UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
For the quarterly period ended March 31, 2017
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.
Dominion Resources, Inc. Yes ☒ No ☐ Virginia Electric and Power Company Yes ☒ No ☐
Dominion Gas Holdings, LLC Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Dominion Resources, Inc.
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
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).
Dominion Resources, Inc. Yes ☐ No ☒ Virginia Electric and Power Company Yes ☐ No ☒
Dominion Gas Holdings, LLC Yes ☐ No ☒
At April 14, 2017, the latest practicable date for determination, Dominion Resources, Inc. had 628,985,754 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
Glossary of Terms
Item 1.
Financial Statements
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Item 4.
Controls and Procedures
Legal Proceedings
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.
Exhibits
2
GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Form 10-Q are defined below:
Abbreviation or Acronym
Definition
2013 Equity Units
Dominion’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013
2014 Equity Units
Dominion’s 2014 Series A Equity Units issued in July 2014
2016 Equity Units
Dominion’s 2016 Series A Equity Units issued in August 2016
AFUDC
Allowance for funds used during construction
AMR
Automated meter reading program deployed by East Ohio
AOCI
Accumulated other comprehensive income (loss)
ARO
Asset retirement obligation
Atlantic Coast Pipeline
Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion, Duke and Southern Company Gas
BACT
Best available control technology
bcf
Billion cubic feet
bcfe
Billion cubic feet equivalent
Bear Garden
A 590 MW combined cycle, natural gas-fired power station in Buckingham County, Virginia
BREDL
Blue Ridge Environmental Defense League
Brunswick County
A 1,376 MW combined cycle, natural gas-fired power station in Brunswick County, Virginia
CAA
Clean Air Act
CAISO
California Independent System Operator
CCR
Coal combustion residual
CEO
Chief Executive Officer
CERCLA
Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
CFO
Chief Financial Officer
CO2
Carbon dioxide
COL
Combined Construction Permit and Operating License
Companies
Dominion, Virginia Power and Dominion Gas, collectively
Cooling degree days
Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
Cove Point
Dominion Cove Point LNG, LP
CPCN
Certificate of Public Convenience and Necessity
CWA
Clean Water Act
DCG
Dominion Carolina Gas Transmission, LLC
DEI
Dominion Energy, Inc.
DOE
Department of Energy
Dominion
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
Dominion Gas
The legal entity, Dominion Gas Holdings, LLC, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Gas Holdings, LLC and its consolidated subsidiaries
Dominion Iroquois
Dominion Iroquois, Inc., which holds a 24.07% noncontrolling partnership interest in Iroquois
Dominion Midstream
The legal entity, Dominion Midstream Partners, LP, one or more of its consolidated subsidiaries, Cove Point Holdings, Iroquois GP Holding Company, LLC, DCG and Questar Pipeline (beginning December 1, 2016) or operating segment, or the entirety of Dominion Midstream Partners, LP, and its consolidated subsidiaries
Dominion Questar
The legal entity, Dominion Questar Corporation, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Questar Corporation and its consolidated subsidiaries
Dominion Questar Combination
Dominion’s acquisition of Dominion Questar completed on September 16, 2016 pursuant to the terms of the agreement and plan of merger entered on January 31, 2016
DRS
Dominion Resources Services, Inc.
DSM
Demand-side management
Dth
Dekatherm
DTI
Dominion Transmission, Inc.
Duke
The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries or operating segments, or the entirety of Duke Energy Corporation and its consolidated subsidiaries
3
DVP
Dominion Virginia Power operating segment
East Ohio
The East Ohio Gas Company, doing business as Dominion East Ohio
EPA
Environmental Protection Agency
EPS
Earnings per share
FERC
Federal Energy Regulatory Commission
Four Brothers
Four Brothers Solar, LLC, a limited liability company owned by Dominion and Four Brothers Holdings, LLC, a wholly-owned subsidiary of NRG effective November 2016
Fowler Ridge
A wind-turbine facility joint venture between Dominion and BP Wind Energy North America Inc. in Benton County, Indiana
FTA
Free Trade Agreement
FTRs
Financial transmission rights
GAAP
U.S. generally accepted accounting principles
Gal
Gallon
GHG
Greenhouse gas
Granite Mountain
Granite Mountain Holdings, LLC, a limited liability company owned by Dominion and Granite Mountain Renewables, LLC, a wholly-owned subsidiary of NRG effective November 2016
Greensville County
An approximately 1,588 MW natural gas-fired combined-cycle power station under construction in Greensville County, Virginia
Heating degree days
Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
Hope
Hope Gas, Inc., doing business as Dominion Hope
Iron Springs
Iron Springs Holdings, LLC, a limited liability company owned by Dominion and Iron Springs Renewables, LLC, a wholly-owned subsidiary of NRG effective November 2016
Iroquois
Iroquois Gas Transmission System, L.P.
ISO-NE
Independent System Operator New England
kV
Kilovolt
Liquefaction Project
A natural gas export/liquefaction facility currently under construction by Cove Point
LNG
Liquefied natural gas
Local 69
Local 69, Utility Workers Union of America, United Gas Workers
MATS
Utility Mercury and Air Toxics Standard Rule
MD&A
MGD
Million gallons a day
MISO
Midcontinent Independent System Operator, Inc.
MW
Megawatt
MWh
Megawatt hour
NAV
Net asset value
NedPower
A wind-turbine facility joint venture between Dominion and Shell Wind Energy, Inc. in Grant County, West Virginia
NGL
Natural gas liquid
NO×
Nitrogen oxide
NRC
Nuclear Regulatory Commission
NRG
The legal entity, NRG Energy, Inc., one or more of its consolidated subsidiaries (including, effective November 2016, Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of NRG Energy, Inc. and its consolidated subsidiaries
NSPS
New Source Performance Standards
Order 1000
Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development
PIPP
Percentage of Income Payment Plan deployed by East Ohio
PIR
Pipeline Infrastructure Replacement program deployed by East Ohio
PJM
PJM Interconnection, L.L.C.
ppb
Parts-per-billion
PSD
Prevention of Significant Deterioration
Questar Gas
Questar Gas Company
4
Questar Pipeline
Questar Pipeline, LLC, one or more of its consolidated subsidiaries, or the entirety of Questar Pipeline, LLC and its consolidated subsidiaries
Rider B
A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Power’s coal-fired power stations to biomass
Rider BW
A rate adjustment clause associated with the recovery of costs related to Brunswick County
Rider GV
A rate adjustment clause associated with the recovery of costs related to Greensville County
Rider R
A rate adjustment clause associated with the recovery of costs related to Bear Garden
Rider S
A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center
Rider US-2
A rate adjustment clause associated with the recovery of costs related to Woodland, Scott Solar and Whitehouse
Rider W
A rate adjustment clause associated with the recovery of costs related to Warren County
Riders C1A and C2A
Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in DSM cases
ROE
Return on equity
SBL Holdco
SBL Holdco, LLC, a wholly-owned subsidiary of DEI
Scott Solar
A 17 MW utility-scale solar power station in Powhatan County, Virginia
SEC
Securities and Exchange Commission
Standard & Poor’s
Standard & Poor’s Ratings Services, a division of McGraw Hill Financial, Inc.
