makes quarterly interest payments on the RSNs and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. Dominion may defer payments on the stock purchase contracts and the RSNs for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, Dominion may not make any cash distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the RSNs.
Dominion has recorded the present value of the stock purchase contract payments as a liability offset by a charge to
In calculating diluted EPS, Dominion applies the treasury stock method to the Equity Units. Pursuant to the terms of the 2014 Equity Units and 2016 Equity Units, Dominion expects to remarket the 2014 Series A RSNs during the second quarter of 2017 and both the 2016 SeriesA-1 and 2016 Series A-2 RSNs during the third quarter of 2019. Following a successful remarketing, the interest rate on the RSNs will be reset, interest will be payable on a semi-annual basis and Dominion will cease to have Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion will issue between Selected information about Dominion’s Equity Units is presented below:
Combined Notes to Consolidated Financial Statements, Continued
NOTE 18. PREFERRED STOCK Dominion is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation
NOTE 19. Issuance of Common Stock DOMINION Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January During In In both April 2016 and July 2016, Dominion issued 8.5 million shares under the related stock purchase contracts entered into as part of Dominion’s 2013 Equity Units and received $1.1 billion of total proceeds. Additionally, Dominion completed a market issuance of equity in April 2016 of 10.2 million shares and received proceeds of $756 million through a registered underwritten public offering. A portion of the net proceeds was used to finance the Dominion Questar Combination. See Note 3 for more information.
VIRGINIA POWER In Shares Reserved for Issuance At December 31, Repurchase of Common Stock Dominion did not repurchase any shares in Purchase of Dominion Midstream Units In September 2015, Dominion initiated a program to purchase from the market up to $50 million of common units representing limited partner interests in Dominion Midstream, which expired in September 2016. Dominion purchased approximately 658,000 common units for $17 million and 887,000 common units for $25 million for the years ended December 31, 2016 and 2015, respectively. Issuance of Dominion Midstream Units During the fourth quarter of 2016, Dominion Midstream received $482 million of proceeds from the issuance of common units and $490 million of proceeds from the issuance of convertible preferred units. The net proceeds were primarily used to finance a portion of the acquisition of Questar Pipeline from Dominion. See Note 3 for more information. The holders of the convertible preferred units are entitled to receive cumulative quarterly distributions payable in cash or additional convertible preferred units, subject to certain conditions. The units are convertible into Dominion Midstream common units on a one-for-one basis, subject to certain adjustments, (i) in whole or in part at the option of the unitholders any time after December 1, 2018 or, (ii) in whole or in part at Dominion Midstream’s option, subject to certain conditions, any time after December 1, 2019. The conversion of such units would result in a potential increase to Dominion’s net income attributable to noncontrolling interests.
Accumulated Other Comprehensive Income (Loss) Presented in the table below is a summary of AOCI by component:
DOMINION The following table presents Dominion’s changes in AOCI by component, net of tax:
Combined Notes to Consolidated Financial Statements, Continued
The following table presents Dominion’s reclassifications out of AOCI by component:
VIRGINIA POWER The following table presents Virginia Power’s changes in AOCI by component, net of tax:
The following table presents Virginia Power’s reclassifications out of AOCI by component:
DOMINION GAS The following table presents Dominion Gas’ changes in AOCI by component, net of tax:
(1) See table below for details about these reclassifications.
Combined Notes to Consolidated Financial Statements, Continued The following table presents Dominion Gas’ reclassifications out of AOCI by component:
Stock-Based Awards The 2005 and 2014 Incentive Compensation Dominion measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion’s results for the years ended December 31,
RESTRICTED STOCK Restricted stock grants are made to officers under Dominion’s LTIP and may also be granted to certain keynon-officer employees from time to time. The fair value of Dominion’s restricted stock awards is equal to the closing price of Dominion’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31,
As of December 31, GOAL-BASED STOCK Goal-based stock awards are granted under Dominion’s LTIP to officers who have not achieved a certain targeted level of share ownership, in lieu of cash-based performance grants.
