UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended September 30, 2015
or
For the transition period from to
Commission File
Number
Exact name of registrants as specified in their charters, address of
principal executive offices and registrants’ telephone number
I.R.S. Employer
Identification Number
120 Tredegar Street
Richmond, Virginia 23219
(804) 819-2000
State or other jurisdiction of incorporation or organization of the registrants: Virginia
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.
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).
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.
Virginia Electric and Power Company
Dominion Gas Holdings, LLC
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
At September 30, 2015, the latest practicable date for determination, Dominion Resources, Inc. had 595,333,610 shares of common stock outstanding and Virginia Electric and Power Company had 274,723 shares of common stock outstanding. Dominion Resources, Inc. is the sole holder of Virginia Electric and Power Company’s common stock. Dominion Resources, Inc. holds all of the membership interests of Dominion Gas Holdings, LLC.
This combined Form 10-Q 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 H(1)(a) AND (b) OF FORM 10-Q AND ARE FILING THIS FORM 10-Q UNDER THE REDUCED DISCLOSURE FORMAT.
COMBINED INDEX
Item 1.
Item 2.
Item 3.
Item 4.
Item 1A.
Item 6.
2
GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Form 10-Q are defined below:
Abbreviation or Acronym
Definition
Dominion’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013
Dominion’s 2014 Series A Equity Units issued in July 2014
Allowance for funds used during construction
Accumulated other comprehensive income (loss)
Asset retirement obligations
Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the CAA
Appalachia to Texas Express ethane line
Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion, Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc.
Best available control technology
Billion cubic feet
Blue Racer Midstream, LLC, a joint venture between Dominion and Caiman
Board of Directors
BP Wind Energy North America Inc.
Blue Ridge Environmental Defense League
Bremo power station
A 1,358 MW combined cycle, natural gas-fired power station under construction in Brunswick County, Virginia
Clean Air Act
Caiman Energy II, LLC
Clean Air Interstate Rule
California independent system operator
Coal combustion residual
Chief Executive Officer
Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
Chief Financial Officer
Chesapeake power station
Carbon dioxide
Combined Construction Permit and Operating License
Dominion, Virginia Power and Dominion Gas, collectively
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
Dominion Cove Point LNG, LP
Certificate of Public Convenience and Necessity
Cross State Air Pollution Rule
Clean Water Act
District of Columbia
Dominion Carolina Gas Transmission, LLC (successor by statutory conversion to and formerly known as Carolina Gas Transmission Corporation)
Dominion Energy, Inc.
Department of Energy
The legal entity, Dominion Resources, Inc., one or more of its consolidated subsidiaries (other than Virginia Power and Dominion Gas) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries
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, Inc., which holds a 24.72% noncontrolling partnership interest in Iroquois
The legal entity, Dominion Midstream Partners, LP, one or more of its consolidated subsidiaries, Cove Point Holdings, Iroquois GP Holding Company, LLC and DCG (beginning April 1, 2015), or the entirety of Dominion Midstream Partners, LP, and its consolidated subsidiaries
3
The initial owner of the 58-mile G-150 pipeline project, which is designed to transport approximately 27,000 barrels per day of NGLs from Natrium to an interconnect with the ATEX line of Enterprise near Follansbee, West Virginia
Dominion Resources Services, Inc.
Demand-side management
Dekatherm
Dominion Transmission, Inc.
Dominion Virginia Power operating segment
The East Ohio Gas Company, doing business as Dominion East Ohio
Enterprise Product Partners, L.P.
Environmental Protection Agency
Engineering, procurement and construction
Earnings per share
Federal Energy Regulatory Commission
Four Brothers Solar, LLC, a limited liability company owned by Dominion and Four Brothers Holdings, LLC, a wholly-owned subsidiary of SunEdison
A wind-turbine facility joint venture between Dominion and BP in Benton County, Indiana
Financial transmission rights
U.S. generally accepted accounting principles
Gallon
Greenhouse gas
Granite Mountain Holdings, LLC, a limited liability company owned by Dominion and Granite Mountain Renewables, LLC, a wholly-owned subsidiary of SunEdison
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 Gas, Inc., doing business as Dominion Hope
Institute of Nuclear Power Operations
Intercompany revolving credit agreement
Iron Springs Holdings, LLC, a limited liability company owned by Dominion and Iron Springs Renewables, LLC, a wholly-owned subsidiary of SunEdison
Iroquois Gas Transmission System L.P.
Independent system operator
ISO New England
Kewaunee nuclear power station
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
Kilovolt
Liquefied natural gas
Utility Mercury and Air Toxics Standard Rule
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Million gallons a day
Millstone nuclear power station
Midcontinent Independent Transmission System Operator, Inc.
Moody’s Investors Service
Morgans Corner Solar Energy, LLC
Megawatt
Megawatt hour
A natural gas and fractionation facility located in Natrium, West Virginia, owned by Blue Racer
North Carolina Electric Membership Corporation
A wind-turbine facility joint venture between Dominion and Shell Wind Energy, Inc. in Grant County, West Virginia
Collectively, North East Transmission Co., Inc. and National Grid IGTS Corp.
Natural gas liquids
4
NJNR Pipeline Company
North Anna nuclear power station
North Carolina Utilities Commission
Collection of approximately 131 miles of various diameter natural gas pipelines in Ohio
Nitrogen oxide
Nuclear Regulatory Commission
New Source Performance Standards
New York Stock Exchange
Old Dominion Electric Cooperative
Public Utilities Commission of Ohio
Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development
Percentage of Income Payment Plan deployed by East Ohio
PJM Interconnection, L.L.C.
Possum Point power station
Parts-per-billion
Pipeline Replacement and Expansion Program, a program of replacing, upgrading and expanding natural gas utility infrastructure to be deployed by Hope
Prevention of Significant Deterioration
Pipeline Safety and Management Program to be deployed by East Ohio to ensure the continued safe and reliable operation of East Ohio’s system and compliance with pipeline safety laws
Real estate investment trust
A rate adjustment clause associated with the recovery of costs related to Brunswick County
A rate adjustment clause associated with the recovery of costs related to Remington Solar Facility
Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in DSM cases
Return on equity
Regional transmission organization
Securities and Exchange Commission
Southern Environmental Law Center
Shell WindEnergy, Inc.
Sulfur dioxide
Project to provide 132,000 Dths/day of firm transportation service from Cove Point’s interconnect with Transco in Fairfax County, Virginia to Competitive Power Venture Maryland, LLC’s power generating facility in Charles County, Maryland
Standard & Poor’s Ratings Services, a division of McGraw Hill Financial, Inc.
The legal entity, SunEdison, Inc., one or more of its consolidated subsidiaries (including Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of SunEdison, Inc. and its consolidated subsidiaries
Granite Mountain and Iron Springs, collectively
United States of America
Unilateral Administrative Order
Virginia Department of Environmental Quality
Voluntary Employees’ Beneficiary Association
Variable interest entity
Virginia State Corporation Commission
The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power and its consolidated subsidiaries
Volatile organic compounds
Yorktown power station
5
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
DOMINION RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Operating Revenue
Operating Expenses
Electric fuel and other energy-related purchases
Purchased electric capacity
Purchased gas
Other operations and maintenance
Depreciation, depletion and amortization
Other taxes
Total operating expenses
Income from operations
Other income
Interest and related charges
Income from operations including noncontrolling interests before income tax expense
Income tax expense
Net Income Including Noncontrolling Interests
Noncontrolling Interests
Net Income Attributable to Dominion
Earnings Per Common Share
Net income attributable to Dominion - Basic
Net income attributable to Dominion - Diluted
Dividends declared per common share
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
6
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income including noncontrolling interests
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)
Changes in unrealized net gains (losses) on investment securities(2)
Changes in unrecognized pension and other postretirement benefit costs(3)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities(4)
Net realized gains on investment securities(5)
Net pension and other postretirement benefit costs(6)
Changes in other comprehensive income (loss) from equity method investees(7)
Total other comprehensive loss
Comprehensive income including noncontrolling interests
Comprehensive income attributable to noncontrolling interests
Comprehensive income attributable to Dominion
7
CONSOLIDATED BALANCE SHEETS
ASSETS
Current Assets
Cash and cash equivalents
Customer receivables (less allowance for doubtful accounts of $36 and $34)
Other receivables (less allowance for doubtful accounts of $2 and $3)
Inventories
Prepayments
Derivative assets
Deferred income taxes
Other
Total current assets
Investments
Nuclear decommissioning trust funds
Investment in equity method affiliates
Total investments
Property, Plant and Equipment
Property, plant and equipment
Accumulated depreciation, depletion and amortization
Total property, plant and equipment, net
Deferred Charges and Other Assets
Goodwill
Pension and other postretirement benefit assets
Regulatory assets
Total deferred charges and other assets
Total assets
8
CONSOLIDATED BALANCE SHEETS—(Continued)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year
Short-term debt
Accounts payable
Accrued interest, payroll and taxes
Other(2)
Total current liabilities
Long-Term Debt
Long-term debt
Junior subordinated notes
Remarketable subordinated notes
Total long-term debt
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits
Regulatory liabilities
Total deferred credits and other liabilities
Total liabilities
Commitments and Contingencies (see Note 16)
Equity
Common stock – no par(3)
Retained earnings
Accumulated other comprehensive loss
Total common shareholders’ equity
Noncontrolling interests
Total equity
Total liabilities and equity
9
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months Ended September 30,
Operating Activities
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)
Gains on the sale of assets and businesses
Charges associated with North Anna and offshore wind legislation
Other adjustments
Changes in:
Accounts receivable
Deferred fuel and purchased gas costs, net (including write-off)
Margin deposit assets and liabilities
Other operating assets and liabilities
Net cash provided by operating activities
Investing Activities
Plant construction and other property additions (including nuclear fuel)
Acquisition of solar development projects
Acquisition of DCG
Proceeds from sales of securities
Purchases of securities
Proceeds from the sale of electric retail energy marketing business
Proceeds from the sale of assets to Blue Racer
Proceeds from assignments of shale development rights
Net cash used in investing activities
Financing Activities
Issuance (repayment) of short-term debt, net
Issuance of long-term debt