SunEdison
The legal entity, SunEdison, Inc., one or more of its consolidated subsidiaries (including, through November 2016, 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
Terra Nova Renewable Partners
A partnership comprised primarily of institutional investors advised by J.P. Morgan Asset Management-Global Real Assets
Three Cedars
Granite Mountain and Iron Springs, collectively
VDEQ
Virginia Department of Environmental Quality
VEBA
Voluntary Employees’ Beneficiary Association
VIE
Variable interest entity
Virginia City Hybrid Energy Center
A 610 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County, Virginia
Virginia Commission
Virginia State Corporation Commission
Virginia Power
The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments, or the entirety of Virginia Power and its consolidated subsidiaries
VOC
Volatile organic compounds
Warren County
A 1,342 MW combined-cycle, natural gas-fired power station in Warren County, Virginia
Whitehouse
A 20 MW utility-scale solar power station in Louisa County, Virginia
Woodland
A 19 MW utility-scale solar power station in Isle of Wight County, Virginia
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 (excess) 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 on derivatives-hedging activities(1)
Changes in unrealized net gains on investment securities(2)
Amounts reclassified to net income:
Net derivative gains-hedging activities(3)
Net realized gains on investment securities(4)
Net pension and other postretirement benefit costs(5)
Changes in other comprehensive income from equity method investees(6)
Total other comprehensive income
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 $19 and $18)
Other receivables (less allowance for doubtful accounts of $2 at both dates)
Inventories
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
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
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 15)
Equity
Common stock – no par(2)
Retained earnings
Accumulated other comprehensive loss
Total common shareholders’ equity
Noncontrolling interests
Total equity
Total liabilities and equity
9
CONSOLIDATED STATEMENT OF EQUITY
December 31, 2015
Contributions from SunEdison to Four Brothers and Three Cedars
Sale of interest in merchant solar projects
Purchase of Dominion Midstream common units
Issuance of common stock
Dividends and distributions
Other comprehensive income, net of tax
March 31, 2016
December 31, 2016
Contributions from NRG to Four Brothers and Three Cedars
March 31, 2017
10
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended March 31,
Operating Activities
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)
Proceeds from assignment of tower rental portfolio
Contribution to pension plan
Other adjustments
Changes in:
Accounts receivable
Deferred fuel and purchased gas costs, net
Prepayments
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
Proceeds from sales of securities
Purchases of securities
Contributions to equity method affiliates
Net cash used in investing activities
Financing Activities
Repayment of short-term debt, net
Repayment of short-term notes
Issuance of long-term debt
Repayment and repurchase of long-term debt
Proceeds from sale of interest in merchant solar projects
Contributions from NRG and SunEdison to Four Brothers and Three Cedars
Common dividend payments
Net cash provided by (used in) financing activities
Increase (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:
Accrued capital expenditures
11
VIRGINIA ELECTRIC AND POWER COMPANY
Three Months Ended
March 31,
Operating Revenue(1)
Electric fuel and other energy-related purchases(1)
Other operations and maintenance:
Affiliated suppliers
Depreciation and amortization
Interest and related charges(1)
Income before income tax expense
Net Income
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
12
Net income
Net deferred losses on derivatives-hedging activities(1)
Changes in unrealized net gains on nuclear decommissioning trust funds(2)
Net realized gains on nuclear decommissioning trust funds(3)
Total other comprehensive income (loss)
Comprehensive income
13
Customer receivables (less allowance for doubtful accounts of $10 at both dates)
Other receivables (less allowance for doubtful accounts of $1 at both dates)
Affiliated receivables
Inventories (average cost method)
Other(2)
Accumulated depreciation and amortization
14
LIABILITIES AND SHAREHOLDER’S EQUITY
Payables to affiliates
Affiliated current borrowings
Asset retirement obligations
Common Shareholder’s Equity
Common stock – no par(3)
Other paid-in capital
Accumulated other comprehensive income
Total common shareholder’s equity
Total liabilities and shareholder’s equity
15
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)
Affiliated receivables and payables
Deferred fuel expenses, net
Plant construction and other property additions
Purchases of nuclear fuel
Repayment of affiliated current borrowings, net
Repayment of long-term debt
Common dividend payments to parent
Increase in cash and cash equivalents
16
DOMINION GAS HOLDINGS, LLC
Purchased gas(1)
Other energy-related purchases
Earnings from equity method investee
Income from operations before income taxes
The accompanying notes are an integral part of Dominion Gas’ Consolidated Financial Statements.
17
Net derivative (gains) losses-hedging activities(2)
Net pension and other postretirement benefit costs(3)
18
Customer receivables (less allowance for doubtful accounts of $1 at both dates)
Other receivables (less allowance for doubtful accounts of $1 at both dates)(2)
Pension and other postretirement benefit assets(2)
19
Membership interests
20
Deferred purchased gas costs, net
Pension and other postretirement benefits
Issuance (repayment) of short-term debt, net
Issuance (repayment) of affiliated current borrowings, net
Distribution payments to parent
Net cash used in financing activities
21
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. See Note 3 for a description of operations acquired in the Dominion Questar Combination.
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, 2016.
In the Companies’ opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position as of March 31, 2017, their results of operations for the three months ended March 31, 2017 and 2016, their cash flows for the three months ended March 31, 2017 and 2016 and Dominion’s changes in equity for the three months ended March 31, 2017. 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 andnon-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. At March 31, 2017, Dominion owns the general partner, 50.9% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Midstream. The public’s ownership interest in Dominion Midstream is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. Also, at March 31, 2017, Dominion owns 50% of the units in and consolidates Four Brothers and Three Cedars. NRG’s ownership interest in Four Brothers and Three Cedars, as well as Terra Nova Renewable Partners’ 33% interest in certain Dominion merchant solar projects, is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements.
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’ 2016 Consolidated Financial Statements and Notes have been reclassified to conform to the 2017 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.
With the exception of the items described below, there have been no significant changes from Note 2 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2016.
In the first quarter of 2017, Virginia Power revised the depreciation rates for its assets to reflect the results of a new depreciation study. This change resulted in an increase in depreciation expense of $10 million ($6 millionafter-tax) for the quarter ended March 31, 2017 and is expected to increase annual depreciation by approximately $40 million ($25 million after-tax).Additionally, Dominion revised the depreciable lives for its merchant generation assets, excluding Millstone, which resulted in a decrease in depreciation expense of $6 million ($4 million after-tax)for the quarter ended March 31, 2017 and is expected to decrease annual depreciation by approximately $26 million ($16 million after-tax).
22
New Accounting Standards
In March 2017, the Financial Accounting Standards Board issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. The update requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement benefit costs would be classified outside of income from operations. In addition, only the service cost component will be eligible for capitalization during construction. The standard also recognized that in the event that a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. The guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, although it can be early adopted, with a retrospective approach for income statement presentation and a prospective approach for capitalization. The Companies are currently evaluating the impact the adoption of the standard will have on their consolidated financial statements and disclosures. The Companies are also evaluating industry issues that could potentially create a regulatory accounting difference in the event that FERC or any of our state commissions do not adopt the change in capitalization requirements for regulatory reporting.
Note 3. Acquisitions and Dispositions
Acquisition of Dominion Questar
In September 2016, Dominion completed the Dominion Questar Combination and Dominion Questar became a wholly-owned
subsidiary of Dominion. Dominion Questar, a Rockies-based integrated natural gas company, included Questar Gas, Wexpro Company and Questar Pipeline at closing. Questar Gas has regulated gas distribution operations in Utah, southwestern Wyoming and southeastern Idaho. Wexpro Company develops and produces natural gas from reserves that are supplied to Questar Gas under a cost-of-service framework. Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage services in Utah, Wyoming and western Colorado. The Dominion Questar Combination provides Dominion with pipeline infrastructure that provides a principal source of gas supply to Western states. Dominion Questar’s regulated businesses also provide further balance between Dominion’s electric and gas operations.
In accordance with the terms of the Dominion Questar Combination, at closing, each share of issued and outstanding Dominion Questar common stock was converted into the right to receive $25.00 per share in cash. The total consideration was $4.4 billion based on 175.5 million shares of Dominion Questar outstanding at closing.
Dominion financed the Dominion Questar Combination through the: (1) August 2016 issuance of $1.4 billion of 2016 Equity Units, (2) August 2016 issuance of $1.3 billion of senior notes, (3) September 2016 borrowing of $1.2 billion under a term loan agreement and (4) $500 million of the proceeds from the April 2016 issuance of common stock. See Notes 17 and 19 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2016 for more information.
See Note 3 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2016 for more information on the Dominion Questar Combination including purchase price allocation, regulatory matters, results of operations, and the contribution of Questar Pipeline to Dominion Midstream.
Pro Forma Information
The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion assuming the Dominion Questar Combination had taken place on January 1, 2015. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.
Net income attributable to Dominion
Earnings Per Common Share – Basic
Earnings Per Common Share – Diluted
23
Wholly-Owned Merchant Solar Projects
In January 2017, Dominion entered into an agreement to acquire 100% of the equity interests of a solar project in North Carolina from Cypress Creek Renewables, LLC for $154 million in cash. The acquisition is expected to close during the second quarter of 2017, prior to the project commencing commercial operations, which is expected by the end of the third quarter of 2017. The project is expected to cost $160 million once constructed, including the initial acquisition cost, and to generate approximately 79 MW.
In September 2016, Dominion entered into an agreement to acquire 100% of the equity interests of a solar project in Virginia from Community Energy Solar, LLC. In February 2017, Dominion closed on the acquisition for $29 million, all of which was allocated to property, plant and equipment. The project is expected to cost approximately $205 million once constructed, including the initial acquisition cost. The facility is expected to begin commercial operations during the fourth quarter of 2017 and to generate approximately 100 MW.