The issuance of awards is based on the achievement of two performance metrics during atwo-year period: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The actual number of shares issued will vary between zero and 200% of targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is
The following table provides a summary of goal-based stock activity for the years ended December 31,
At December 31, As of December 31, CASH-BASED PERFORMANCE GRANTS Cash-based performance grants are made to Dominion’s officers under Dominion’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved. In February
In February In February 2016, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15,
NOTE 20. DIVIDEND RESTRICTIONS The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, The Ohio Commission may prohibit any public service company, including East Ohio, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2016, the Ohio Commission had not restricted the payment of dividends by East Ohio. The Utah Commission may prohibit any public service company, including Questar Gas, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2016, the Utah Commission had not restricted the payment of dividends by Questar Gas. Certain agreements associated with See Note 17 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on certain junior subordinated notes and equity units, initially in the form of corporate units.
NOTE 21. EMPLOYEE BENEFIT PLANS
Dominion provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Gas participates in a number of the Dominion-sponsored retirement plans. Under the terms of its benefit plans, Dominion reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits. Dominion maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension Pension benefits for Dominion Gas employees not represented by collective bargaining units are covered by the Domin-
Combined Notes to Consolidated Financial Statements, Continued ion Pension Plan, a defined benefit pension plan sponsored by Dominion that provides benefits to multiple Dominion subsidiaries. Pension benefits for Dominion Gas employees represented by collective bargaining units are covered by separate pension plans for East Ohio and, for DTI, a plan that provides benefits to employees of both DTI and Hope. Employee compensation is the basis for allocating pension costs and obligations between DTI and Hope and determining East Ohio’s share of total pension costs. Retiree healthcare and life insurance benefits for Dominion Gas employees not represented by collective bargaining units are covered by the Dominion Retiree Health and Welfare Plan, a plan sponsored by Dominion that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Retiree healthcare and life insurance benefits for Dominion Gas employees represented by collective bargaining units are covered by separate other postretirement benefit plans for East Ohio and, for DTI, a plan that provides benefits to both DTI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DTI and Hope and determining East Ohio’s share of total other postretirement benefit costs. Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates, mortality rates and the rate of compensation increases. Dominion uses December 31 as the measurement date for all of its employee benefit Dominion’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Dominion’s pension and other postretirement plan assets periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.
During 2016, Dominion and Dominion Gas (for employees represented by collective bargaining units) engaged their actuary to conduct an experience study of their employees demographics over a five-year period as compared to significant assumptions that were being used to determine pension and other postretirement benefit obligations and periodic costs. These assumptions primarily included mortality, retirement rates, termination rates, and salary increase rates. The changes in assumptions implemented as a result of the experience study resulted in increases of $290 million and $38 million in the Plan Amendments and Remeasurements In the third quarter of In the third quarter of 2014, East Ohio remeasured its other postretirement benefit plan as a result of an amendment that changed medical coverage upon the attainment of age 65 for certain future retirees effective January 1, 2016. For employees represented by collective bargaining units, the remeasurement resulted in an increase in the accumulated postretirement benefit obligation of $22 million. The impact of the remeasurement on net periodic benefit credit was recognized prospectively from the remeasurement date and reduced net periodic benefit
Funded Status The following table summarizes the changes in
Combined Notes to Consolidated Financial Statements, Continued
The ABO for all of Dominion’s defined benefit pension plans was Under its funding policies, Dominion evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion determines the amount of contributions for the current year, if any, at that time. During Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion’s subsidiaries, including Dominion Gas, fund other postretirement benefit costs through VEBAs. Dominion’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion’s contributions to VEBAs, all of which pertained to Dominion Gas employees, totaled $12 million for both 2016 and 2015, and Dominion expects to contribute approximately $12 million to the Dominion VEBAs in Dominion The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan
The following table provides information on the ABO and fair value of plan assets for Dominion’s pension plans with an ABO in excess of plan assets:
The following benefit payments, which reflect expected future service, as appropriate, are expected to be
Plan Assets Dominion’s overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. As a participating employer in various pension plans sponsored by Dominion, Dominion Gas is subject to Dominion’s investment policies for such plans. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for Dominion also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and
individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies. Strategic investment policies are established for Dominion’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities. For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.