Repayment and repurchase of long-term debt
Subsidiary preferred stock redemption
Issuance of common stock
Common dividend payments
Subsidiary preferred dividend payments
Net cash provided by financing activities
Decrease in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Supplemental Cash Flow Information
Significant noncash investing activities:(1)
Accrued capital expenditures
Dominion Midstream’s acquisition of a noncontrolling partnership interest in Iroquois in exchange for issuance of Dominion Midstream common units
10
VIRGINIA ELECTRIC AND POWER COMPANY
Operating Revenue(1)
Electric fuel and other energy-related purchases(1)
Other operations and maintenance:
Affiliated suppliers
Depreciation and amortization
Income before income tax expense
Net Income
Preferred dividends
Balance available for common stock
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
11
Net income
Net deferred losses on derivatives-hedging activities(1)
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds(2)
Net derivative (gains) losses-hedging activities(3)
Net realized gains on nuclear decommissioning trust funds(4)
Other comprehensive income (loss)
Comprehensive income
12
Customer receivables (less allowance for doubtful accounts of $27 and $25)
Other receivables (less allowance for doubtful accounts of $1 at both dates)
Inventories (average cost method)
Accumulated depreciation and amortization
13
LIABILITIES AND SHAREHOLDER’S EQUITY
Payables to affiliates
Affiliated current borrowings
Common Shareholder’s Equity
Other paid-in capital
Accumulated other comprehensive income
Total common shareholder’s equity
Total liabilities and shareholder’s equity
14
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)
Deferred fuel expenses, net (including write-off)
Plant construction and other property additions
Purchases of nuclear fuel
Issuance of short-term debt, net
Repayment of affiliated current borrowings, net
Repayment of long-term debt
Preferred stock redemption
Preferred dividend payments
Net cash provided by (used in) financing activities
Increase in cash and cash equivalents
Significant noncash investing activities:
15
DOMINION GAS HOLDINGS, LLC
Purchased gas(1)
Other energy-related purchases
Income from operations before income taxes
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
16
Net derivative (gains) losses-hedging activities(2)
Net pension and other postretirement benefit costs(3)
17
Customer receivables (less allowance for doubtful accounts of $5 and $4)(2)
Other receivables (less allowance for doubtful accounts of $1 at both dates)(2)
Affiliated receivables
Pension and other postretirement benefit assets(2)
18
Membership interests
Accumulated other comprehensive loss(2)
19
Gains on sales of assets
Deferred purchased gas costs, net
Proceeds from sale of assets to an affiliate
Issuance (repayment) of affiliated current borrowings, net
Distribution payments
Significant noncash investing and financing activities:
Extinguishment of affiliated long-term debt in exchange for assets sold to affiliate
20
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Nature of 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. Dominion Gas is a holding company that conducts business activities through a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution operations in Ohio, and gas gathering and processing activities primarily in West Virginia, Ohio and Pennsylvania. Dominion Gas’ principal wholly-owned subsidiaries are DTI, East Ohio and Dominion Iroquois.
Note 2. Significant Accounting Policies
As permitted by the rules and regulations of the SEC, the Companies’ accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with GAAP. These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.
In the Companies’ opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position as of September 30, 2015, their results of operations for the three and nine months ended September 30, 2015 and 2014, and their cash flows for the nine months ended September 30, 2015 and 2014. Such adjustments are normal and recurring in nature unless otherwise noted.
The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.
The Companies’ accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. As of September 30, 2015, Dominion owns the general partner and 63.1% of the limited partner interests in Dominion Midstream. The public’s ownership interest in Dominion Midstream is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. Also, as of September 30, 2015, Dominion owns 50% of the units in and consolidates Four Brothers and Three Cedars. SunEdison’s ownership interest in these projects is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. See Note 3 for more details regarding the nature and purpose of Four Brothers and Three Cedars.
The results of operations for interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, rate changes, electric fuel and other energy-related purchases, purchased gas expenses and other factors.
Certain amounts in the Companies’ 2014 Consolidated Financial Statements and Notes have been reclassified to conform to the 2015 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.
Amounts disclosed for Dominion are inclusive of Virginia Power and/or Dominion Gas, where applicable.
21
Note 3. Acquisitions and Dispositions
Dominion
Wholly-Owned Merchant Solar Projects
Acquisitions
The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion in 2014 and 2015. Long-term power purchase, interconnection and operation and maintenance agreements have been executed for all of the projects. Dominion has claimed and/or expects to claim federal investment tax credits on the projects. These projects are included in the Dominion Generation operating segment.
CompletedAcquisition Date
Seller
Project Name(s)
Date of
CommercialOperations
March 2014
November 2014
December 2014
April 2015
June 2015
July 2015
In June 2015, Dominion entered into an agreement to acquire 100% of the equity interests in the Maricopa West solar project in California from EC&R NA Solar PV, LLC for approximately $65 million in cash. The project is expected to close in the fourth quarter of 2015 and cost approximately $66 million once constructed, including the initial acquisition cost. Upon completion, the facility is expected to generate approximately 20 MW.
Expected 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 currently wholly-owned merchant solar projects to SunEdison for approximately $300 million. The potential sale relates to a total of 24 solar projects totaling approximately 425 MW. The sales of these interests are expected to close by the end of the first quarter of 2016.
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 approximately $64 million of consideration, consisting of $2 million in cash and a $62 million payable. As of September 30, 2015, a $56 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Four Brothers’ purpose is to develop and operate four solar projects located in Utah, which will produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $730 million to construct, including the initial acquisition cost. Dominion is obligated to contribute $445 million of capital to fund the construction of the projects. As of September 30, 2015, Dominion has contributed approximately $38 million. The facilities are expected to begin commercial operations in the third quarter of 2016, generating approximately 320 MW.
In September 2015, Dominion acquired 50% of the units in Three Cedars from SunEdison for approximately $43 million of consideration, consisting of $6 million in cash and a $37 million payable, which is included in other current liabilities in Dominion’s Consolidated Balance Sheets as of September 30, 2015. Three Cedars’ purpose is to develop and operate three solar projects located in Utah, which will produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $425 million to construct. Dominion is obligated to contribute $276 million of capital to fund the construction of the projects. The facilities are expected to begin commercial operations in the third quarter of 2016, generating approximately 210 MW.
22
Long-term power purchase, interconnection and operation and maintenance agreements have been executed for both Four Brothers and Three Cedars. Dominion expects to 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 approximately $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 approximately $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 non-recourse project financing and outside equity partners. The acquired assets of Four Brothers and Three Cedars are included in the Dominion Generation operating segment.
Four Brothers and Three Cedars have entered into agreements with SunEdison to provide administrative and support services in connection with the construction of the projects, operation and maintenance of the facilities, and administrative and technical management services of the solar facilities. In addition, Dominion has entered into contracts with SunEdison to provide services related to construction project management and oversight. Costs related to services to be provided under these agreements were immaterial for the nine months ended September 30, 2015.
Dominion Midstream Acquisition of Interest in Iroquois
In September 2015, Dominion Midstream acquired from NG and NJNR a 25.93% noncontrolling partnership interest in Iroquois, which owns and operates a 416-mile, FERC-regulated natural gas transmission pipeline in New York and Connecticut. In exchange for this partnership interest, Dominion Midstream issued approximately 8.6 million common units representing limited partnership interests in Dominion Midstream (approximately 6.8 million common units to NG for its 20.4% interest and approximately 1.8 million common units to NJNR for its 5.53% interest). The investment was recorded at approximately $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 24.72% partnership interest in Iroquois. Dominion Midstream and Dominion Gas each account for their interest in Iroquois as an equity method investment. See Notes 10 and 14 for more information regarding Iroquois.
In January 2015, Dominion completed the acquisition of 100% of the equity interests of DCG from SCANA Corporation for approximately $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 Southeast. The allocation of the purchase price resulted in approximately $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 approximately $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 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 a two-year, approximately $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.
Sale of Electric Retail Energy Marketing Business
In March 2014, Dominion completed the sale of its electric retail energy marketing business. The proceeds were approximately $187 million, net of transaction costs. The sale resulted in a gain, subject to post-closing adjustments, of approximately $100 million ($57 million after-tax) net of a $31 million write-off of goodwill, and is included in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. The sale of the electric retail energy marketing business did not qualify for discontinued operations classification.
23
Virginia Power
Acquisition of Solar Project
In September 2015, Virginia Power entered into an agreement to acquire 100% of a solar development project in North Carolina from Morgans Corner for approximately $47 million. The acquisition is expected to close in the fourth quarter of 2015. The project is expected to be placed into service by the end of the first quarter of 2016 and cost approximately $50 million once constructed, including the initial acquisition cost. Upon completion, the facility is expected to generate approximately 20 MW. The output generated by Morgans Corner will be used to meet a ten year non-jurisdictional supply agreement with the U.S. Navy, which has the unilateral option to extend for an additional ten years. In October 2015, the North Carolina Commission granted the transfer of the existing CPCN from Morgans Corner to Virginia Power. The acquired assets will be included in the Virginia Power Generation operating segment.