In August 2016, Dominion entered into an agreement to acquire 100% of the equity interests of two solar projects in California from Solar Frontier Americas Holding LLC. In March 2017, Dominion closed on the acquisition of one of the solar projects for $77 million, all of which was allocated to property, plant and equipment. The project is expected to cost approximately $80 million once constructed, including the initial acquisition cost. The facility is expected to begin commercial operations during the second quarter of 2017 and to generate approximately 30 MW. In April 2017, Dominion discontinued efforts on the acquisition of the additional 20 MW solar project from Solar Frontier Americas Holding LLC.
Sale of Interest in Merchant Solar Projects
In September 2015, Dominion signed an agreement to sell a noncontrolling interest (consisting of 33% of the equity interests) in all of its then currently wholly-owned merchant solar projects, 24 solar projects totaling approximately 425 MW, to SunEdison. In December 2015, the sale of interest in 15 of the solar projects closed for $184 million with the sale of interest in the remaining projects completed in January 2016 for $117 million. Upon closing, SunEdison sold its interest in these projects to Terra Nova Renewable Partners. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion’s remaining 67% ownership in the projects upon the occurrence of certain events, none of which had occurred as of March 31, 2017 nor are expected to occur in the remainder of 2017.
Assignment of Tower Rental Portfolio
Virginia Power rents space on certain of its electric transmission towers to various wireless carriers for communications antennas and other equipment. In March 2017, Virginia Power sold its rental portfolio to Vertical Bridge Towers II, LLC for $91 million in cash. The proceeds are subject to Virginia Power’s FERC-regulated tariff, under which it is required to return half of the proceeds to customers. Virginia Power recognized $7 million in other income in March 2017 with the remaining $39 million to be recognized ratably through 2023.
Assignment of Shale Development Rights
In November 2014, Dominion Gas closed on an agreement with a natural gas producer to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. In connection with that agreement, in January 2016, Dominion Gas conveyed approximately 2,000 acres of Marcellus Shale development rights and received proceeds of $5 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in a $5 million ($3 million after-tax) gain, included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.
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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
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
The effective tax rate in 2017 for Dominion and Dominion Gas reflects the completion of audits by state tax authorities that resulted in the recognition of previously unrecognized tax benefits. Otherwise, as of March 31, 2017, 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, 2016 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:
Average shares of common stock outstanding – Basic
Net effect of dilutive securities(1)
Average shares of common stock outstanding – Diluted
The 2014 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three months ended March 31, 2017 and 2016, as the dilutive stock price threshold was not met. The 2016 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three months ended March 31, 2017, as the dilutive stock price threshold was not met. The Dominion Midstream convertible preferred units are potentially dilutive securities but had no effect on the calculation of diluted EPS for the three months ended March 31, 2017.
Note 7. Accumulated Other Comprehensive Income
The following table presents Dominion’s changes in AOCI by component, net of tax:
Three Months Ended March 31, 2017
Beginning balance
Other comprehensive income before reclassifications: gains
Amounts reclassified from AOCI(1): (gains) losses
Net current-period other comprehensive income
Ending balance
Three Months Ended March 31, 2016
Net current-period other comprehensive income (loss)
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The following table presents Dominion’s reclassifications out of AOCI by component:
Details About AOCI Components
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts
Interest rate contracts
Foreign currency contracts
Tax
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
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The following table presents Dominion Gas’ changes in AOCI by component, net of tax:
Other comprehensive income before reclassifications: losses
Amounts reclassified from AOCI(1): losses
Amounts reclassified from AOCI(1): gains
Net current-period other comprehensive loss
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The following table presents Dominion Gas’ reclassifications out of AOCI by component:
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, 2016. 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, futures, and swaps contracts. An option model is used to value Level 3 physical and financial options. The discounted cash flow model for forwards, futures, and swaps 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 March 31, 2017. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility and credit spreads.
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Valuation Techniques
Unobservable Input
Assets
Physical and financial forwards and futures:
Natural gas(2)
Physical and financial options:
Natural gas
Electricity
Liabilities
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Significant Unobservable Inputs
Position
Change to Input
Impact on Fair
Value Measurement
Market price
Price volatility
Credit spread
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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 March 31, 2017
Derivatives:
Commodity
Interest rate
Investments(1):
Equity securities:
U.S.
Fixed income:
Corporate debt instruments
Government securities
Cash equivalents and other
Foreign currency
At December 31, 2016
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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
Included in regulatory assets/liabilities
Settlements
Transfers out of Level 3
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 Dominion’s Consolidated Statements of Income for the three months ended March 31, 2017 and 2016. 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 months ended March 31, 2017 and 2016.
The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at March 31, 2017. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility and credit spreads.
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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:
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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 months ended March 31, 2017 and 2016. 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 months ended March 31, 2017 and 2016.
The following table presents Dominion Gas’ liabilities for derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions. Derivative assets at March 31, 2017 and December 31, 2016 were not material.
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:
Included in other comprehensive income (loss)
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There were no gains or losses included in earnings in the level 3 fair value category for the three months ended March 31, 2017 and 2016. 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 months ended March 31, 2017 and 2016.
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, affiliated 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)
Junior subordinated notes(3)
Remarketable subordinated notes(3)
Long-term debt, including securities due within one year(3)
Long-term debt, including securities due within one year(4)
Note 9. Derivatives and Hedge Accounting Activities
The Companies’ accounting policies, 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, 2016. 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. Virginia Power’s and Dominion Gas’ derivative contracts consist of over-the-countertransactions. 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.
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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:
Commodity contracts:
Over-the-counter
Exchange
Interest rate contracts:
Total derivatives, subject to a master netting or similar arrangement
Total derivatives, not subject to a master netting or similar arrangement
Total
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Foreign currency contracts:
Volumes
The following table presents the volume of Dominion’s derivative activity at March 31, 2017. These volumes are based on open derivative positions and represent the combined absolute value of its long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of its long and short positions.
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Natural Gas (bcf):
Fixed price(1)
Basis
Electricity (MWh):
Fixed price
Liquids (Gal)(2)
Interest rate(3)
Foreign currency(3)(4)
Ineffectiveness and AOCI
For the three months ended March 31, 2017 and 2016, 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 March 31, 2017:
Commodities:
Gas
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign currency exchange rates.
Fair Value and Gains and Losses on Derivative Instruments
The following table presents the fair values of Dominion’s derivatives and where they are presented in its Consolidated Balance Sheets:
Total current derivative assets(1)
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Noncurrent Assets
Total noncurrent derivative assets(2)
Total derivative assets
LIABILITIES
Total current derivative liabilities(3)
Noncurrent Liabilities
Total noncurrent derivative liabilities(4)
Total derivative liabilities
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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
Foreign currency(4)
Derivatives Not Designated as Hedging Instruments
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The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:
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The following table presents the volume of Virginia Power’s derivative activity at March 31, 2017. These volumes are based on open derivative positions and represent the combined absolute value of its long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of its long and short positions.
Interest rate(2)
For the three months ended March 31, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were not material.
The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at March 31, 2017:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates.
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The following table presents the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:
Total noncurrent derivatives liabilities(4)
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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)
The tables below present Dominion Gas’ derivative liability balances by type of financial instrument, before and after the effects of offsetting. Derivative assets at March 31, 2017 and December 31, 2016 were not material.
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The following table presents the volume of Dominion Gas’ derivative activity at March 31, 2017. These volumes are based on open derivative positions and represent the combined absolute value of its long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of its long and short positions.
NGLs (Gal)
Foreign currency(1)
The following table presents selected information related to losses on cash flow hedges included in AOCI in Dominion Gas’ Consolidated Balance Sheet at March 31, 2017:
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates and foreign currency exchange rates.
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The following tables present the fair values of Dominion Gas’ derivatives and where they are presented in its Consolidated Balance Sheets:
Total current derivative liabilities(1)
Total noncurrent derivative liabilities(2)
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. The gains and losses associated with derivatives not designated as hedging instruments were immaterial for the three months ended March 31, 2017 and 2016.
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Derivative Type and Location of Gains (Losses):
Foreign currency(3)
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 $108 million and $104 million at March 31, 2017 and December 31, 2016, respectively.