Combined Notes to Consolidated Financial Statements, Continued
The fair values of Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) pension plan assets by asset category are as follows:
The fair values of Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) other postretirement plan assets by asset category are as follows:
Combined Notes to Consolidated Financial Statements, Continued
The
Net Periodic Benefit (Credit) Cost Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in the Consolidated Statements of Income. The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans are as follows:
Combined Notes to Consolidated Financial Statements, Continued
The components of AOCI and regulatory assets and liabilities for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:
The following table provides the components of AOCI and regulatory assets and liabilities for Dominion’s and Dominion Gas’ (for employees represented by collective bargaining units) plans as of December 31,
The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion develops assumptions, which are then compared to the forecasts of an independent investment advisor (except for the expected long-term rates of return) to ensure reasonableness. An internal committee selects the final assumptions used for Dominion’s pension and other postretirement plans, including those in which Dominion Gas participates, including discount rates, expected long-term rates of return, healthcare cost trend rates and mortality rates. Dominion determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans, including those in which Dominion Gas participates, by using a combination of: Expected inflation and risk-free interest rate assumptions; Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes; Expected future risk premiums, asset volatilities and correlations;
Forecasts of an independent investment advisor; Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; and Investment allocation of plan assets. Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans, including those in which Dominion Gas participates. Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate. During 2016, Dominion conducted a new experience study as scheduled and, as a result, updated its mortality assumptions for all its plans, including those in which Dominion Gas participates. Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion’s retiree healthcare
Virginia Power—Participation in Defined
Virginia Power
expected in costs for participating Dominion subsidiaries. See Note 24 for Virginia Power Retiree healthcare and life insurance benefits, for Virginia Power employees and for Dominion Gas employees not represented by collective bargaining units, are covered by the Dominion Retiree Health and Welfare Plan Dominion holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power and Dominion Gas’ employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power and Dominion Gas will provide to Dominion for their shares of employee benefit plan contributions. Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power Defined Contribution Plans Dominion
recognized Organizational Design Initiative In the first quarter of 2016, the Companies announced an organizational design initiative that reduced their total workforces during 2016. The goal of the organizational design initiative was to streamline leadership structure and push decision making lower while also improving efficiency. For the year ended December 31, 2016, Dominion recorded a $65 million ($40 million after-tax) charge, including $33 million ($20 million after-tax) at Virginia Power and $8 million ($5 million after-tax) at Dominion Gas, primarily reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other costs related to the organizational design initiative. The terms of the severance under the organizational design initiative were consistent with the Companies’ existing severance plans.
NOTE 22. COMMITMENTS A As a result of issues generated in the ordinary course of business, operations of the Companies. Environmental Matters
Combined Notes to Consolidated Financial Statements, Continued AIR CAA The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of MATS In December 2011, the EPA issued MATS for coal andoil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision foroil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance In June 2015, the U.S. Supreme Court issued a decision holding that the EPA failed to take cost into account when the agency first decided to regulate the emissions from coal- andoil-fired plants, and remanded the MATS rule back to the U.S. Court of Appeals for the D.C. Circuit. However, the Supreme Court did not vacate or stay the effective date and implementation of the MATS rule. In November 2015, in response to the Supreme Court decision, the EPA proposed a supplemental finding that consideration of cost does not alter the agency’s previous conclusion that it is appropriate and necessary to regulate coal- andoil-fired electric utility steam generating units under Section 112 of the CAA. In December
CSAPR In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO2 and NO Following numerous petitions by industry participants for review and
Ozone Standards In The EPA is expected to complete attainment designations for a new standard by December 2017 and states will have until 2020 or 2021 to develop NOx and VOC Emissions In