Dominion Gas
Assignments of Shale Development Rights
In December 2013, DTI closed an agreement with a natural gas producer to convey over time approximately 79,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provided for payments to DTI, subject to customary adjustments, of up to approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013 and 2014, DTI received approximately $98 million in cash proceeds. At December 31, 2014, deferred revenue totaled approximately $85 million. In March 2015, DTI and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of approximately 9,000 acres of Marcellus Shale development rights and a two year extension of the term of the original agreement. The conveyance of development rights resulted in the recognition of $43 million ($27 million after-tax) of previously deferred revenue to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. At September 30, 2015, deferred revenue totaled approximately $38 million, which is expected to be recognized over the remaining term of the agreement.
In March 2015, DTI 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 approximately $27 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in a $27 million ($16 million after-tax) gain, included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.
In September 2015, DTI 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 DTI, subject to customary adjustments, of approximately $52 million and an overriding royalty interest in gas produced from the acreage. In September 2015, DTI received proceeds of $52 million associated with the conveyance of the acreage, resulting in a $52 million ($29 million after-tax) gain, included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.
Dominion and Dominion Gas
Blue Racer
See Note 10 for a discussion of transactions related to Blue Racer.
24
Note 4. Operating Revenue
The Companies’ operating revenue consists of the following:
Electric sales:
Regulated
Nonregulated
Gas sales:
Gas transportation and storage
Total operating revenue
Regulated electric sales
NGL revenue
Note 5. Income Taxes
For continuing operations, including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows:
U.S. statutory rate
Increases (reductions) resulting from:
State taxes, net of federal benefit
Investment tax credits
Production tax credits
Other, net
Effective tax rate
As of September 30, 2015, there have been no material changes in the Companies’ unrecognized tax benefits or possible changes that could reasonably be expected to occur during the next twelve months. See Note 5 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 for a discussion of these unrecognized tax benefits.
25
Note 6. Earnings Per Share
The following table presents the calculation of Dominion’s basic and diluted EPS:
Net income attributable to Dominion
Average shares of common stock outstanding – Basic
Net effect of dilutive securities(1)
Average shares of common stock outstanding – Diluted
Earnings Per Common Share – Basic
Earnings Per Common Share – Diluted
The 2014 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2015 and 2014, as the dilutive stock price threshold was not met.
26
Note 7. Accumulated Other Comprehensive Income
The following table presents Dominion’s changes in AOCI by component, net of tax:
Three Months Ended September 30, 2015
Beginning balance
Other comprehensive income before reclassifications: gains (losses)
Amounts reclassified from AOCI(1): (gains) losses
Net current-period other comprehensive income (loss)
Ending balance
Three Months Ended September 30, 2014
Nine Months Ended September 30, 2015
Nine Months Ended September 30, 2014
The following table presents Dominion’s reclassifications out of AOCI by component:
Details about AOCI components
Affected line item in the Consolidated Statements ofIncome
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts
Interest rate contracts
Tax
27
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities
Impairment
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs
Actuarial (gains) losses
28
29
The following table presents Dominion Gas’ changes in AOCI by component, net of tax:
Net current-period other comprehensive income
30
The following table presents Dominion Gas’ reclassifications out of AOCI by component:
Affected line item in the Consolidated Statementsof Income
31
Note 8. Fair Value Measurements
The Companies’ fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. See Note 9 in this report for further information about the Companies’ derivatives and hedge accounting activities.
The Companies enter into certain physical and financial forwards, futures, options and swaps, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards and futures contracts. An option model is used to value Level 3 physical and financial options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices, and volumes. For Level 3 fair value measurements, forward market prices, credit spreads and implied price volatilities are considered unobservable. The unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.
The following table presents Dominion’s quantitative information about Level 3 fair value measurements at September 30, 2015. The range and weighted average are presented in dollars for market price inputs and percentages for credit spreads and price volatility.
Assets:
Physical and Financial Forwards and Futures:
Natural Gas(2)
Liquids(3)
Electric
FTRs
Physical and Financial Options:
Natural Gas
Liabilities:
32
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Significant Unobservable Inputs
Position
Change to Input
Impact on FairValue Measurement
33
Recurring Fair Value Measurements
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:
At September 30, 2015
Derivatives:
Commodity
Interest rate
Investments(1):
Equity securities:
U.S.:
Large cap
REIT
Non-U.S.:
Fixed income:
Corporate debt instruments
U.S. Treasury securities and agency debentures
State and municipal
Cash equivalents and other
At December 31, 2014
34
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:
Total realized and unrealized gains (losses):
Included in earnings
Included in other comprehensive income (loss)
Included in regulatory assets/liabilities
Settlements
Transfers out of Level 3(1)
The amount of gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date
35
The following table presents Dominion’s classification of gains and losses included in earnings in the Level 3 fair value category:
Total gains (losses) included in earnings
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date
The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at September 30, 2015. The range and weighted average are presented in dollars for market price inputs and percentages for credit spreads and price volatility.
36
37
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:
U.S. large cap
38
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 were classified in electric fuel and other energy-related purchases in Virginia Power’s Consolidated Statements of Income for the three and nine months ended September 30, 2015 and 2014. There were no unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and nine months ended September 30, 2015 and 2014.
The following table presents Dominion Gas’ quantitative information about Level 3 fair value measurements at September 30, 2015. The range and weighted average are presented in dollars for market price inputs and percentages for credit spreads.
NGLs
39
The following table presents Dominion Gas’ assets and liabilities for derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
Total Assets
The following table presents the net change in Dominion Gas’ assets and liabilities for derivatives 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 three and nine months ended September 30, 2015 and 2014. There were no unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and nine months ended September 30, 2015 and 2014.
40
Fair Value of Financial Instruments
Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, restricted cash (which is recorded in other current assets), customer and other receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies’ financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:
Long-term debt, including securities due within one year(2)(3)
Junior subordinated notes(3)
Remarketable subordinated notes(3)
Long-term debt, including securities due within one year(3)
Long-term debt(3)
Note 9. Derivatives and Hedge Accounting Activities
The Companies’ accounting policies and objectives and strategies for using derivative instruments are discussed in Note 2 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. See Note 8 in this report for further information about fair value measurements and associated valuation methods for derivatives.
Derivative assets and liabilities are presented gross on the Companies’ Consolidated Balance Sheets. Dominion’s derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Dominion Gas’ and Virginia Power’s derivative contracts consist of over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a counterparty. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions.
In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and in some cases other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on the Companies’ Consolidated Balance Sheets, as well as letters of credit and other forms of security, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure.
41
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:
Interest rate contracts:
Over-the-counter
Commodity contracts:
Exchange
Total derivatives, subject to a master netting or similar arrangement
Total derivatives, not subject to a master netting or similar arrangement
Total
42
Volumes
The following table presents the volume of Dominion’s derivative activity as of September 30, 2015. 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.
Natural Gas (bcf):
Fixed price(1)
Basis
Electricity (MWh):
Fixed price
Capacity (MW)
Liquids (Gal)(2)
Ineffectiveness and AOCI
For the three and nine months ended September 30, 2015 and 2014, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.
The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at September 30, 2015:
Commodities:
Gas
Electricity
43
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.
44
Fair Value and Gains and Losses on Derivative Instruments
The following table presents the fair values of Dominion’s derivatives and where they are presented in its Consolidated Balance Sheets:
Total current derivative assets
Noncurrent Assets
Total noncurrent derivative assets(1)
Total derivative assets
LIABILITIES
Total current derivative liabilities(2)
Noncurrent Liabilities
Interest Rate
Total noncurrent derivative liabilities(3)
Total derivative liabilities
45
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:
Derivatives in cash flow hedging relationships
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue
Total commodity
Interest rate(3)
46
Derivatives not designated as hedging instruments
Interest rate(2)
The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:
47
The following table presents the volume of Virginia Power’s derivative activity as of September 30, 2015. 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
For the three and nine months ended September 30, 2015 and 2014, gains or losses on hedging instruments determined to be ineffective were not material.
48
The following table presents the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated
Balance Sheets:
Total current derivative assets(1)
Total noncurrent derivative assets(2)
Total current derivative liabilities(3)
Total noncurrent derivatives liabilities (4)
Total noncurrent derivative liabilities(4)
49
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:
Commodity(2)
50
The tables below present Dominion Gas’ derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting.
51
The following table presents the volume of Dominion Gas’ derivative activity as of September 30, 2015. 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.
NGLs (Gal)
The following table presents selected information related to losses on cash flow hedges included in AOCI in Dominion Gas’ Consolidated Balance Sheet at September 30, 2015:
52
The following tables present the fair values of Dominion Gas’ commodity and interest rate derivatives and where they are presented in its Consolidated Balance Sheets:
53
The following table presents 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:
54
Note 10. Investments
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 $96 million and $110 million at September 30, 2015 and December 31, 2014, respectively. Cost method investments held in Dominion’s rabbi trusts totaled $4 million and $6 million at September 30, 2015 and December 31, 2014, respectively.
Decommissioning Trust Securities
Dominion holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below:
Marketable equity securities:
Marketable debt securities:
Corporate bonds
Cost method investments
Cash equivalents and other(2)
55
The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2015 by contractual maturity is as follows:
Due in one year or less
Due after one year through five years
Due after five years through ten years
Due after ten years
Presented below is selected information regarding Dominion’s marketable equity and debt securities held in nuclear decommissioning trust funds.
Proceeds from sales
Realized gains(1)
Realized losses(1)
Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:
Total other-than-temporary impairment losses (1)
Losses recorded to nuclear decommissioning trust regulatory liability
Losses recognized in other comprehensive income (before taxes)
Net impairment losses recognized in earnings
56
Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below:
The fair value of Virginia Power’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2015 by contractual maturity is as follows:
57
Presented below is selected information regarding Virginia Power’s marketable equity and debt securities held in nuclear decommissioning trust funds.
Other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds for Virginia Power were not material for the three and nine months ended September 30, 2015 and 2014.