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Decommissioning Trust Securities
Dominion holds marketable equity and debt securities (classified asavailable-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below:
Marketable equity securities:
Common/collective trust funds
Cost method investments
Cash equivalents and other(2)
The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at March 31, 2017 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)
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Other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds for Dominion were not material for the three months ended March 31, 2017 and 2016.
Virginia Power holds marketable equity and debt securities (classified asavailable-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. 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 March 31, 2017 by contractual maturity is as follows:
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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 months ended March 31, 2017 and 2016.
Equity Method Investments
In the first quarter of 2017, Dominion contributed $117 million to Atlantic Coast Pipeline.
Dominion Gas’ equity earnings totaled $7 million and $6 million for the three months ended March 31, 2017 and 2016, respectively. Dominion Gas received distributions from this investment of $6 million for both the three months ended March 31, 2017 and 2016. At March 31, 2017 and December 31, 2016, the carrying amount of Dominion Gas’ investment of $99 million and $98 million, respectively, exceeded its share of underlying equity in net assets by $8 million. The difference reflects equity method goodwill and is not being amortized.
Note 11. Regulatory Assets and Liabilities
Regulatory assets and liabilities include the following:
Regulatory assets:
Deferred rate adjustment clause costs(1)
Deferred nuclear refueling outage costs(2)
Regulatory assets-current(3)
Unrecognized pension and other postretirement benefit costs(4)
PJM transmission rates(5)
Derivatives(6)
Income taxes recoverable through future rates(7)
Utility reform legislation(8)
Regulatory assets-noncurrent
Total regulatory assets
Regulatory liabilities:
Deferred cost of fuel used in electric generation(9)
PIPP(10)
Regulatory liabilities-current(11)
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Provision for future cost of removal and AROs(12)
Nuclear decommissioning trust(13)
Regulatory liabilities-noncurrent
Total regulatory liabilities
Provision for future cost of removal(12)
Unrecovered gas costs(14)
Regulatory assets-noncurrent(15)
Regulatory liabilities-noncurrent(16)
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At March 31, 2017, $295 million of Dominion’s and $230 million of Virginia Power’s regulatory assets represented past expenditures on which they do not currently earn a return. With the exception of the $200 million PJM transmission cost allocation matter, the majority of 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 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.
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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 Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California and Utah, under Dominion’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sell as a qualified facility. 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, Old Dominion Electric Cooperative and North Carolina Electric Membership Corporation filed a complaint with FERC against Virginia Power claiming, among other issues, that the incremental costs of undergrounding certain transmission line projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. A settlement of the other issues raised in the complaint was approved by FERC in May 2012.
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 the costs of new facilities approved by PJM prior to February 1, 2013. Transmission facilities approved after February 1, 2013 are allocated on a hybrid cost allocation method approved by FERC and not subject to any court review.
In June 2016, PJM, the PJM transmission owners and state commissions representing substantially all of the load in the PJM market submitted a settlement to FERC to resolve the outstanding issues regarding this matter. Under the terms of the settlement, Virginia Power would be required to pay in excess of $200 million to PJM over the next 10 years. Although the settlement agreement has not been accepted by FERC, and the settlement is opposed by a small group of parties to the proceeding, Virginia Power believes it is probable it will be required to make payment as an outcome of the settlement. Accordingly, as of March 31, 2017, Virginia Power has recorded a contingent liability of $208 million in other deferred credits and other liabilities, which is offset by a $200 million regulatory asset for the amount that will be recovered through retail rates in Virginia.
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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, 2016.
Virginia Regulation
Regulation Act Legislation
In March 2017, as required by Regulation Act legislation enacted in February 2015, Virginia Power filed an application for the Virginia Commission to determine the general ROE for Virginia Power’s non-transmission rate adjustment clauses. The application supported a 10.5% ROE for these rate adjustment clauses. This case is pending.
Solar Facility Project
In March 2017, Virginia Power received Virginia Commission approval for a CPCN to construct and operate the Oceana solar facility and related distribution interconnection facilities at a total estimated cost of approximately $40 million, excluding financing costs. The 18 MW facility is expected to begin operation in late 2017. The facility is the subject of a public-private partnership whereby the Commonwealth of Virginia, a non-jurisdictional customer, will compensate Virginia Power for the facility’s net electrical energy output. Virginia Power will retire renewable energy certificates on the Commonwealth’s behalf in an amount equal to those generated by the facility. There is no rate adjustment clause associated with the facility, nor will any of its costs be recovered from jurisdictional customers.
Rate Adjustment Clauses
Below is a discussion of significant riders associated with various Virginia Power projects:
Electric Transmission Projects
Virginia Power previously filed an application with the Virginia Commission for a CPCN to convert an existing transmission line to 230 kV in Prince William County, Virginia, and Loudoun County, Virginia, and to construct and operate a new approximately five mile overhead 230 kV double circuit transmission line between a tap point near the Gainesville substation and a new to-be-constructed Haymarket substation. In April 2017, the Virginia Commission granted a CPCN to construct and operate the project along an approved route subject to Virginia Power’s obtaining all necessary rights-of-way. Otherwise, Virginia Power can construct and operate the project along an approved alternative route. The total estimated cost of the project is approximately $55 million.
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Virginia Power previously filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 28 miles of the existing 500 kV transmission line between the Carson switching station and a terminus located near the Rogers Road switching station under construction in Greensville County, Virginia, along with associated work at the Carson switching station. In March 2017, the Virginia Commission granted a CPCN to construct and operate the project. The total estimated cost of the project is approximately $55 million.
North Anna
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna nuclear power station. If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power has not yet committed to building a new nuclear unit at North Anna nuclear power station.
Requests by BREDL for a contested NRC hearing on Virginia Power’s COL application have been dismissed, and in September 2016, the U.S. Court of Appeals for the D.C. Circuit dismissed with prejudice petitions for judicial review that BREDL and other organizations had filed challenging the NRC’s reliance on a rule generically assessing the environmental impacts of continued onsite storage of spent nuclear fuel in various licensing proceedings, including Virginia Power’s COL proceeding. This dismissal followed the Court’s June 2016 decision in New York v. NRC, upholding the NRC’s continued storage rule and August 2016 denial of requests for rehearing en banc. Therefore, the contested portion of the COL proceeding is closed. The NRC is required to conduct a hearing in all COL proceedings. This mandatory NRC hearing was held in March 2017 and was uncontested. A decision by the NRC whether to issue a COL is expected by the end of the second quarter of 2017.
In August 2016, Virginia Power received a 60-day notice of intent to sue from the Sierra Club alleging Endangered Species Act violations. The notice alleges that the U.S. Army Corps of Engineers failed to conduct adequate environmental and consultation reviews, related to a potential third nuclear unit located at North Anna, prior to issuing a CWA section 404 permit to Virginia Power in September 2011. No lawsuit has been filed and in November 2016, the Army Corps of Engineers suspended the section 404 permit while it gathered additional information. The section 404 permit was reinstated in April 2017.
Other Virginia Legislation
In February 2017, the Governor of Virginia signed legislation into law that allows utilities to file a rate adjustment clause to recover costs of pumped hydroelectricity generation and storage facilities that are located in the coalfield region of Virginia.
In March 2017, the Governor of Virginia signed legislation into law that allows utilities to file a rate adjustment clause to recover, beginning in 2020, reasonably appropriate costs for extending the COLs, or the operating lives, of nuclear power generation facilities.
Also in March 2017, the Governor of Virginia signed legislation into law stating that is in the public interest for utilities to replace existing overhead tap lines having nine or more total unplanned outageevents-per-mile with new underground facilities, and that utilities can seek cost recovery for such new underground facilities through a rate adjustment clause.
Ohio Regulation
PIR Program
In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In April 2017, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2016 costs. The filing reflects gross plant investment for 2016 of $188 million, cumulative gross plant investment of $1.2 billion and a revenue requirement of $157 million.
AMR Program
In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. In April 2017, the Ohio Commission approved East Ohio’s application to adjust its AMR cost recovery rate for 2016 costs. The filing reflects a revenue requirement of approximately $6 million.
Ohio Legislation
In March 2017, the Governor of Ohio signed legislation into law that allows utilities to file an application to recover infrastructure development costs associated with economic development projects. The new cost recovery provision allows for projects totaling up to $22 million for East Ohio subject to Ohio Commission approval.
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Note 13. Variable Interest Entities
There have been no significant changes regarding the entities the Companies consider VIEs as described in Note 15 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2016.