NSPS In August 2012, the EPA issued the first NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In June 2016, the EPA issued a final NSPS regulation, for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 will be required to comply with this regulation. Dominion and Dominion Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material. CLIMATE CHANGE REGULATION Carbon Regulations In October 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the U.S. Court of Appeals for the D.C. Circuit’s June 2012 decision upholding the EPA’s regulation of GHG emissions from stationary sources under the CAA’s permitting programs. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the EPA’s ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant emissions rate at 75,000 tons per year of CO2 equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their financial statements. In July 2011, the EPA signed a final rule deferring the need for PSD and Title V permitting for CO2 emissions for biomass projects. This rule temporarily deferred for a period of up to three years the consideration of CO2 emissions from biomass projects when determining whether a stationary source meets the PSD and Title V applicability thresholds, including those for the application of BACT. The deferral policy expired in July 2014. In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however, a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the CO2 deferral period. It is unclear how the court’s decision or the EPA’s final policy regarding the treatment of specific feedstock will affect biomass sources that were permitted during the deferral period; however, the expenditures to comply with any new requirements could be material to Dominion’s and Virginia Power’s financial statements. Methane Emissions In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR Program, the Natural Gas STAR Methane Challenge Program. The program covers the entire natural gas sector from production to distribution, with more emphasis on transparency and increased reporting for both annual emissions and reductions achieved through implementation measures. In March 2016, East Ohio, Hope, DTI and Questar Gas (prior to the Dominion Questar Combination) joined the EPA as founding partners in the new Methane Challenge program and submitted implementation plans in September 2016. DCG joined the EPA’s voluntary Natural Gas STAR Program in July 2016 and submitted an implementation plan in September 2016. Dominion and Dominion Gas do not expect the costs related to these programs to have a material impact on their results of operations, financial condition and/or cash flows. WATER The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. In In September 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule establishes updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new
Combined Notes to Consolidated Financial Statements, Continued wastewater treatment technologies in order to meet the new discharge limits. Virginia Power has eight facilities that may be subject to additional SOLIDAND HAZARDOUS WASTE The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with anEPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight. From time to time, Dominion, In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, pursuant to CERCLA, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina.
Dominion has determined that it is associated with ducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which
The Companies are defendants in a number of lawsuits and APPALACHIAN GATEWAY Pipeline Contractor Litigation Following the completion of the Appalachian Gateway project in 2012, DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DTI filed a complaint in U.S. District Court for the Eastern District of Virginia for breach of contract as well as accounting and declaratory relief. The contractor filed a motion to dismiss, or in the alternative, a motion to transfer venue to Pennsylvania and/or West Virginia, where the pipelines were constructed. DTI filed an opposition to the contractor’s motion in August 2013. In November 2013, the court granted the contractor’s motion on the basis that DTI must first comply with the dispute resolution process. In July 2015, the contractor filed a complaint against DTI in U.S. District Court for the Western District of Pennsylvania. In August 2015, DTI filed a motion to dismiss, or in the alternative, a motion to transfer venue to Virginia. In March 2016, the Pennsylvania court granted the motion to dismiss and transferred the case to the U.S. District Court for the Eastern District of Virginia. In April 2016, the Virginia court issued an order staying the proceedings and ordering mediation. A mediation occurred in May 2016 but was unsuccessful. In July 2016, DTI filed a motion to dismiss. This case is pending. DTI has accrued a liability of $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows. Gas Producers Litigation In