Equity Method Investments
Iroquois
At September 30, 2015, Dominion Midstream used the equity method to account for its 25.93% noncontrolling partnership interest in Iroquois. At September 30, 2015, the carrying amount of Dominion Midstream’s investment of $216 million exceeded its share of underlying equity in net assets by approximately $122 million. The difference reflects equity method goodwill and is not being amortized.
Dominion Gas’ equity earnings on its 24.72% non-controlling partnership interest totaled $17 million for both the nine months ended September 30, 2015 and 2014. Dominion Gas received distributions from this investment of $26 million and $10 million for the nine months ended September 30, 2015 and 2014, respectively. At September 30, 2015 and December 31, 2014, the carrying amount of Dominion Gas’ investment of $98 million and $107 million, respectively, exceeded its share of underlying equity in net assets by approximately $8 million at both dates. The difference reflects equity method goodwill and is not being amortized.
In December 2012, Dominion formed Blue Racer with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. Blue Racer is an equal partnership between Dominion and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital.
Dominion NGL Pipelines, LLC was contributed in January 2014 by Dominion to Blue Racer, prior to commencement of service, resulting in an increased equity method investment of $155 million, including $6 million of goodwill allocated from Dominion’s goodwill balance to its equity method investment in Blue Racer.
In March 2014, Dominion Gas sold the Northern System to an affiliate, that subsequently sold the Northern System to Blue Racer for consideration of approximately $84 million. Dominion Gas’ consideration consisted of $17 million in cash proceeds and the extinguishment of affiliated long-term debt of $67 million and Dominion’s consideration consisted of cash proceeds of approximately $84 million. The sale resulted in a gain of approximately $59 million ($35 million after-tax for Dominion Gas and $34 million after-tax for Dominion) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statements of Income.
Note 11. Regulatory Assets and Liabilities
Regulatory assets and liabilities include the following:
Regulatory assets:
Deferred cost of fuel used in electric generation(1)
Deferred rate adjustment clause costs(2)
Deferred nuclear refueling outage costs(3)
58
Unrecovered gas costs(4)
Regulatory assets-current(5)
Unrecognized pension and other postretirement benefit costs(6)
Income taxes recoverable through future rates(7)
Derivatives(8)
Regulatory assets-non-current
Total regulatory assets
Regulatory liabilities:
PIPP(9)
Regulatory liabilities-current(10)
Provision for future cost of removal and AROs(11)
Nuclear decommissioning trust(12)
Regulatory liabilities-non-current
Total regulatory liabilities
Regulatory assets-current
Provision for future cost of removal(11)
59
Regulatory assets-non-current(13)
Regulatory liabilities-non-current(14)
At September 30, 2015, approximately $120 million of Dominion’s, $91 million of Virginia Power’s and $27 million of Dominion Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. These expenditures are expected to be recovered within the next two years.
Note 12. Regulatory Matters
Regulatory Matters Involving Potential Loss Contingencies
As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For matters for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed
60
sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.
FERC - Electric
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 and ISO-NE wholesale markets, and to wholesale purchasers in the states of Tennessee, Georgia and California under Dominion’s market-based sales tariffs authorized by FERC. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in the wholesale market. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.
Rates
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.
In March 2010, ODEC and NCEMC filed a complaint with FERC against Virginia Power claiming that approximately $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. In February 2012, Virginia Power submitted to FERC a settlement agreement to resolve all issues set for hearing. The settlement was accepted by FERC in May 2012 and provides for payment by Virginia Power to the transmission customer parties collectively of $250,000 per year for ten years and resolves all matters other than allocation of the incremental cost of certain underground transmission facilities.
In March 2014, FERC issued an order excluding from Virginia 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 for non-Virginia wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities because the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to benefit the citizens of Virginia. The order is retroactively effective as of March 2010 and will cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC determined that there was not sufficient evidence on the record to determine the magnitude of the underground increment and held a hearing to determine the appropriate amount of undergrounding cost to be allocated to each wholesale transmission customer in Virginia. While Virginia Power cannot predict the outcome of the hearing, it is not expected to have a material effect on results of operations.
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
61
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. Settlement discussions are ongoing. Virginia Power anticipates that the majority of the impacts of any rate design changes resulting from the settlement discussions will be recoverable through retail rates in Virginia.
Other Regulatory Matters
Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015.
Virginia Regulation
Biennial Review
In connection with its current biennial review of Virginia Power’s base rates, terms and conditions, the Virginia Commission is reviewing Virginia Power’s earnings on its rates for generation and distribution services for the combined 2013 and 2014 test periods, and determining whether credits are due to customers in the event Virginia Power’s earnings exceeded the authorized ROE band of 9.3% to 10.7%. In September 2015, the Virginia Commission conducted an evidentiary hearing related to the biennial review. In its testimony, the Virginia Commission staff proposed making several regulatory adjustments to Virginia Power’s earnings. If the Virginia Commission were to accept all of these proposed adjustments, Virginia Power would have earned an ROE of 11.34% during the 2013 and 2014 test years, resulting in a total credit to customers of approximately $65 million. Virginia Power believes that the adjustments proposed by the Virginia Commission staff were improper and inconsistent with prior regulatory precedent. Virginia Power demonstrated that its costs, revenues and investments for the combined test periods resulted in an earned return of 10.13%, which is within the allowed range. Due to the uncertainty surrounding the Virginia Commission’s final ruling expected to be issued by the end of November 2015, Virginia Power has not recognized a liability related to the staff’s recommendation as of September 30, 2015.
Virginia Fuel Expenses
In August 2015, the Virginia Commission approved Virginia Power’s annual fuel factor filing to recover an estimated $1.6 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2015. Virginia Power’s new approved fuel rate, in effect on an interim basis since April 1, 2015, represents a fuel revenue decrease of approximately $512 million when applied to projected kilowatt-hour sales for the period April 1, 2015 to June 30, 2016.
Remington Solar Facility
In January 2015, Virginia Power applied for a CPCN to construct and operate a 20 MW utility-scale solar facility near its existing Remington Power Station in Fauquier County, Virginia. Virginia Power also applied for approval of Rider US-1 to recover the costs of the facility. In October 2015, the Virginia Commission denied approval of the CPCN and Rider US-1 based on the evidence in the record but stated that an application could be re-filed to address the concerns cited by the Virginia Commission. Virginia Power is reviewing the order and assessing its options.
Rate Adjustment Clauses
Below is a discussion of significant riders associated with various Virginia Power projects:
North Anna
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. The COL is expected in 2017. Virginia Power has not yet committed to building a new nuclear unit at North Anna.
62
The motions and petitions filed by BREDL prior to April 2015 have been dismissed, and under a previous ruling of the NRC, the contested portion of the COL proceeding remains terminated. The NRC is required to conduct a hearing in all COL proceedings, and if a new contention is not admitted, the mandatory NRC hearing will be uncontested.
In April 2015, BREDL filed a new motion and petition seeking to object to the NRC’s reliance on the continued storage rule in licensing proceedings. The BREDL filings are substantially the same as those filed in other COL proceedings in which final environmental impact statements were issued prior to promulgation of the continued storage rule, like North Anna 3. In June 2015, the NRC denied the April 2015 motion and petition.
In August 2015, BREDL filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking review of the NRC’s June 2015 decision. Along with the petition for judicial review, BREDL also filed a motion to hold this judicial review in abeyance pending the outcome of the ongoing judicial review of the NRC’s rule pertaining to the continued onsite storage of spent nuclear fuel in litigation pending before the same court. Similar petitions were filed seeking judicial review of the NRC’s decision as it applies to other COL and license renewal proceedings. Virginia Power has filed a motion with the court to intervene in the proceeding. This case is pending.
North Carolina Regulation
In August 2015, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed an approximately $11 million decrease to the fuel component of its electric rates for the rate year beginning January 1, 2016. This decrease includes the North Carolina Commission’s previous approval to defer recovering 50% of Virginia Power’s estimated $17 million jurisdictional deferred fuel balance to the 2016 fuel year, without interest. This case is pending.
FERC - Gas
In August 2015, FERC approved DTI’s Clarington Project, which is expected to cost approximately $80 million. The project is expected to provide 250,000 Dths per day of firm transportation service from central West Virginia to Clarington, Ohio. Construction is expected to commence in the fourth quarter of 2015 and to be placed into service in the fourth quarter of 2016.
In October 2015, Cove Point received authorization to construct the approximately $30 million St. Charles Transportation Project and the approximately $40 million Keys Energy Project. Construction on each project is expected to commence in the fourth quarter of 2015. The St. Charles Transportation project is anticipated to be placed into service in June 2016. The Keys Energy Project is anticipated to be placed into service in March 2017.
Note 13. Asset Retirement Obligations
AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of the Companies’ long-lived assets. Dominion’s and Virginia Power’s AROs are primarily associated with the decommissioning of their nuclear generation facilities and also include those for ash pond closures and the future abatement of asbestos expected to be disturbed in their generation facilities. Dominion Gas’ AROs primarily include plugging and abandonment of gas and oil wells and the interim retirement of natural gas gathering, transmission, distribution and storage pipeline components.
The Companies have also identified, but not recognized, AROs related to retirement of Dominion’s LNG facility, Dominion Gas’ storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in Dominion’s and Virginia Power’s generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs for Dominion and Virginia Power during 2014 and 2015 are presented below. There were no significant changes to Dominion Gas’ AROs.
63
AROs at December 31, 2013(1)
Obligations incurred during the period
Obligations settled during the period
Revisions in estimated cash flows(2)
Accretion
AROs at December 31, 2014(1)
Obligations incurred during the period(3)
Revisions in estimated cash flows(3)
AROs at September 30, 2015(1)
AROs at December 31, 2013
AROs at December 31, 2014(4)
AROs at September 30, 2015(4)
Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At September 30, 2015 and December 31, 2014, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $4.0 billion and $4.2 billion, respectively. At September 30, 2015 and December 31, 2014, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.9 billion.