Dominion’s securities due within one year and long-term debt include $30 million and $365 million, respectively, of debt issued in 2016 by SBL Holdco, a VIE, net of issuance costs that is nonrecourse to Dominion and is secured by SBL Holdco’s interest in certain merchant solar facilities.
Virginia Power has long-term power and capacity contracts with three non-utility generators with an aggregate summer generation capacity of approximately 418 MW. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $258 million as of March 31, 2017. Virginia Power paid $28 million and $37 million for electric capacity and $8 million and $7 million for electric energy to these entities in the three months ended March 31, 2017 and 2016, respectively.
Virginia Power and Dominion Gas
Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of $85 million and $31 million for the three months ended March 31, 2017 and $114 million and $35 million for the three months ended March 31, 2016, respectively.
Note 14. 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 March 31, 2017, 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)
Questar Gas’ short-term financing is supported through its access as co-borrower to the two joint revolving credit facilities discussed above with Dominion, Virginia Power and Dominion Gas. At March 31, 2017 the aggregate sub-limit for Questar Gas was $250 million.
In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which have a stated maturity date of December 2017 with automatic one-year renewals through the maturity of the SBL Holdco term loan agreement in 2023. As of March 31, 2017, no amounts were outstanding under these facilities.
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.
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At March 31, 2017, Virginia Power’s share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion, Dominion Gas and Questar Gas were as follows:
In addition to the credit facility commitments mentioned above, Virginia Power also has a $100 million credit facility with a maturity date of April 2020. As of March 31, 2017, this facility supports $100 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. 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.
At March 31, 2017, Dominion Gas’ share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion, Virginia Power and Questar Gas were as follows:
Long-term Debt
In January 2017, Dominion issued $400 million of 1.875% senior notes and $400 million of 2.75% senior notes that mature in 2019 and 2022, respectively.
In March 2017, Dominion issued through private placement $300 million of 3.496% senior notes that mature in 2024. Also in March 2017, Dominion issued an additional $100 million of its 3.90% senior notes that mature in 2025.
In March 2017, Virginia Power issued $750 million of 3.50% senior notes that mature in 2027.
Note 15. 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
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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 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 power station 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 needed to continue operating through at least April 2017 due to delays in transmission upgrades needed to maintain electric reliability. Therefore, in October 2015, Virginia Power submitted a request to the EPA for an additional one year compliance extension under an EPA Administrative Order. The order was signed by the EPA in April 2016 allowing the Yorktown power station units to operate for up to one additional year, as required to maintain reliable power availability while transmission upgrades are being made.
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 U.S. Court of Appeals for the D.C. Circuit. However, the Supreme Court did not vacate or stay the effective date and implementation of the MATS rule. In November 2015, in response to the Supreme Court decision, the EPA proposed a supplemental finding that consideration of cost does not alter the agency’s previous conclusion that it is appropriate and necessary to regulate coal- and oil-fired electric utility steam generating units under Section 112 of the CAA. In December 2015, the U.S. Court of Appeals for the D.C. Circuit issued an order remanding the MATS rulemaking proceeding back to the EPA without setting aside judgment, noting that EPA had represented it was on track to issue a final finding regarding its consideration of cost. In April 2016, the EPA issued a final supplemental finding that consideration of costs does not alter its conclusion regarding appropriateness and necessity for the regulation. This regulation has been challenged in court. In April 2017, the EPA requested that the U.S. Court of Appeals for the D.C. Circuit delay oral arguments in the case to allow agency review of the rule. Virginia Power ceased operating the coal units at Yorktown power station in April 2017 as planned; however, this does not change the need to complete necessary electricity transmission upgrades which are expected to be in service approximately 20 months following receipt of all required permits and approvals for construction. Since the MATS rule remains in effect and Dominion is complying with the requirements of the rule, Dominion does not expect any adverse impacts to its operations at this time.
Ozone Standards
In October 2015, the EPA issued a final rule tightening the ozone standard from 75-ppb to 70-ppb. To comply with this standard, in April 2016 Virginia Power submitted the NOX Reasonable Available Control Technology analysis for Unit 5 at Possum Point power station. In December 2016, the VDEQ determined that NOX controls are required on Unit 5. Installation and operation of these NOX controls including an associated water treatment system will be required by mid-2019 with an expected cost in the range of $25 million to $35 million.
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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 2012, the EPA issued the first NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In June 2016, the EPA issued a final NSPS regulation, for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 are required to comply with this regulation. In April 2017, the EPA issued a notice that it is reviewing and, if appropriate, will issue a rulemaking to suspend, revise or rescind the June 2016 final NSPS for certain oil and gas facilities. Meanwhile the rule remains in effect. Dominion and Dominion Gas are implementing the final regulation. Dominion and Dominion Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.
Climate Change Regulation
Carbon Regulations
In October 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the U.S. Court of Appeals for the D.C. Circuit’s June 2012 decision upholding the EPA’s regulation of GHG emissions from stationary sources under the CAA’s permitting programs. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the EPA’s ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant emissions rate at 75,000 tons per year of CO2 equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their financial statements.
In July 2011, the EPA signed a final rule deferring the need for PSD and Title V permitting for CO2 emissions for biomass projects. This rule temporarily deferred for a period of up to three years the consideration of CO2 emissions from biomass projects when determining whether a stationary source meets the PSD and Title V applicability thresholds, including those for the application of BACT. The deferral policy expired in July 2014. In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however, a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the CO2 deferral period. It is unclear how the court’s decision or the EPA’s final policy regarding the treatment of specific feedstock will affect biomass sources that were permitted during the deferral period; however, the expenditures to comply with any new requirements could be material to Dominion’s and Virginia Power’s financial statements.
Methane Emissions
In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR Program, the Natural Gas STAR Methane Challenge Program. The program covers the entire natural gas sector from production to distribution, with more emphasis on transparency and increased reporting for both annual emissions and reductions achieved through implementation measures. In March 2016, East Ohio, Hope, DTI and Questar Gas (prior to the Dominion Questar Combination) joined the EPA as founding partners in the new Methane Challenge program and submitted implementation plans in September 2016. DCG joined the EPA’s voluntary Natural Gas STAR Program in July 2016 and submitted an implementation plan in September 2016. Dominion and Dominion Gas do not expect the costs related to these programs to have a material impact on their results of operations, financial condition and/or cash flows.
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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. Virginia Power has eight facilities that may be subject to additional wastewater treatment requirements associated with the final rule. In April 2017, the EPA granted two separate petitions for reconsideration of the Effluent Limitations Guidelines final rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the United States’ request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. 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.
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. The Companies do not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.
Dominion has determined that it is associated with 19 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.
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See below for discussion on ash pond and landfill closure costs.
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
Pipeline Contractor Litigation
Following the completion of the Appalachian Gateway project in 2012, DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DTI filed a complaint in U.S. District Court for the Eastern District of Virginia for breach of contract as well as accounting and declaratory relief. The contractor filed a motion to dismiss, or in the alternative, a motion to transfer venue to Pennsylvania and/or West Virginia, where the pipelines were constructed. DTI filed an opposition to the contractor’s motion in August 2013. In November 2013, the court granted the contractor’s motion on the basis that DTI must first comply with the dispute resolution process. In July 2015, the contractor filed a complaint against DTI in U.S. District Court for the Western District of Pennsylvania. In August 2015, DTI filed a motion to dismiss, or in the alternative, a motion to transfer venue to Virginia. In March 2016, the Pennsylvania court granted the motion to dismiss and transferred the case to the U.S. District Court for the Eastern District of Virginia. In April 2016, the Virginia court issued an order staying the proceedings and ordering mediation. A mediation occurred in May 2016 but was unsuccessful. In July 2016, DTI filed a motion to dismiss. In March 2017, the court dismissed three of eight counts in the complaint. This case is pending. DTI has accrued a liability of $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.
Gas Producers Litigation
In connection with the Appalachian Gateway project, Dominion Field Services, Inc. entered into contracts for firm purchase rights with a group of small gas producers. In June 2016, certain of the gas producers filed a complaint in the Circuit Court of Marshall County, West Virginia against Dominion, DTI and Dominion Field Services, Inc., among other defendants, claiming that the contracts are unenforceable and seeking compensatory and punitive damages. In the third quarter of 2016, Dominion and DTI, with the consent of the other defendants, removed the case to the U.S. District Court for the Northern District of West Virginia. In October 2016, the defendants filed a motion to dismiss and the plaintiffs filed a motion to remand. In February 2017, the U.S. District Court entered an order remanding the matter to the Circuit Court of Marshall County, West Virginia. In March 2017, Dominion was voluntarily dismissed from the case; however, DTI and Dominion Field Services, Inc. remain parties to the matter. In April 2017, the case was transferred to the Business Court Division of West Virginia. This case is pending. Dominion and Dominion Gas cannot currently estimate financial statement impacts, but there could be a material impact to their financial condition and/or cash flows.