ASH PONDAND LANDFILL CLOSURE COSTS In September 2014, Virginia Power received a notice from the Southern Environmental Law Center on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at Possum Point power station. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point power station’s historical and active ash storage facilities. A similar notice from the Southern Environmental Law Center on behalf of the Sierra Club was subsequently received related to Chesapeake power station. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum Point power station, Chesapeake and Bremo power stations as settlement of the potential litigation. While the issue is open to potential further negotiations, the Southern Environmental Law Center declined the offer as presented in January In In April 2016, the EPA announced a partial settlement with certain environmental and industry organizations that had challenged the final CCR rule in the U.S. Court of Appeals for the D.C. Circuit. As part of the settlement, certain exemptions included in the final rule for inactive ponds that closed by April 2018 will be removed, resulting in inactive ponds ultimately being subject to the same requirements as existing ponds. In June 2016, the court issued an order approving the settlement, which requires the EPA to modify provisions in the final CCR rule concerning inactive ponds. In August 2016, the EPA issued a final rule, effective October 2016, extending certain compliance deadlines in the In February and March 2016, respectively, two parties filed administrative appeals in the Circuit Court for the City of In 2015, Virginia Power recorded a $386 million ARO related to In December 2016, the U.S. Congress passed and the President signed legislation that creates a framework for
COVE POINT Dominion is constructing the Liquefaction Project at the Cove Point facility, which would enable the facility to Liquefaction Project. In October
Combined Notes to Consolidated Financial Statements, Continued Two parties have separately filed petitions
In September 2013, the FERC The FERC staff in the Office of Enforcement, Division of Investigations, is conducting anon-public investigation of Virginia Power’s offers of combustion turbines generators into the PJMday-ahead markets from April 2010 through September 2014. The FERC staff notified Virginia Power of its preliminary findings relating to Virginia Power’s alleged violation of FERC’s rules in connection with these activities. Virginia Power has provided its response to the FERC staff’s preliminary findings letter explaining why Virginia Power’s conduct was
GREENSVILLE COUNTY Virginia Power is constructing Greensville County and related transmission interconnection facilities. In
Nuclear Matters In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3, with the Tier 1 recommendations consisting of actions which the staff determined should be started without unnecessary delay. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible. Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction
permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion Nuclear Operations NUCLEAR DECOMMISSIONING—MINIMUM FINANCIAL ASSURANCE The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The
their expected earnings for the Surry and North Anna units will be sufficient to cover
NUCLEAR INSURANCE The Price-Anderson Amendments Act of 1988 provides the public up to
discretion to lower or eliminate the maximum retrospective premium assessment. Dominion and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination. Millstone and Virginia Power also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program,
ODEC, a part owner of North Anna, and Massachusetts Municipal and Green Mountain, part owners of Millstone’s Unit 3, are responsible to Dominion and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance. SPENT NUCLEAR FUEL Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by
In 2015, Virginia Power and Dominion received payments of $8 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2013 through December 31, 2013, and $17 million for resolution of claims incurred at Millstone for the period of July 1, 2013 through June 30, 2014. In 2014, Virginia Power and Dominion received payments of $27 million for the resolution of claims incurred at North Anna and Surry for the period January 1, 2011 through December 31, 2012 and $17 million for the resolution of claims incurred at Millstone for the period of July 1, 2012 through June 30, 2013. In 2014, Dominion also received payments totaling $7 million for the resolution of claims incurred at Kewaunee for periods from January 1, 2011 through December 31, 2013. Dominion and Virginia Power continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion’s receivables
Combined Notes to Consolidated Financial Statements, Continued for spent nuclear fuel-related costs totaled Pursuant to a November 2013 decision of the U.S Court of Appeals for the
Long-Term Purchase Agreements At December 31,
Lease Commitments
Rental expense for Dominion totaled In July 2016, Dominion signed an agreement with a lessor to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $365 million, to fund the estimated project costs. The project is expected to be completed by mid-2019. Dominion has been appointed to act as the construction agent for the lessor, during which time Dominion will request cash draws from the lessor and debt investors to fund all project costs, which totaled $46 million as of December 31, 2016. If the project is terminated under certain events of default, Dominion could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion could be required to pay up to 100% of the then funded amount. The five-year lease term will commence once construction is substantially complete and the facility is able to be occupied. At the end of the initial lease term, Dominion can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion may be required to make a payment to the lessor, up to 87% of project costs, for the difference between the project costs and sale proceeds. Guarantees, Surety Bonds and Letters of Credit
At December 31,
Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their
At December 31,
Additionally,
As of December 31, Indemnifications As part of commercial contract negotiations in the normal course of business, impact on their results of operations, cash flows or financial position.