Note 14. Variable Interest Entities
As discussed in Note 15 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, certain variable pricing terms in some of the Companies’ contracts cause them to be considered variable interests in the counterparties.
Dominion Midstream and Dominion Gas own a 25.93% and 24.72% noncontrolling partnership interest in Iroquois, respectively. See Note 3 for further details regarding the nature of this entity. Dominion concluded that Iroquois is a VIE because a non-affiliated Iroquois equity holder has the ability during a limited period of time to transfer its ownership interests to another Iroquois equity holder or its affiliate. At September 30, 2015, Dominion concluded that neither Dominion Midstream
64
nor Dominion Gas is the primary beneficiary of Iroquois as they do not have the power to direct the activities of Iroquois that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. If Iroquois determines capital contributions are required, Dominion Midstream and Dominion Gas each would be obligated to provide the portion of capital contributions based on its ownership percentage. Dominion Midstream’s and Dominion Gas’ maximum exposure to loss is limited to its current and future investment.
Virginia Power has long-term power and capacity contracts with five non-utility generators with an aggregate summer generation capacity of approximately 870 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $478 million as of September 30, 2015. Virginia Power paid $52 million and $55 million for electric capacity and $17 million and $28 million for electric energy to these entities in the three months ended September 30, 2015 and 2014, respectively. Virginia Power paid $160 million and $166 million for electric capacity and $77 million and $115 million for electric energy to these entities in the nine months ended September 30, 2015 and 2014, respectively.
Virginia Power and Dominion Gas
Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of approximately $73 million and $27 million for the three months ended September 30, 2015, $82 million and $27 million for the three months ended September 30, 2014, $239 million and $85 million for the nine months ended September 30, 2015, and $246 million and $78 million for the nine months ended September 30, 2014, respectively. Virginia Power and Dominion Gas determined that each is not the most closely associated entity with DRS and therefore neither is the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power and Dominion Gas. Virginia Power and Dominion Gas have no obligation to absorb more than their allocated shares of DRS costs.
Note 15. Significant Financing Transactions
Credit Facilities and Short-term Debt
The Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.
At September 30, 2015, Dominion’s commercial paper and letters of credit outstanding, as well as its capacity available under credit facilities, were as follows:
Joint revolving credit facility(1)
Virginia Power’s short-term financing is supported through its access as co-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.
65
At September 30, 2015, Virginia Power’s share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion and Dominion Gas, were as follows:
In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility with a maturity date of April 2019. As of September 30, 2015, this facility supports approximately $119 million of certain variable rate tax-exempt financings of Virginia Power.
Dominion Gas’ short-term financing is supported by its access as co-borrower to the two joint revolving credit facilities. In December 2014, Dominion Gas entered into a commercial paper program pursuant to which it began accessing the commercial paper markets in January 2015.
At September 30, 2015, Dominion Gas’ share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion and Virginia Power were as follows:
Long-term Debt
In May 2015, Virginia Power issued $350 million of 3.10% senior notes and $350 million of 4.20% senior notes that mature in 2025, and 2045, respectively.
In June 2015, Dominion issued $500 million of 1.90% senior notes that mature in 2018.
At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 were subject to redemption at 100% of the principal amount plus accrued interest in August 2015. As a result, at December 31, 2014, the notes were included in securities due within one year in Dominion’s Consolidated Balance Sheets. The option to redeem the notes expired in June 2015. As of September 30, 2015, the notes were included in long-term debt in Dominion’s Consolidated Balance Sheets.
In August 2015, Virginia Power remarketed five series of tax-exempt bonds, with an aggregate outstanding principal of $412 million to new investors. Two of the bonds will bear interest at a coupon rate of 1.75% for the first four years after which they will bear interest at a market rate to be determined at that time. Three of the bonds will bear interest at a coupon rate of 2.15% for the first five years after which they will bear interest at a market rate to be determined at that time. Previously, interest on all of the remarketed bonds was variable and reset monthly. This remarketing was accounted for as a debt extinguishment with the previous investors.
66
In September 2015, Dominion issued $650 million of 3.90% senior notes that mature in 2025.
Issuance of Common Stock
Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2014, Dominion began purchasing its common stock on the open market for these plans. In April 2014, Dominion began issuing new common shares for these direct stock purchase plans.
In December 2014, Dominion filed an SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at-the-market program. Also in December 2014, Dominion entered into four separate sales agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion and the sales agents and in conformance with applicable securities laws. During the first quarter of 2015, Dominion provided sales instructions to the sales agents and issued 2.9 million shares through at-the-market issuances and received cash proceeds of approximately $219 million, net of fees and commissions paid of approximately $2 million. During the second quarter of 2015, Dominion provided sales instructions to the sales agents and issued 1.1 million shares through at-the-market issuances and received cash proceeds of approximately $78 million, net of fees and commissions paid of approximately $1 million. Following these issuances, Dominion has the ability to issue up to approximately $200 million of stock under the 2014 sales agency agreements. However, Dominion completed its 2015 planned market issuances of equity in May 2015 with the issuance of 2.8 million shares and receipt of proceeds of approximately $202 million through a registered underwritten public offering. Dominion has no current plans to issue to the market any additional shares of its common stock or other equity-linked securities in 2015.
Note 16. Commitments and Contingencies
As a result of issues generated in the ordinary course of business, the Companies are involved in legal proceedings before various courts and are periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial position, liquidity or results of operations of the Companies.
Environmental Matters
The Companies are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.
Air
The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the 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 the Companies’ facilities are subject to the CAA’s permitting and other requirements.
In December 2011, the EPA issued MATS for coal- and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an
67
exemption from emission limits, and allows compliance with operational work practice standards. Compliance was required by April 16, 2015, with certain limited exceptions. However, in June 2014, the VDEQ granted a one-year MATS compliance extension for two coal-fired units at Yorktown to defer planned retirements and allow for continued operation of the units to address reliability concerns while necessary electric transmission upgrades are being completed. These coal units will need to continue operating until at least April 2017 due to delays in transmission upgrades needed to maintain electric reliability, which based on assumptions about the timing for required agency actions and construction schedules are expected to be completed by no earlier than the second quarter of 2017. Therefore, in October 2015 Virginia Power submitted a request to the EPA for an additional one year compliance extension under an EPA Administrative Order.
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- and oil-fired plants, and remanded the MATS rule back to the D.C. Circuit Court. However, the Supreme Court did not vacate or stay the effective date and implementation of the MATS rule. Therefore, the Supreme Court’s decision does not change Dominion’s plans to close coal units at Yorktown or the need to complete necessary electricity transmission upgrades by 2017. At this time, Dominion intends to proceed as scheduled, pending further action regarding the MATS rule by the D.C. Circuit Court.
The EPA established CAIR with the intent to require significant reductions in SO2 and NOx emissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO2 and NOx emissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO2 and NOx emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NOx emissions caps, NOx emissions caps during the ozone season (May 1 through September 30) and annual SO2 emission caps with differing requirements for two groups of affected states.
Following numerous petitions by industry participants for review and a successful motion for stay, in October 2014, the U.S. Court of Appeals for the D.C. Circuit ordered that the EPA’s motion to lift the stay of CSAPR be granted. Further, the Court granted the EPA’s request to shift the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets (which would have gone into effect in 2012 and 2013) will apply in 2015 and 2016, and Phase 2 emissions budgets will apply in 2017 and beyond. CSAPR replaced CAIR beginning in January 2015. The cost to comply is not expected to be material to the Consolidated Financial Statements. Future outcomes of any additional litigation and/or any action to issue a revised rule could affect the assessment regarding cost of compliance.
In October 2015, the EPA issued a final rule tightening the ozone standard from 75 ppb to 70 ppb. 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 plans to address the new standard. Until the states have developed implementation plans, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significant expenditures are required to implement additional controls, it could adversely affect the Companies’ results of operations and cash flows.
In August 2010, the EPA issued revised National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. The rule was amended in March 2011 and January 2013. The rule establishes emission standards for control of hazardous air pollutants for engines at smaller facilities, known as area sources. As a result of these regulations, Dominion Gas installed emissions controls on several compressor engines. Dominion Gas has spent approximately $2 million to date and is evaluating further expenditures. Dominion Gas is unable to estimate the additional potential impacts on results of operations, financial condition and/or cash flows related to this matter.
In August 2012, the EPA issued the first NSPS impacting the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In September 2015, the EPA issued a proposed NSPS to regulate methane and VOC emissions from transmission and storage, gathering and boosting, production and processing facilities. All projects which commence construction after September 2015 will be required to comply with this regulation. Dominion is evaluating the proposed regulation and cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.
In January 2015, as part of its Climate Action Plan, the EPA announced plans to reduce methane emissions from the oil and gas sector including natural gas processing and transmission sources. In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR program, the Natural Gas STAR Methane Challenge Program. The proposed program covers the entire natural gas sector from production to distribution, with more emphasis on transparency and increased reporting for both
68
annual emissions and reductions achieved through implementation measures. Dominion is evaluating the proposed program and cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.
Water
The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The Companies must comply with applicable aspects of the CWA programs at their operating facilities.
In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. While the impacts of this rule could be material to Dominion’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.
In September 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 wastewater treatment technologies in order to meet the new discharge limits. Dominion has seven facilities that may be subject to additional wastewater treatment requirements associated with the final rule. The expenditures to comply with these new requirements are expected to be material.
Solid and Hazardous Waste
The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.
From time to time, Dominion, Virginia Power, or Dominion Gas may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion, Virginia Power, or Dominion Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. Except as noted below, the Companies do not believe this will have a material effect on results of operations, financial condition and/or cash flows.
In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. In November 2011, Virginia Power and a number of other parties notified the EPA that they are declining to undertake the work set forth in the UAO.