Ash Pond and Landfill Closure Costs
In September 2014, Virginia Power received a notice from the Southern Environmental Law Center on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at Possum Point power station. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point power station’s historical and active ash storage facilities. A similar notice from the Southern Environmental Law Center on behalf of the Sierra Club was subsequently received related to Chesapeake power station. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum Point power station, Chesapeake and Bremo power stations as settlement of the potential litigation. While the issue is open to potential further negotiations, the Southern Environmental Law Center declined the offer as presented in January 2015 and, in March 2015, filed a lawsuit related to its claims of the alleged CWA violations at Chesapeake power station. Virginia Power filed a motion to dismiss in April 2015, which was denied in November 2015. In March 2017, the court ruled that impacted groundwater associated with the on-site coal ash storage units was migrating to adjacent surface water, which constituted an unpermitted point source discharge in violation of the CWA. The court, however, rejected Sierra Club’s claims that Virginia Power had violated specific conditions of its water discharge permit. Finding no harm to the environment, the court further declined to impose civil penalties or require excavation of the ash from the site as Sierra Club had sought. On remedy, the court ordered the parties to submit within 30 days a remedial plan (or separate plans) incorporating certain prescribed sediment, water and aquatic life monitoring. The court also ordered Virginia Power to reopen its solid waste permit application for closure of the coal ash storage units at Chesapeake power station. In April 2017, Virginia Power submitted its remedial plan to the court, which included a timetable for submitting a revised solid waste permit application to the VDEQ. The revised application will include a proposed remedial alternative to address groundwater impacts associated with coal ash storage at Chesapeake power station. Sierra Club submitted a separate remedial plan to the court. Also in April 2017, Virginia Power and Sierra Club both filed notices of appeal of the court’s March 2017 ruling to the U.S. Court of Appeals for the Fourth Circuit.
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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 April 2016, the EPA announced a partial settlement with certain environmental and industry organizations that had challenged the final CCR rule in the U.S. Court of Appeals for the D.C. Circuit. As part of the settlement, certain exemptions included in the final rule for inactive ponds that closed by April 2018 will be removed, resulting in inactive ponds ultimately being subject to the same requirements as existing ponds. In June 2016, the court issued an order approving the settlement, which requires the EPA to modify provisions in the final CCR rule concerning inactive ponds. In August 2016, the EPA issued a final rule, effective October 2016, extending certain compliance deadlines in the final CCR rule for inactive ponds. Virginia Power does not believe these changes will substantially impact its closure plans for inactive ponds.
In December 2016, the U.S. Congress passed and the President signed legislation that creates a framework for EPA- approved state CCR permit programs. Under this legislation, an approved state CCR permit program functions in lieu of the self-implementing Federal CCR rule. The legislation allows states more flexibility in developing permit programs to implement the environmental criteria in the CCR rule. It is unknown how long it will take for the EPA to develop the framework for state program approvals. The EPA has enforcement authority until these new CCR rules are in place and state programs are approved. The EPA and states with approved programs both will have authority to enforce CCR requirements under their respective rules and programs. Dominion cannot forecast potential incremental impacts or costs related to existing coal ash sites until rules implementing the 2016 CCR legislation are in place.
In April 2017, the Governor of Virginia signed legislation into law that places a moratorium on the VDEQ issuing solid waste permits for closure of ash ponds at Virginia Power’s Bremo, Chesapeake, Chesterfield and Possum Point power stations until May 2018. The law also requires Virginia Power to conduct an assessment of closure alternatives for the ash ponds at these four stations, to include an evaluation of excavation for recycling or off-site disposal, surface and groundwater conditions and safety. The assessments are due by December 1, 2017. Virginia Power is evaluating the legislation and is unable to estimate the potential financial statement impacts. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the obligation.
Dominion is constructing the Liquefaction Project at the Cove Point facility, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project. In October 2014, several parties filed a motion with FERC to stay the order and requested rehearing. In May 2015, FERC denied the requests for stay and rehearing.
Two parties have separately filed petitions for review of the FERC order in the U.S. Court of Appeals for the D.C. Circuit, which petitions were consolidated. Separately, one party requested a stay of the FERC order until the judicial proceedings are complete, which the court denied in June 2015. In July 2016, the court denied one party’s petition for review of the FERC order authorizing the Liquefaction Project. The court also issued a decision remanding the other party’s petition for review of the FERC order to FERC for further explanation of FERC’s decision that a previous transaction with an existing import shipper was not unduly discriminatory. Cove Point believes that on remand FERC will be able to justify its decision.
In September 2013, the DOE granted Non-FTA Authorization approval for the export of up to 0.77 bcfe/day of natural gas to countries that do not have an FTA for trade in natural gas. In June 2016, a party filed a petition for review of this approval in the U.S. Court of Appeals for the D.C. Circuit. This case is pending.
The FERC staff in the Office of Enforcement, Division of Investigations, is conducting a non-public investigation of Virginia Power’s offers of combustion turbines generators into the PJM day-ahead markets from April 2010 through September 2014. The FERC staff notified Virginia Power of its preliminary findings relating to Virginia Power’s alleged violation of FERC’s rules in connection with these activities. Virginia Power has provided its response to the FERC staff’s preliminary findings letter explaining why Virginia Power’s conduct was lawful and refuting any allegation of wrongdoing. Virginia Power is cooperating fully with the investigation; however, it cannot currently predict whether or to what extent it may incur a material liability.
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Virginia Power is constructing Greensville County and related transmission interconnection facilities. In July 2016, the Sierra Club filed an administrative appeal in the Circuit Court for the City of Richmond challenging certain provisions in Greensville County’s PSD air permit issued by VDEQ in June 2016. Virginia Power is currently unable to make an estimate of the potential impacts to its consolidated financial statements related to this matter.
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 the Institute of Nuclear Power Operations. 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 requiring 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 have been implemented. The information requests issued by the NRC request each reactor to reevaluate the seismic and external 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. The walkdowns of each unit have been completed, audited by the NRC and found to be adequate. Reevaluation of the emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevaluation of the seismic and external flooding hazards is expected to continue through 2018. Dominion and Virginia Power do not currently expect that compliance with the NRC’s information requests will materially impact their financial position, results of operations or cash flows during the implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion and Virginia Power do not expect material financial impacts related to compliance with Tier 2 and Tier 3 recommendations.
Guarantees, Surety Bonds and Letters of Credit
At March 31, 2017, Dominion had issued $48 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded.
Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion would be obligated to satisfy such obligation. 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.
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At March 31, 2017, Dominion had issued the following subsidiary guarantees:
Commodity transactions(1)
Nuclear obligations(2)
Cove Point(3)
Solar(4)
Other(5)
Total(6)
Additionally, at March 31, 2017, Dominion had purchased $138 million of surety bonds, including $62 million at Virginia Power and $22 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $76 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 16. 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, 2016.
At March 31, 2017, Dominion’s credit exposure related to energy marketing and price risk management activities totaled $89 million. Of this amount, investment grade counterparties, including those internally rated, represented 65%. No single counterparty, whether investment grade or non-investment grade, exceeded $26 million of exposure. At March 31, 2017, Virginia Power’s exposure related to sales to wholesale customers totaled $28 million. Of this amount, investment grade counterparties, including those internally rated, represented 43%. No single counterparty, whether investment grade or non-investment grade, exceeded $5 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 March 31, 2017, Dominion would not have been required to post any collateral to its counterparties and at December 31, 2016, Dominion would have been required to post an additional $3 million 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 March 31, 2017 or December 31, 2016 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 March 31, 2017 and December 31, 2016 was $4 million and $9 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 March 31, 2017 and December 31, 2016. See Note 9 for further information about derivative instruments.
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Note 17. 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 and, where applicable, combined income tax returns for Dominion are filed in various states. Dominion’s transactions with equity method investments are described in Note 10. 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 March 31, 2017, Virginia Power’s derivative assets and liabilities with affiliates were $27 million and $3 million, respectively. As of December 31, 2016, Virginia Power’s derivative assets and liabilities with affiliates were $41 million and $8 million, respectively. See Note 9 for more information.