NOTE 23. CREDIT RISK Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.
GENERAL DOMINION As a diversified energy company, Dominion transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast,mid-Atlantic, Midwest and Dominion is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations. Dominion’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include VIRGINIA POWER Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and
Combined Notes to Consolidated Financial Statements, Continued industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealizedon- oroff-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, DOMINION GAS Dominion Gas transacts mainly with major companies in the energy industry and with residential and commercial energy consumers. These transactions principally occur in the Northeast,mid-Atlantic and Midwest regions of the U.S. Dominion Gas does not believe that this geographic concentration contributes to its overall exposure to In 2016, DTI provided service to 289 customers with approximately 96% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 40% of the total storage and transportation revenue and the thirty largest provided approximately 70% of the total storage and transportation revenue. East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates established by the Ohio Commission. Approximately 98% of East Ohio revenues are derived from its regulated gas distribution services. East Ohio’s bad debt risk is mitigated by the regulatory framework established by the Ohio Commission. See Note 13 for further information about Ohio’s PIPP and UEX Riders that mitigate East Ohio’s overall credit risk. CREDIT-RELATED CONTINGENT PROVISIONS The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31,
NOTE 24. RELATED-PARTY TRANSACTIONS Virginia Power VIRGINIA POWER Transactions with Affiliates Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 19 for more information. As of December 31, Virginia Power participates in certain Dominion benefit plans as described in Note 21. At December 31, 2016 and 2015, Virginia Power’s amounts due to Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $396 million and $316 million, respectively. At December 31, 2016 and 2015, Virginia Power’s amounts due from Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $130 million and $77 million, respectively. DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage. The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DRS to Virginia Power on the basis of direct and allocated methods in accordance with Virginia Power’s services agreements with DRS. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DRS resources that is attributable
to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DRS service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. Presented below are significant transactions with DRS and other affiliates:
Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were There were no issuances of Virginia Power’s common stock to Dominion in DOMINION GAS Transactions with Related Parties Dominion Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Gas provides transportation and storage services to affiliates. Dominion Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of December 31, 2016 and 2015, all of Dominion Gas’ commodity derivatives were with affiliates. See Notes 7 and 19 for more information. See Note 9 for information regarding transactions with an affiliate. Dominion Gas participates in certain Dominion benefit plans as described in Note 21. At December 31, 2016 and 2015, Dominion Gas’ amounts due from Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $697 million and $652 million, respectively. At December 31, 2016 and 2015, Dominion Gas’ amounts due from Dominion and liabilities due to Dominion associated with the Dominion Retiree Health and Welfare Plan were immaterial. DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Gas. Dominion Gas provides certain services to related parties, including technical services. The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DRS to Dominion Gas on the basis of direct and allocated methods in accordance with Dominion Gas’ services agreements with DRS. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DRS resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DRS service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. The costs of these services follow:
The following table presents affiliated and related party balances reflected in Dominion Gas’ Consolidated Balance Sheets:
Dominion Gas’ borrowings under the IRCA with Dominion totaled $118 million and $95 million as of December 31, 2016 and 2015, respectively. The weighted-average interest rate of these borrowings was 1.08% and 0.65% at December 31, 2016 and 2015, respectively. Interest charges related to Dominion Gas’ total borrowings from Dominion were immaterial for the years ended December 31, 2016 and 2015 and $4 million for the year ended December 31, 2014.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 25. OPERATING SEGMENTS
In addition to the operating segments above, the Companies also report a Corporate and Other segment.