The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO. Virginia Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter.
69
Dominion has determined that it is associated with 17 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion Gas. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which the Companies are associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post-closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.
See below for discussion on ash pond closure costs.
Climate Change Legislation and Regulation
In October 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the D.C. Circuit Court’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 July 2014, the EPA issued a memorandum specifying that it will no longer apply or enforce federal regulations or EPA-approved PSD state implementation plan provisions that require new and modified stationary sources to obtain a PSD permit when GHGs are the only pollutant that would be emitted at levels that exceed the permitting thresholds. In August 2015, the EPA published a final rule rescinding the requirement for all new and modified major sources to obtain permits based solely on their GHG emissions. In addition, the EPA stated that it will continue to use the existing thresholds to apply to sources that are otherwise subject to PSD for conventional pollutants until it completes a new rulemaking either justifying and upholding those thresholds or setting new ones. Some states have issued interim guidance that follows the EPA guidance. Due to uncertainty regarding what additional actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the court ruling under a new rulemaking, the Companies cannot predict the impact to their financial statements at this time.
In July 2011, the EPA signed a final rule deferring the need for PSD and Title V permitting for CO2 emissions for biomass projects. This rule temporarily deferred for a period of up to three years the consideration of CO2 emissions from biomass projects when determining whether a stationary source meets the PSD and Title V applicability thresholds, including those for the application of BACT. The deferral policy expired in July 2014. In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however, a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the CO2 deferral period. It is unclear how the 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.
Other Legal Matters
The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.
Appalachian Gateway
Following the completion of the Appalachian Gateway Project in 2012, DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DTI filed a complaint in U.S. District Court 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. This case is pending. DTI has accrued a liability of approximately $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.
70
Ash Pond Closure Costs
In September 2014, Virginia Power received a notice from the SELC on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at Possum Point. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point’s historical and active ash storage facilities. A similar notice from the SELC on behalf of the Sierra Club was subsequently received related to Chesapeake. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum Point, Chesapeake and Bremo as settlement of the potential litigation. While the issue is open to potential further negotiations, the SELC declined the offer as presented in January 2015 and, in March 2015, filed a lawsuit related to its claims of the alleged CWA violations at Chesapeake. Virginia Power filed a motion to dismiss in April 2015. A ruling on the motion is pending. As a result of the settlement offer, Virginia Power recognized a charge of $121 million in other operations and maintenance expense in its Consolidated Statements of Income in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.
In April 2015, the EPA’s final rule regulating the management of CCRs stored in impoundments (ash ponds) and landfills was published in the Federal Register. The final rule regulates CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store CCRs. Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. The enactment of the final rule in April 2015 created a legal obligation for Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary. In the second quarter of 2015, Virginia Power recorded a $325 million ARO related to future ash pond and landfill closure costs. Recognition of the ARO also resulted in a $45 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $159 million increase in property, plant, and equipment associated with asset retirement costs, and a $121 million reduction in other noncurrent liabilities related to reversal of the contingent liability described above since the ARO obligation created by the final CCR rule represents similar activities. Dominion is in the process of obtaining the necessary permits to complete the work. The actual asset retirement costs related to the CCR rule may vary substantially from the estimates used to record the increased obligation in the second quarter, due to compliance requirements that may be imposed by the various state regulators.
Nuclear Matters
In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as INPO. Like other U.S. nuclear operators, Dominion has been gathering supporting data and participating in industry initiatives focused on the ability to respond to and mitigate the consequences of design-basis and beyond-design-basis events at its stations.
In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011, the NRC staff prioritized these recommendations into Tiers 1, 2 and 3, with the Tier 1 recommendations consisting of actions which the staff determined should be started without unnecessary delay. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.
Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion require implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation. The orders require prompt implementation of the safety enhancements and completion of implementation within two refueling outages or by December 31, 2016, whichever comes first. Implementation of these enhancements is currently in progress. The information requests issued by the NRC request each reactor to reevaluate the seismic and flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. Dominion and Virginia Power do not currently expect that compliance with the NRC’s March 2012 orders and information requests will materially impact their financial position, results of operations or cash flows during the approximately four-year implementation period. The NRC staff is evaluating the implementation of the longer-term Tier 2 and Tier 3 recommendations. Dominion and Virginia Power are currently unable to estimate the potential financial impacts related to compliance with Tier 2 and Tier 3 recommendations.
71
Guarantees, Surety Bonds and Letters of Credit
At September 30, 2015, Dominion had issued $74 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of September 30, 2015, Dominion’s exposure under these guarantees was $39 million, primarily related to certain reserve requirements associated with non-recourse financing.
Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.
At September 30, 2015, Dominion had issued the following subsidiary guarantees:
Subsidiary debt(2)
Commodity transactions(3)
Nuclear obligations(4)
Cove Point(5)
Solar(6)
Other(7)
Additionally, at September 30, 2015, Dominion had purchased $91 million of surety bonds, including $31 million at Virginia Power and $23 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $57 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.
Note 17. Credit Risk
The Companies’ accounting policies for credit risk are discussed in Note 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.
72
At September 30, 2015, Dominion’s credit exposure related to energy marketing and price risk management activities totaled $195 million. Of this amount, investment grade counterparties, including those internally rated, represented 64%. No single counterparty, whether investment grade or non-investment grade, exceeded $35 million of exposure.
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 rating 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 September 30, 2015 and December 31, 2014, Dominion would have been required to post an additional $14 million and $20 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion had not posted any collateral at September 30, 2015 related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. Dominion had posted approximately $1 million in collateral at December 31, 2014 related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of September 30, 2015 and December 31, 2014 was $32 million and $49 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and Dominion Gas were not material as of September 30, 2015 and December 31, 2014. See Note 9 for further information about derivative instruments.
In the third quarter of 2015, DTI provided service to 244 customers with approximately 95% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 45% of total storage and transportation revenue and the thirty largest provided approximately 72% of total storage and transportation revenue. Approximately 98% of the transmission capacity under contract on DTI’s pipeline is subscribed with long-term contracts (two years or greater). The remaining 2% is contracted on a year-to-year basis. Less than 1% of firm transportation capacity is currently unsubscribed. More than 99% of DTI’s storage capacity is under long-term contracts with less than 1% currently unsubscribed.
East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates approved by the Ohio Commission. Approximately 99% of East Ohio revenues are derived from its jurisdictional gas services. East Ohio’s bad debt risk is mitigated by the regulatory framework established by the Ohio Commission.
Note 18. Related Party Transactions
Virginia Power and Dominion Gas engage in related party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s and Dominion Gas’ receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power and Dominion Gas are included in Dominion’s consolidated federal income tax return. A discussion of significant related party transactions follows.
Transactions with Affiliates
Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps, to manage commodity price risks associated with purchases of natural gas. As of September 30, 2015, Virginia Power’s derivative assets and liabilities with affiliates were $22 million and $4 million, respectively. As of December 31, 2014, Virginia Power’s derivative assets and liabilities with affiliates were not material. See Notes 7 and 9 for more information.
Virginia Power participates in certain Dominion benefit plans described in Note 19. In Virginia Power’s Consolidated Balance Sheets at September 30, 2015 and December 31, 2014, amounts due to Dominion associated with these benefit plans included in other deferred credits and other liabilities were $292 million and $219 million, respectively, and amounts due from Dominion at September 30, 2015 and December 31, 2014 included in other deferred charges and other assets were $66 million and $37 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.
73
Presented below are Virginia Power’s significant transactions with DRS and other affiliates:
Commodity purchases from affiliates
Services provided by affiliates(1)
Services provided to affiliates
Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. Virginia Power had no short-term demand note borrowings from Dominion as of September 30, 2015. There were $427 million in short-term demand note borrowings from Dominion as of December 31, 2014. Virginia Power had no outstanding borrowings under the Dominion money pool for its nonregulated subsidiaries as of September 30, 2015 and December 31, 2014. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the three and nine months ended September 30, 2015 and 2014.
There were no issuances of Virginia Power’s common stock to Dominion for the three and nine months ended September 30, 2015 or 2014.
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 September 30, 2015 and December 31, 2014, all of Dominion Gas’ commodity derivatives were with affiliates. See Notes 7 and 9 for more information. See Note 10 for information regarding sales of assets to an affiliate.
Dominion Gas participates in certain Dominion benefit plans as described in Note 19.
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 costs of these services follow:
Purchases of natural gas and transportation and storage services from affiliates
Sales of natural gas and transportation and storage services to affiliates
Services provided by related parties(1)
Services provided to related parties (2)
The following table presents affiliated and related party activity reflected in Dominion Gas’ Consolidated Balance Sheets:
Other receivables (1)
Customer receivables from related parties
Imbalances receivable from affiliates(2)
Affiliated notes receivable(3)
74
Dominion Gas’ borrowings under the IRCA with Dominion totaled $198 million as of September 30, 2015 and $384 million as of December 31, 2014. Interest charges related to Dominion Gas’ total borrowings from Dominion were immaterial for the three and nine months ended September 30, 2015 and 2014.
Note 19. Employee Benefit Plans
The components of Dominion’s provision for net periodic benefit cost (credit) were as follows:
Three Months Ended September 30,
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service credit
Amortization of net actuarial loss
Settlements and curtailments
Net periodic benefit cost (credit)
Amortization of prior service cost (credit)
Employer Contributions
During the nine months ended September 30, 2015, Dominion made no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs during the remainder of 2015.
Dominion Gas participates in certain Dominion benefit plans as described in Note 21 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. At September 30, 2015 and December 31, 2014, 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 $642 million and $614 million, respectively. At September 30, 2015 and December 31, 2014, Dominion Gas’ amounts due to Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred credits and other liabilities in the Consolidated Balance Sheets were $4 million and $7 million, respectively.