Virginia Power participates in certain Dominion benefit plans described in Note 18. At March 31, 2017 and December 31, 2016, amounts due to Dominion associated with the Dominion Pension Plan and included in other deferred credits and other liabilities in the Consolidated Balance Sheets were $423 million and $396 million, respectively. At March 31, 2017 and December 31, 2016, Virginia Power’s amounts due from Dominion associated with the Dominion Retiree Health and Welfare plan and included in other deferred charges and other assets in the Consolidated Balance Sheets were $149 million and $130 million, respectively.
DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage.
The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DRS to Virginia Power on the basis of direct and allocated methods in accordance with Virginia Power’s services agreements with DRS. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DRS resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DRS service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.
Presented below are 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 March 31, 2017. There were $262 million in short-term demand note borrowings from Dominion as of December 31, 2016. Virginia Power had no outstanding borrowings under the Dominion money pool for its nonregulated subsidiaries as of March 31, 2017 and December 31, 2016. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the three months ended March 31, 2017 and 2016.
There were no issuances of Virginia Power’s common stock to Dominion for the three months ended March 31, 2017 and 2016.
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 March 31, 2017 and December 31, 2016, all of Dominion Gas’ commodity derivatives were with affiliates. See Notes 7 and 9 for more information.
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Dominion Gas participates in certain Dominion benefit plans as described in Note 18. At March 31, 2017 and December 31, 2016, amounts due from Dominion associated with the Dominion Pension Plan included in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $706 million and $697 million, respectively. At March 31, 2017 and December 31, 2016, Dominion Gas’ amounts due from Dominion associated with the Dominion Retiree Health and Welfare plan included in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $3 million and $2 million, respectively.
The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DRS to Dominion Gas on the basis of direct and allocated methods in accordance with Dominion Gas’ services agreements with DRS. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DRS resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DRS service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. The costs of these services follow:
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)
Imbalances receivable from affiliates(2)
Imbalances payable to affiliates(3)
Affiliated notes receivable(4)
Dominion Gas’ borrowings under the intercompany revolving credit agreement with Dominion were $174 million and $118 million as of March 31, 2017 and December 31, 2016, respectively. Interest charges related to Dominion Gas’ total borrowings from Dominion were immaterial for the three months ended March 31, 2017 and 2016.
Note 18. Employee Benefit Plans
In the first quarter of 2016, the Companies announced an organizational design initiative that reduced their total workforces during 2016. The goal of the organizational design initiative was to streamline leadership structure and push decision making lower while also improving efficiency. In the first quarter of 2016, Dominion recorded a $70 million ($43 million after-tax) charge, including $40 million ($25 million after-tax) at Virginia Power and $8 million ($5 million after-tax) at Dominion Gas, primarily reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other costs related to the organizational design initiative. The terms of the severance under the organizational design initiative were consistent with the Companies’ existing severance plans.
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Plan Amendment and Remeasurement
In the first quarter of 2017, Dominion and Dominion Gas remeasured an other postretirement benefit plan as a result of an amendment that changed post-65 retiree medical coverage for certain current and future Local 69 retirees effective July 1, 2017. The remeasurement resulted in a decrease in Dominion’s and Dominion Gas’ accumulated postretirement benefit obligation of $73 million and $61 million, respectively. As a result of regulatory accounting, the remeasurement will have an immaterial impact on net income for both Dominion and Dominion Gas. The discount rate used for the remeasurement was 4.30%. All other assumptions used were consistent with the measurement as of December 31, 2016.
In the first quarter of 2017, Dominion recorded a $7 million ($4 million after-tax) charge, including $6 million ($4 million after-tax) at Dominion Gas, as a result of additional payments associated with the new collective bargaining agreement, which is reflected in other operations and maintenance expense in their Consolidated Statements of Income.
The components of Dominion’s provision for net periodic benefit cost (credit) were as follows:
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service credit
Amortization of net actuarial loss
Net periodic benefit cost (credit)
Employer Contributions
During the three months ended March 31, 2017, Dominion made no contributions to its defined benefit pension plans or other postretirement benefit plans, except for a $75 million contribution made in January 2017 to Dominion Questar’s qualified pension plan to satisfy a regulatory condition to closing of the Dominion Questar Combination. Dominion expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs during the remainder of 2017.
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, 2016. See Note 17 for more information.
The components of Dominion Gas’ provision for net periodic benefit credit for employees represented by collective bargaining units were as follows:
Net periodic benefit credit
During the three months ended March 31, 2017, 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 2017.
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Note 19. 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
Regulated electric distribution
Regulated electric transmission
Dominion Generation
Regulated electric fleet
Merchant electric fleet
Dominion Energy
Gas transmission and storage
Gas distribution and storage
Gas gathering and processing
LNG import and storage
Nonregulated retail energy marketing
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 in allocating resources.
In the three months ended March 31, 2017, Dominion reported after-tax net income of $21 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segments. In the three months ended March 31, 2016, Dominion reported an after-tax net expense of $48 million for specific items in the Corporate and Other segment, with $38 million of these net expenses attributable to its operating segments.
The net income for specific items attributable to Dominion’s operating segments in 2017 primarily related to the impact of the following item which was attributable to Dominion Generation:
The net expense for specific items attributable to Dominion’s operating segments in 2016 primarily related to the impact of the following item:
The following table presents segment information pertaining to Dominion’s operations:
Total revenue from external customers
Intersegment revenue
Net income (loss) attributable to Dominion
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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 in allocating resources.
In the three months ended March 31, 2017, Virginia Power reported after-tax net income of $2 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segments. In the three months ended March 31, 2016, Virginia Power reported an after-tax net expense of $26 million for specific items in the Corporate and Other segment, with $25 million of these net expenses attributable to its operating segments.
The net expense for specific items attributable to Virginia Power’s operating segments in 2016 primarily related to the impact of the following item:
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 or in allocating resources and the effect of certain items recorded at Dominion Gas as a result of Dominion’s basis in the net assets contributed.
In the three months ended March 31, 2017, Dominion Gas reported no specific items in the Corporate and Other segment. In the three months ended March 31, 2016, Dominion Gas reported an after-tax net expense of $2 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segment.
The net expense for specific items in 2016 primarily related to an $8 million ($5 million after-tax) charge related to an organizational design initiative.
The following table presents segment information pertaining to Dominion Gas’ operations:
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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:
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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, 2016.
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 March 31, 2017, 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, 2016. 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.
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Results of Operations
Presented below is a summary of Dominion’s consolidated results:
First Quarter
Diluted EPS
Overview
First Quarter 2017 vs. 2016
Net income attributable to Dominion increased 21%, primarily due to the Dominion Questar Combination, the PJM capacity performance market effective June 2016, the absence of organizational design initiative costs, and an increase in sales to utility customers due to the effect of changes in customer usage and other factors. These increases were partially offset by an increase in interest expense and a decrease in sales to utility customers from a reduction in heating degree days.
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 20%, primarily reflecting:
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Other operations and maintenance increased 5%, primarily reflecting:
Depreciation, depletion and amortization increased 34%, primarily due to the Dominion Questar Combination ($56 million), and various expansion projects being placed into service ($45 million).
Other income increased $62 million, primarily reflecting:
Interest and related charges increased 29%, primarily due to higher long-term debt interest expense resulting from debt issuances in 2016 and the first quarter of 2017 ($51 million) and debt acquired in the Dominion Questar Combination ($14 million).
Income tax expense increased 54%, primarily due to higher pre-tax income and an increased effective tax rate, principally due to lower renewable energy investment tax credits.
Noncontrolling interests increased $35 million, primarily due to an increase in the Dominion Midstream earnings attributable to public unitholders ($18 million) and Four Brothers and Three Cedars earnings attributable to NRG ($17 million).
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
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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)
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
2017 vs. 2016
Increase (Decrease)
Regulated electric sales:
Weather
FERC transmission equity return
Storm damage and service restoration
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):
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Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
Electric capacity
Rate adjustment clause equity return
Noncontrolling interest(1)
Interest expense
Presented below are selected operating statistics related to Dominion Energy’s operations:
Gas distribution throughput (bcf)(1):
Sales
Transportation
Heating degree days (gas distribution service area):
Eastern region
Western region(1)
Average gas distribution customer accounts (thousands)(1)(2):
Average retail energy marketing customer accounts (thousands)(2)
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:
Cove Point import contracts
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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
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. See Note 19 to the Consolidated Financial Statements in this report for discussion of these items in more detail. Corporate and other also includes items attributable to the Corporate and Other segment.