The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) In March 2014, Dominion exited the In the second quarter of 2013, Dominion commenced a restructuring of its producer services business, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates. The restructuring, which was completed in the first quarter of 2014, resulted in the termination of natural gas trading and certain energy marketing activities. As a result, the earnings impact from natural gas trading and certain energy marketing activities has been included in the Corporate and Other Segment of
In The net expenses for specific items in
DVP ($5 millionafter-tax); Dominion Energy ($12 millionafter-tax); and Dominion Generation ($19 millionafter-tax). In
The net expenses for specific items in
A $99 million ($60 millionafter-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Dominion Generation; and An $85 million ($52 millionafter-tax)write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015, attributable to Dominion Generation. In 2014, Dominion reportedafter-tax net expenses of $970 million in the Corporate and Other segment, with $544 million of these net expenses attributable to specific items related to its operating segments. The net expenses for specific items in 2014 primarily related to the impact of the following items: $374 million ($248 millionafter-tax) in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, attributable to Dominion Generation; A $319 million ($193 millionafter-tax) net loss related to the producer services business discussed above, attributable to Dominion Energy; and A $121 million ($74 millionafter-tax) charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities, attributable to Dominion Generation.
The following table presents segment information pertaining to Dominion’s operations:
The majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s DVP and Dominion Generation segments. The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. In The net expenses for specific items in
A $197 million ($121 millionafter-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Dominion Generation. In
The net expenses for specific items in
A $99 million ($60 millionafter-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Dominion Generation; and An $85 million ($52 millionafter-tax)write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015, attributable to Dominion Generation. In The net expenses for specific items in $374 million ($248 millionafter-tax) in charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, attributable to Dominion Generation; and A $121 million ($74 millionafter-tax) charge related to a settlement offer to incur future ash pond closure costs at certain utility generation facilities, attributable to Dominion Generation.
The following table presents segment information pertaining to Virginia Power’s operations:
DOMINION GAS The Corporate and Other Segment of Dominion Gas primarily includes specific items attributable to Dominion Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources and the effect of certain items recorded at Dominion Gas as a result of Dominion’s basis in the net assets contributed. In 2016, Dominion Gas reportedafter-tax net expenses of $3 million in its Corporate and Other segment, with $7 million of these net expenses attributable to its operating segment. The net expense for specific items in 2016 primarily related to the impact of the following item: An $8 million ($5 millionafter-tax) charge related to an organizational design initiative. In 2015, Dominion Gas reportedafter-tax net expenses of $21 million in its Corporate and Other segment, with $13 million of these net expenses attributable to specific items related to its operating segment. The net expenses for specific items in 2015 primarily related to the impact of the following item: $16 million ($10 millionafter-tax) ceiling test impairment charge. In 2014, Dominion Gas reportedafter-tax net expenses of $9 million in its Corporate and Other segment, with none of these net expenses attributable to specific items related to its operating segment.
The following table presents segment information pertaining to Dominion Gas’ operations:
Combined Notes to Consolidated Financial Statements, Continued
NOTE 26. QUARTERLY FINANCIALAND COMMON STOCK DATA A summary of DOMINION
There were no significant
items impacting Dominion’s 2015 quarterly results.
VIRGINIA POWER Virginia Power’s quarterly results of operations were as follows:
Virginia Power’s 2016 results include the impact of the following significant item: Fourth quarter results include a $121 millionafter-tax charge related to future ash pond and landfill closure costs at certain utility generation facilities. Virginia Power’s 2015 results include the impact of the following significant items: Fourth quarter results include a $32 millionafter-tax charge related to incremental future ash pond and landfill closure costs at certain utility generation facilities. Second quarter results include a $28 millionafter-tax charge related to incremental future ash pond and landfill closure costs at certain utility generation facilities due to the enactment of the final CCR rule in April 2015. First quarter results include a $52 millionafter-taxwrite-off of deferred fuel costs associated with Virginia legislation enacted in February 2015. DOMINION GAS Dominion Gas’ quarterly results of operations were as follows:
There were no significant items impacting Dominion Gas’ 2016 quarterly results. Dominion Gas’ 2015 results include the impact of the following significant items: Third quarter results include a $29 millionafter-tax gain from an agreement to convey shale development rights underneath a natural gas storage field. First quarter results include a $43 millionafter-tax gain from agreements to convey shale development rights underneath several natural gas storage fields.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None.