75
The components of Dominion Gas’ provision for net periodic benefit credit for employees represented by collective bargaining units were as follows:
Amortization of prior service cost
Net periodic benefit credit
During the nine months ended September 30, 2015, Dominion Gas made no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion Gas expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs, for both employees represented by collective bargaining units and employees not represented by collective bargaining units, during the remainder of 2015.
Note 20. Operating Segments
The Companies are organized primarily on the basis of products and services sold in the U.S. A description of the operations included in the Companies’ primary operating segments is as follows:
Primary Operating Segment
Description of Operations
VirginiaPower
DominionGas
DVP
Regulated electric distribution
Regulated electric transmission
Dominion Generation
Regulated electric fleet
Merchant electric fleet
Nonregulated retail energy marketing
Dominion Energy
Gas transmission and storage(1)
Gas distribution and storage
Gas gathering and processing
LNG import and storage
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) and the net impact of operations that are discontinued or sold. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
In January 2014, Dominion announced it would exit the electric retail energy marketing business. Dominion completed the sale in March 2014. As a result, the earnings impact from the electric retail energy marketing business has been included in the Corporate and Other Segment of Dominion for 2014 first quarter results of operations.
76
In the second quarter of 2013, Dominion commenced a repositioning 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 repositioning was completed in the first quarter of 2014 and resulted in the termination of natural gas trading and certain energy marketing activities. As a result, the earnings impact from natural gas trading and certain energy marketing activities has been included in the Corporate and Other Segment of Dominion for 2014.
In the nine months ended September 30, 2015, Dominion reported an after-tax net expense of $82 million for specific items in the Corporate and Other segment, with $80 million of these net expenses attributable to its operating segments. In the nine months ended September 30, 2014, Dominion reported an after-tax net expense of $446 million for specific items in the Corporate and Other segment, with $435 million of these net expenses attributable to its operating segments.
The net expense for specific items in 2015 primarily related to the impact of the following items, all of which were attributable to Dominion Generation:
The net expense for specific items in 2014 primarily related to the impact of the following items:
77
The following table presents segment information pertaining to Dominion’s operations:
Total revenue from external customers
Intersegment revenue
Net income (loss) attributable to Dominion
Intersegment sales and transfers for Dominion are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation.
The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
In the nine months ended September 30, 2015, Virginia Power reported an after-tax net expense of $101 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segments. In the nine months ended September 30, 2014, Virginia Power reported an after-tax net expense of $235 million for specific items in the Corporate and Other segment, with $239 million of these net expenses attributable to its operating segments.
78
The following table presents segment information pertaining to Virginia Power’s operations:
Net income (loss)
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 and the effect of certain items recorded at Dominion Gas as a result of Dominion’s basis in the net assets contributed.
In the nine months ended September 30, 2015 and 2014, Dominion Gas reported no amounts for specific items in the Corporate and Other segment.
The following table presents segment information pertaining to Dominion Gas’ operations:
79
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MD&A discusses Dominion’s results of operations and general financial condition and Virginia Power’s and Dominion Gas’ results of operations. MD&A should be read in conjunction with the Companies’ Consolidated Financial Statements. Virginia Power and Dominion Gas meet the conditions to file under the reduced disclosure format, and therefore have omitted certain sections of MD&A.
Contents of MD&A
MD&A consists of the following information:
Forward-Looking Statements
This report contains statements concerning the Companies’ expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words.
The Companies make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:
80
Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.
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
As of September 30, 2015 there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. The policies disclosed included the accounting for regulated operations, AROs, income taxes, derivative contracts and other instruments at fair value, goodwill and long-lived asset impairment testing and employee benefit plans.
81
Results of Operations
Presented below is a summary of Dominion’s consolidated results:
Third Quarter
Diluted EPS
Year-To-Date
Overview
Third Quarter 2015 vs. 2014
Net income attributable to Dominion increased 12%, primarily due to a gain from an agreement to convey shale development rights underneath a natural gas storage field and 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.
Year-To-Date 2015 vs. 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, which was completed in the first quarter of 2014, and gains from agreements to convey shale development rights underneath natural gas storage fields.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion’s results of operations:
Net revenue
An analysis of Dominion’s results of operations follows:
Net revenue increased 8%, primarily reflecting:
82
Other operations and maintenance decreased 8%, primarily reflecting:
These decreases were partially offset by:
Other income decreased 84%, primarily due to lower realized gains (net of investment income) on nuclear decommissioning trust funds ($36 million), a decrease in earnings from rabbi trust investments ($7 million) and an increase in donations paid ($6 million).
Income tax expense increased 34%, primarily reflecting higher pre-tax income.
Net revenue increased 15%, primarily reflecting:
Other operations and maintenance decreased 5%, primarily reflecting:
83
Other income decreased 23%, primarily due to lower realized gains (net of investment income) on nuclear decommissioning trust funds ($15 million), a decrease in earnings from rabbi trust investments ($9 million) and an increase in donations paid ($6 million).
Income tax expense increased 66%, primarily reflecting higher pre-tax income.
Segment Results of Operations
Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. Presented below is a summary of contributions by Dominion’s operating segments to net income attributable to Dominion:
Primary operating segments
Corporate and Other
Consolidated
Presented below are selected operating statistics related to DVP’s operations:
Electricity delivered (million MWh)
Degree days (electric distribution service area):
Cooling
Heating
Average electric distribution customer accounts (thousands)(1)
84
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
2015 vs. 2014
Increase (Decrease)
Regulated electric sales:
Weather
FERC transmission equity return
Other operations and maintenance expense
Share dilution
Change in net income contribution
Presented below are selected operating statistics related to Dominion Generation’s operations:
Electricity supplied (million MWh):
Utility
Merchant
Degree days (electric utility service area):
Average retail energy marketing customer accounts (thousands)(1)(2)
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
Merchant generation margin
PJM ancillary services
Rate adjustment clause equity return
Outage costs
Renewable energy investment tax credits(1)
85
Presented below are selected operating statistics related to Dominion Energy’s operations:
Gas distribution throughput (bcf):
Sales
Transportation
Heating degree days (gas distribution service area)
Average gas distribution customer accounts (thousands)(1):
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:
Assignment of shale development rights
Noncontrolling interest (2)
Gas distribution margin:
Rate adjustment clauses
Presented below are the Corporate and Other segment’s after-tax results:
Specific items attributable to operating segments
Specific items attributable to corporate operations
Total specific items
Other corporate operations:
Renewable energy investment tax credits
Total other corporate operations
Total net expense
EPS impact
86
Total Specific Items
Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing those segments’ performance or in allocating resources among the segments. See Note 20 to the Consolidated Financial Statements in this report for discussion of these items in more detail.
Presented below is a summary of Virginia Power’s consolidated results:
Net income increased 23%, primarily due to an increase in sales to retail customers, primarily due to an increase in cooling degree days, an increase from rate adjustment clauses, and 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, partially offset by a decrease in sales to customers due to the effect of changes in customer usage and other factors.
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.
Presented below are selected amounts related to Virginia Power’s results of operations:
An analysis of Virginia Power’s results of operations follows:
Net revenue increased 8%, primarily reflecting an increase in sales to retail customers, primarily due to an increase in cooling degree days ($68 million) and an increase from rate adjustment clauses ($63 million), partially offset by a decrease in sales to customers due to the effect of changes in customer usage and other factors ($41 million).
Other operations and maintenance decreased 6%, primarily reflecting 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 ($43 million), partially offset by a $26 million increase in certain electric transmission-related expenditures, which are primarily recovered through state and FERC rates and do not impact net income.
87
Other income decreased 46%, primarily reflecting a decrease in the equity component of AFUDC ($5 million), a decrease in amounts collectible from customers for taxes in connection with contributions in aid of construction ($3 million) and lower realized gains (net of investment income) on nuclear decommissioning trust funds ($2 million).
Interest and related charges increased 15%, primarily reflecting higher long-term debt interest expense resulting from debt issuances in October 2014 and May 2015.
Income tax expense increased 25%, primarily reflecting higher pre-tax income.
Net revenue increased 5%, primarily reflecting:
Other operations and maintenance decreased 12%, primarily reflecting:
Other income decreased 18%, primarily reflecting a decrease in amounts collectible from customers for taxes in connection with contributions in aid of construction ($5 million) and a decrease in the equity component of AFUDC ($3 million).
Income tax expense increased 24%, primarily reflecting higher pre-tax income.
Presented below is a summary of Dominion Gas’ consolidated results:
Net income increased 4%, primarily due to a gain from an agreement to convey shale development rights underneath a natural gas storage field, partially offset by the absence of gains on the sale of assets and higher interest expense.
Net income decreased 2%, primarily due to the absence of gains on the 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.
88
Presented below are selected amounts related to Dominion Gas’ results of operations:
An analysis of Dominion Gas’ results of operations follows:
Net revenue increased 1%, primarily reflecting:
Other operations and maintenance decreased 31%, primarily reflecting:
Other taxes increased 13%, primarily due to increased investment resulting in higher property taxes.
Interest and related charges increased $11 million, primarily due to higher long-term debt interest expense resulting from debt issuances in December 2014.
Income tax expense increased 13%, primarily reflecting higher pre-tax income.
89
Other operations and maintenance increased 3%, primarily reflecting:
Interest and related charges increased $34 million, primarily due to higher long-term debt interest expense resulting from debt issuances in December 2014.
Liquidity and Capital Resources
Dominion depends on both internal and external sources of liquidity to provide working capital and as a bridge to long-term debt financings. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.
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. The common units may be acquired by Dominion over the next 12 months at the discretion of management. During the third quarter of 2015, Dominion purchased approximately 77,000 common units for approximately $2 million. In October 2015, Dominion purchased approximately 478,000 additional common units for approximately $13 million.