Presented below is a summary of Virginia Power’s consolidated results:
Net income increased 35%, primarily due to the PJM capacity performance market effective June 2016, an increase in sales to retail customers due to the effect of changes in customer usage and other factors, and the absence of organizational design initiative costs. These increases were partially offset by a decrease in sales to retail customers from a reduction in heating degree days.
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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:
Other operations and maintenance decreased 17%, primarily reflecting:
Depreciation and amortization increased 15%, primarily due to various expansion projects being placed into service ($22 million) and revised depreciation rates ($10 million).
Other income increased 94%, primarily reflecting:
Income tax expenseincreased 36%, primarily due to higher pre-tax income.
Presented below is a summary of Dominion Gas’ consolidated results:
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Net income increased 10%, primarily due to an increase in gas transportation and storage activities from expansion projects placed into service and decreased net fuel costs.
Presented below are selected amounts related to Dominion Gas’ results of operations:
An analysis of Dominion Gas’ results of operations follows:
Net revenue increased 12%, primarily reflecting:
Other operations and maintenance increased 27%, primarily reflecting:
Liquidity and Capital Resources
Dominion depends on both internal and external sources of liquidity to provide working capital and as a bridge to long-term debt financings. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.
At March 31, 2017, Dominion had $2.8 billion of unused capacity under its credit facilities. See Note 14 to the Consolidated Financial Statements for more information.
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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 increase (decrease) in cash and cash equivalents
Cash and cash equivalents at March 31
Operating Cash Flows
Net cash provided by Dominion’s operating activities increased $168 million, primarily due to the Dominion Questar Combination, the benefit from the PJM capacity performance market, and proceeds from the assignment of the electric transmission tower rental portfolio, partially offset by lower deferred fuel cost recoveries in the Virginia jurisdiction and Dominion’s contribution to Dominion Questar’s pension plan.
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, 2016.
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 March 31, 2017 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 $169 million, primarily due to increased investment in Atlantic Coast Pipeline and the acquisition of solar development projects.
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, 2016, 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.
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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.
Net cash provided by Dominion’s financing activities was $559 million in 2017, as compared to net cash used in financing activities of $56 million in 2016, primarily due to higher net debt issuances, partially offset by the absence of the proceeds from the sale of interest in merchant solar projects in the first quarter of 2016, and lower contributions to Four Brothers and Three Cedars from NRG in 2017 compared to contributions from SunEdison in 2016.
See Notes 3 and 14 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, 2016, 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 March 31, 2017, 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, 2016, there is a discussion on the various covenants present in the enabling agreements underlying Dominion’s debt. As of March 31, 2017, there have been no material changes to debt covenants, nor any events of default under Dominion’s debt covenants. Pursuant to a waiver received in April 2016 and in connection with the closing of the Dominion Questar Combination, the 65% maximum debt to total capital ratio in Dominion’s credit agreements has, with respect to Dominion only, been temporarily increased to 70% until the end of the fiscal quarter ending June 30, 2017.
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
As of March 31, 2017, 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, 2016.
Use of Off-Balance Sheet Arrangements
As of March 31, 2017, 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, 2016.
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, 2016.
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-Kfor the year ended December 31, 2016, and Note 15 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
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generating units or equivalent statewide intensity-based or mass-based CO2 binding goals or limits. States are required to submit final plans identifying how they will comply with the rule by September 2018. The EPA also issued a proposed federal implementation plan and model trading rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. The final rule has been challenged in the U.S. Court of Appeals for the D.C. Circuit. In February 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan until the disposition of the petitions challenging the rule now before the Court of Appeals, and, if such petitions are filed in the future, before the U.S. Supreme Court. In June 2016, the Governor of Virginia signed an executive order directing the Virginia Natural Resources Secretary to convene a workgroup charged with recommending concrete steps to reduce carbon pollution from power plants which could include reductions at levels similar to the Clean Power Plan as an option. In March 2017, the President issued an Executive Order directing the EPA to undertake a review of the Clean Power Plan that could result in significant revisions to, or rescinding of, the rule. In April 2017, the U.S. Court of Appeals for the D.C. Circuit issued an order suspending the cases challenging the Clean Power Plan for 60 days to allow the EPA time to determine whether to revise or rescind the rule. Also in April 2017, the EPA issued a notice withdrawing the proposed federal implementation plan and model trading rules. Given these developments and associated federal and state regulatory and legal uncertainties, Dominion cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.
Climate Change
In March 2016, as part of its Climate Action Plan, the EPA began development of regulations for reducing methane emissions from existing sources in the oil and natural gas sectors. In November 2016, the EPA issued an Information Collection Request to collect information on existing sources upstream of local distribution companies in this sector. In March 2017, the EPA withdrew the Information Collection Request. Dominion cannot currently estimate the impacts on results of operations, financial condition and/or cash flows related to this matter.
Legal Matters
See Item 3. Legal Proceedings in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2016, and Notes 12 and 15 to the Consolidated Financial Statements and Item 1. Legal Proceedings in this report for additional information on various legal matters.
Collective Bargaining Agreement
In March 2017, members of the Local 69 ratified a new four-year labor contract. The new contract is retroactive to April 1, 2016 and runs through April 1, 2020. Local 69 represents about 760 DTI employees in West Virginia, Maryland, New York, Pennsylvania, Ohio and Virginia and about 150 Hope employees in West Virginia.
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, 2016, and Note 12 to the Consolidated Financial Statements in this report for additional information on various regulatory matters.
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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 hold commodity-based derivative instruments held for non-tradingpurposes associated with purchases and sales of electricity, natural gas and other energy-related products and Dominion Gas 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 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 would have resulted in a decrease in fair value of $20 million and $27 million of Dominion’s commodity-based derivative instruments as of March 31, 2017 and December 31, 2016, respectively.
A hypothetical 10% decrease in commodity prices would have resulted in a decrease in the fair value of $55 million and $62 million of Virginia Power’s commodity-based derivative instruments as of March 31, 2017 and December 31, 2016, respectively.
A hypothetical 10% increase in commodity prices would have resulted in a decrease in fair value of $5 million and $4 million of Dominion Gas’ commodity-based derivative instruments as of March 31, 2017 and December 31, 2016, respectively.
The impact of a change in energy commodity prices on the Companies’ commodity-based 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-based financial 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 March 31, 2017 or December 31, 2016.
The Companies also use interest rate derivatives, including forward-starting swaps, as cash flow hedges of forecasted interest payments. As of March 31, 2017, Dominion and Virginia Power had $4.4 billion and $2.2 billion, respectively, in aggregate
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notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $80 million and $67 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at March 31, 2017. As of December 31, 2016, Dominion and Virginia Power had $2.9 billion and $1.7 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $58 million and $45 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at December 31, 2016.
Dominion Gas holds foreign currency swaps for the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of March 31, 2017 and December 31, 2016, Dominion and Dominion Gas had $280 million (€250 million) in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% increase in market interest rates would have resulted in a $6 million and $5 million decrease in the fair value of Dominion Gas’ foreign currency swaps at March 31, 2017 and December 31, 2016, respectively.
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 $100 million and $28 million for the three months ended March 31, 2017 and 2016, respectively, and $144 million for the year ended December 31, 2016. 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 increase in unrealized gains on these investments of $76 million and $38 million for the three months ended March 31, 2017 and 2016, respectively, and $183 million for the year ended December 31, 2016.
Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $47 million and $13 million for the three months ended March 31, 2017 and 2016, respectively, and $67 million for the year ended December 31, 2016. 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 increase in unrealized gains on these investments of $34 million and $23 million for the three months March 31, 2017 and 2016, respectively, and $93 million for the year ended December 31, 2016.
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.
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.
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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, which information is incorporated herein by reference:
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, 2016, 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, 2016. 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 in this report.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
ISSUER PURCHASES OF EQUITY SECURITIES
Period
1/1/17-1/31/17
$1.18 billion
2/1/17-2/28/17
3/1/17-3/31/17
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ITEM 6. EXHIBITS
Exhibit
Description
VirginiaPower
DominionGas
85
86
87
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.
Registrant
/s/ Michele L. Cardiff
Michele L. Cardiff
Vice President, Controller and
Chief Accounting Officer
88
EXHIBIT INDEX
89
90
91