Item 9A. Controls and Procedures DOMINION Senior management, including Dominion’s CEO and CFO, evaluated the effectiveness of Dominion’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion’s CEO and CFO have concluded that Dominion’s disclosure controls and procedures are effective. There were no changes in Dominion’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion’s internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORTON INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Dominion Dominion maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. The Audit Committee of the Board of Directors of Dominion, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time. SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion’s Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion. There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time. Management evaluated Dominion’s internal control over financial reporting as of December 31, Dominion’s independent registered public accounting firm is engaged to express an opinion on Dominion’s internal control over financial reporting, as stated in their report which is included herein. In September 2016, Dominion acquired Dominion Questar. Dominion excluded all of the acquired Dominion Questar’s business from the scope of management’s assessment of the effectiveness of Dominion’s internal control over financial reporting as of December 31, 2016. Dominion Questar constituted 3% of Dominion’s total revenues for 2016 and 6% of Dominion’s total assets as of December 31, 2016. February
REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Dominion Resources, Inc. Richmond, Virginia We have audited the internal control over financial reporting of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, Dominion maintained, in all material respects, effective internal control over financial reporting as of December 31, We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, /s/ Deloitte & Touche LLP Richmond, Virginia February
VIRGINIA POWER Senior management, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes in Virginia Power’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Power’s internal control over financial reporting.
MANAGEMENT’S ANNUAL REPORTON INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Virginia Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities. SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power. There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time. Management evaluated Virginia Power’s internal control over financial reporting as of December 31, the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, This annual report does not include an attestation report of Virginia Power’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act. February DOMINION GAS Senior management, including Dominion Gas’ CEO and CFO, evaluated the effectiveness of Dominion Gas’ disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion Gas’ CEO and CFO have concluded that Dominion Gas’ disclosure controls and procedures are effective. There were no changes in Dominion Gas’ internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion Gas’ internal control over financial reporting. MANAGEMENT’S ANNUAL REPORTON INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Dominion Gas understands and accepts responsibility for Dominion Gas’ financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion Gas continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business. Dominion Gas maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. The Board of Directors also serves as Dominion Gas’ Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Dominion Gas’ auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities. SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Dominion Gas’ 2016 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Dominion Gas tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2016, Dominion Gas makes the following assertions: Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion Gas.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time. Management evaluated Dominion Gas’ internal control over financial reporting as of December 31, 2016. This assessment was based on criteria for effective internal control over financial reporting described inInternal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion Gas maintained effective internal control over financial reporting as of December 31, 2016. This annual report does not include an attestation report of Dominion Gas’ independent registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Dominion Gas’ independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act. February 28, 2017 None.
Part III Item 10. Directors, Executive Officers and Corporate Governance DOMINION The following information for Dominion is incorporated by reference from the Dominion
The information concerning the executive officers of Dominion required by this item is included in Part I of this Form10-K under the captionExecutive Officers of Dominion. Each executive officer of Dominion is elected annually.
Item 11. Executive Compensation
The following information about Dominion is contained in the
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters DOMINION The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the The information regarding equity securities of Dominion that are authorized for issuance under its equity compensation plans contained under the headingExecutive Compensation-EquityCompensation Plans in the
Item 13. Certain Relationships and Related Transactions, and Director Independence DOMINION The information regarding related party transactions required by this item found under the headingOther Information-Related Party Transactions, and information regarding director independence found under the heading
Item 14. Principal Accountant Fees and Services DOMINION The information concerning principal accountant fees and services contained under the heading VIRGINIA POWERAND DOMINION GAS The following table presents fees paid to Deloitte & Touche LLP for services related to Virginia Power and Dominion Gas for the fiscal years ended December 31,
Audit
Virginia Power’s
Item 15. Exhibits and Financial Statement Schedules
(a) Certain documents are filed as part of this Form10-K and are incorporated by reference and found on the pages noted. 1. Financial Statements See Index on page 2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes. 3. Exhibits (incorporated by reference unless otherwise noted)
None.
Signatures
DOMINION Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the
Dominion Gas Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 28, 2017 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2017.
Exhibit Index
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