At September 30, 2015, Dominion had $1.9 billion of unused capacity under its credit facilities.
A summary of Dominion’s cash flows is presented below:
Cash and cash equivalents at January 1
Cash flows provided by (used in):
Operating activities
Investing activities
Financing activities
Net decrease in cash and cash equivalents
Cash and cash equivalents at September 30
Operating Cash Flows
Net cash provided by Dominion’s operating activities increased $1.0 billion, primarily due to the absence of losses related to the repositioning of Dominion’s producer services business in 2014, higher deferred fuel cost recoveries in its Virginia jurisdiction, higher revenue from rate adjustment clauses, lower net margin collateral requirements, the impact from more favorable weather in 2015, and changes in other working capital items.
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.
Dominion’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, which are discussed in Item 1A. Risk Factors in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.
90
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 September 30, 2015 for these activities. Gross credit exposure for each counterparty is calculated prior to the application of collateral and represents outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.
Investment grade(1)
Non-investment grade(2)
No external ratings:
Internally rated—investment grade(3)
Internally rated—non-investment grade(4)
Investing Cash Flows
Net cash used in Dominion’s investing activities increased $817 million, primarily due to Dominion’s acquisition of DCG in 2015, the absence of proceeds from the sale of Dominion’s electric retail energy marketing business, and higher acquisitions of solar development projects in 2015.
Financing Cash Flows and Liquidity
Dominion relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed further in Credit Ratings and Debt Covenants in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, the ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.
Dominion currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933, as amended. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows Dominion to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.
In 2015, net cash provided by Dominion’s financing activities decreased $208 million, primarily reflecting lower net debt issuances, partially offset by the issuance of common stock through an at-the-market program.
See Note 15 to the Consolidated Financial Statements in this report for further information regarding Dominion’s credit facilities, liquidity and significant financing transactions.
Credit Ratings
Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In the Credit Ratings section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, there is a discussion on the use of capital markets by Dominion as well as the impact of credit ratings on the accessibility and costs of using these markets. As of September 30, 2015, there have been no changes in Dominion’s credit ratings.
Debt Covenants
In the Debt Covenants section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, there is a discussion on the various covenants present in the enabling agreements underlying Dominion’s debt. As of September 30, 2015, there have been no material changes to debt covenants, nor any events of default under Dominion’s debt covenants.
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
As of September 30, 2015, there have been no material changes outside the ordinary course of business to Dominion’s contractual obligations nor any material changes to planned capital expenditures as disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.
91
Use of Off-Balance Sheet Arrangements
As of September 30, 2015, there have been no material changes in the off-balance sheet arrangements disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.
Future Issues and Other Matters
The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by, and subsequent to, the dates of Dominion’s Consolidated Financial Statements that may impact future results of operations, financial condition and/or cash flows. This section should be read in conjunction with Item 1. Business and Future Issues and Other Matters in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Future Issues and Other Matters in MD&A in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015.
Dominion is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. See Note 22 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Note 16 to the Consolidated Financial Statements in this report for additional information on various environmental matters.
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 interim plans to the EPA by summer 2016 identifying how they will comply with the rule, with final plans due by September 2018. Dominion’s most recent integrated resources plan filed in July 2015 includes four alternative plans that represent plausible compliance strategies with the rule as proposed, and which include additional coal unit retirements and additional low or zero-carbon resources. However, until the state plans are developed and the EPA approves the plans, Dominion cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.
Legal Matters
See Item 3. Legal Proceedingsin the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, Notes 12 and 15 to the Consolidated Financial Statements and Item 1. Legal Proceedings in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 and Notes 12 and 16 to the Consolidated Financial Statements and Item 1. Legal Proceedings for the quarter ended June 30, 2015 and in this report for additional information on various legal matters.
Regulatory Matters
See Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Note 12 in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015, June 30, 2015 and in this report for additional information on various regulatory matters.
DTI Gathering and Processing Facilities
In October 2015, DTI filed an application with FERC seeking authority to abandon by sale its gathering and processing facilities to Dominion Gathering and Processing, Inc., a newly-formed wholly-owned subsidiary of Dominion Gas. Pending approval by FERC, these gathering and processing facilities with a carrying value of approximately $430 million are expected to be transferred in the first half of 2016.
Atlantic Coast Pipeline
In September 2014, Dominion, along with Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc., announced the formation of Atlantic Coast Pipeline and its intent to construct an approximately 550-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, which has an expected cost of $4.5 billion to $5.0 billion, excluding financing costs. An application requesting FERC authorization to construct and operate the project facilities was filed in September 2015. The project is expected to be in service in the fourth quarter of 2018.
92
Supply Header Project
In September 2014, DTI announced its intent to construct and operate the Supply Header Project which is expected to cost approximately $500 million and provide 1,500,000 Dths per day of firm transportation service to various customers including the Atlantic Coast Pipeline. In September 2015, DTI filed its application requesting FERC authorization to construct and operate the project facilities. The project is expected to be in service in the fourth quarter of 2018.
West Virginia Regulation
In September 2015, Hope requested approval of PREP from the West Virginia Commission. In the application, Hope proposed a projected capital investment for 2016 of $24 million as part of a total five-year projected capital investment of $158 million.
Ohio Regulation
In October 2015, East Ohio requested approval from the Ohio Commission to defer the operation and maintenance costs associated with implementing a proposed PSMP. The costs are not expected to exceed $15 million per year.
93
ITEM 3.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part I, Item 2. MD&A in this report. The reader’s attention is directed to those paragraphs for discussion of various risks and uncertainties that may impact the Companies.
Market Risk Sensitive Instruments and Risk Management
The Companies’ financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in Dominion’s and Virginia Power’s electric operations and Dominion’s and Dominion Gas’ natural gas procurement and marketing operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt and future issuances of debt. In addition, the Companies are exposed to investment price risk through various portfolios of equity and debt securities.
The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in commodity prices or interest rates.
Commodity Price Risk
To manage price risk, Dominion and Virginia Power primarily hold commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products and Dominion Gas primarily holds commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of natural gas and other energy-related products.
The 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% decrease in commodity prices of Dominion’s commodity-based financial derivative instruments would have resulted in an increase in fair value of approximately $68 million and $101 million as of September 30, 2015 and December 31, 2014, respectively. The decline in sensitivity is largely due to decreased commodity derivative activity and lower commodity prices.
A hypothetical 10% decrease in commodity prices would not have resulted in a material change in the fair value of Virginia Power’s commodity-based financial derivatives as of September 30, 2015 or December 31, 2014.
A hypothetical 10% decrease in commodity prices of Dominion Gas’ commodity-based financial derivative instruments would have resulted in an increase in fair value of approximately $6 million and $2 million as of September 30, 2015 and December 31, 2014, respectively. The rise in sensitivity is largely due to increased commodity derivative activity.
The impact of a change in energy commodity prices on the Companies’ commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.
Interest Rate Risk
The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt and interest rate swaps designated under fair value hedging and outstanding for the Companies, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at September 30, 2015 or December 31, 2014.
The Companies may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges.
94
As of September 30, 2015 Dominion, Virginia Power and Dominion Gas had $3.8 billion, $1.2 billion and $250 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $43 million, $30 million and $1 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at September 30, 2015. As of December 31, 2014, Dominion, Virginia Power and Dominion Gas had $4.1 billion, $1.5 billion and $250 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $46 million, $25 million and $2 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2014.
The impact of a change in interest rates on the Companies’ interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.
Investment Price Risk
Dominion and Virginia Power are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in Dominion’s and Virginia Power’s Consolidated Balance Sheets at fair value.
Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $134 million for the nine months ended September 30, 2015 and 2014 and $176 million for the year ended December 31, 2014. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on these investments of $260 million for the nine months ended September 30, 2015, and a net increase in unrealized gains on these investments of $86 million and $172 million for the nine months ended September 30, 2014 and for the year ended December 31, 2014, respectively.
Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $67 million, $58 million and $77 million for the nine months ended September 30, 2015 and 2014 and for the year ended December 31, 2014, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on these investments of $123 million for the nine months ended September 30, 2015, and a net increase in unrealized gains on these investments of $47 million and $87 million for the nine months ended September 30, 2014 and for the year ended December 31, 2014, respectively.
Dominion sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power and Dominion Gas employees participate in these plans. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.
95
ITEM 4. CONTROLS AND PROCEDURES
Senior management of each of Dominion, Virginia Power, and Dominion Gas, including Dominion’s, Virginia Power’s, and Dominion Gas’ CEO and CFO, evaluated the effectiveness of each of their respective Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, each of Dominion’s, Virginia Power’s, and Dominion Gas’ CEO and CFO have concluded that each of their respective Company’s disclosure controls and procedures are effective.
There were no changes in Dominion’s, Virginia Power’s, or 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, the Companies’ internal control over financial reporting.
96
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, the Companies are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Companies, or permits issued by various local, state and/or federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Companies and their subsidiaries are involved in various legal proceedings.
See the following for discussions on various environmental and other regulatory proceedings to which the Companies are a party:
ITEM 1A. RISK FACTORS
The Companies businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond the Companies’ control. A number of these risk factors have been identified in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, which should be taken into consideration when reviewing the information contained in this report. There have been no material changes with regard to the risk factors previously disclosed in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. 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 MD&A.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
ISSUER PURCHASES OF EQUITY SECURITIES
Period
7/1/15-7/31/15
$1.18 billion
8/1/15-8/31/15
9/1/15-9/30/15
97
98
ITEM 6. EXHIBITS
ExhibitNumber
Description
Virginia
Power
99
100
SIGNATURE
Pursuant to the requirements 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.
/s/ Michele L. Cardiff
Vice President, Controller and
Chief Accounting Officer
101
EXHIBIT INDEX
Exhibit
102
103