UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 20172020
or
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number |
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GAS HOLDINGS, LLC |
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Formerly Known As Dominion Energy Gas Holdings, LLC |
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| 120 Tredegar Street Richmond, Virginia 23219 (804) 819-2000 |
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State or other jurisdiction of incorporation or organization of the registrants: Virginia
Securities registered pursuant to Section 12(b) of the Act:
Registrant | Trading Symbol | Title of Each Class | Name of Each Exchange on Which Registered |
EASTERN ENERGY GAS HOLDINGS, LLC | 2014 Series C 4.6% Senior Notes | New York Stock Exchange |
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 Energy, Inc.
Yes ☒ No ☐ Virginia Electric and Power Company Yes ☒ No ☐
Dominion Energy Gas Holdings, LLC Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Dominion Energy, Inc.
Yes ☒ No ☐ Virginia Electric and Power Company Yes ☒ No ☐
Dominion Energy Gas Holdings, LLC Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Dominion Energy, Inc.
Large accelerated filer |
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| Accelerated filer | ☐ | Emerging growth company | ☐ |
Non-accelerated filer |
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Emerging growth company
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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
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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. ☐
Dominion Energy Gas Holdings, LLC
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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. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Dominion Energy, Inc. Yes ☐ No ☒ Virginia Electric and Power Company Yes ☐ No ☒
Dominion Energy Gas Holdings, LLC Yes ☐ No ☒
At October 13, 2017, the latest practicable date for determination, Dominion Energy, Inc. had 643,529,769 shares of common stock outstanding and Virginia Electric and Power Company had 274,723 shares of common stock outstanding. Dominion Energy, Inc. is the sole holder of Virginia Electric and Power Company’s common stock. Dominion Energy, Inc. holds allAll of the membership interests of Dominion Energy Gas Holdings, LLC.
This combined Form 10-Q represents separate filings by Dominion Energy, Inc., Virginia Electric and Power Company and Dominion Energy 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 DominionEastern Energy Gas Holdings, LLC make no representationsis held by its indirect parent company, Berkshire Hathaway Energy Company, as to the information relating to Dominion Energy, Inc.’s other operations.of November 12, 2020.
VIRGINIA ELECTRIC AND POWER COMPANY AND DOMINION
EASTERN ENERGY GAS HOLDINGS, LLC MEETMEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND AREIS FILING THIS FORM 10-Q UNDER THE REDUCED DISCLOSURE FORMAT.
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Item 1. |
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Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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Item 3. |
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Item 4. |
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Item 1. |
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Item 1A. |
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Item 6. |
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GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Form 10-Q are defined below:
Abbreviation or Acronym |
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AFUDC |
| Allowance for funds used during construction |
AOCI |
| Accumulated other comprehensive income (loss) |
ARO |
| Asset retirement obligation |
Atlantic Coast Pipeline |
| Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion Energy and Duke |
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BHE | Berkshire Hathaway Energy Company | |
Brookfield | Brookfield Super-Core Infrastructure Partners, an infrastructure fund managed by Brookfield Asset Management Inc. | |
CAA |
| Clean Air Act |
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CERCLA |
| Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund |
CFO |
| Chief Financial Officer |
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Cove Point |
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CWA |
| Clean Water Act |
DCP | The legal entity, CPMLP Holdings Company, LLC (formerly known as Dominion Cove Point, LLC), one or more of its consolidated subsidiaries, or the entirety of CPMLP Holdings Company, LLC and its consolidated subsidiaries | |
DECG |
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DECGS | Carolina Gas Services, Inc. (formerly known as Dominion Energy Carolina Gas Services, Inc.) | |
DEQPS | Dominion Energy Questar Pipeline Services, Inc. | |
DES |
| Dominion Energy Services, Inc. |
DETI |
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DMLPHCII | Eastern MLP Holding Company II, LLC (formerly known as Dominion MLP Holding Company II, LLC) | |
Dominion Energy |
| The legal entity, Dominion Energy, Inc. |
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Restructuring |
| The |
Dominion Energy Midstream |
| The legal entity, |
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Dominion Energy Questar |
| The legal entity, Dominion Energy Questar Corporation, |
Dominion Energy Questar |
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| The legal entity, Dominion Energy Questar Pipeline, LLC, |
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East Ohio |
| The East Ohio Gas Company, doing business as Dominion Energy Ohio |
Eastern |
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EPA |
| U.S. Environmental Protection Agency |
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FERC |
| Federal Energy Regulatory Commission |
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GAAP |
| U.S. generally accepted accounting principles |
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GHG |
| Greenhouse gas |
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Iroquois |
| Iroquois Gas Transmission System, L.P. |
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Liquefaction |
| A natural gas export/liquefaction facility |
LNG |
| Liquefied natural gas |
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MD&A |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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NSPS |
| New Source Performance Standards |
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SEC |
| U.S. Securities and Exchange Commission |
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VEBA |
| Voluntary |
VIE |
| Variable interest entity |
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VOC |
| Volatile organic compounds |
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4
PART I. FINANCIALFINANCIAL INFORMATION
DOMINION
EASTERN ENERGY INC.GAS HOLDINGS, LLC
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
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| Three Months Ended September 30, |
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| Nine Months Ended September 30, |
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| 2017 |
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| 2016 |
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| 2017 |
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| 2016 |
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(millions, except per share amounts) |
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Operating Revenue |
| $ | 3,179 |
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| $ | 3,132 |
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| $ | 9,376 |
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| $ | 8,651 |
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Operating Expenses |
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Electric fuel and other energy-related purchases |
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| 638 |
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| 606 |
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| 1,711 |
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| 1,791 |
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Purchased (excess) electric capacity |
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| 21 |
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| (6 | ) |
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| (8 | ) |
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| 107 |
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Purchased gas |
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| 24 |
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| 77 |
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| 441 |
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| 252 |
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Other operations and maintenance |
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| 649 |
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| 765 |
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| 2,166 |
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| 2,133 |
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Depreciation, depletion and amortization |
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| 485 |
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| 400 |
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| 1,421 |
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| 1,112 |
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Other taxes |
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| 162 |
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| 145 |
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| 519 |
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| 448 |
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Total operating expenses |
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| 1,979 |
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| 1,987 |
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| 6,250 |
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| 5,843 |
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Income from operations |
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| 1,200 |
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| 1,145 |
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| 3,126 |
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| 2,808 |
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Other income |
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| 73 |
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| 63 |
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| 249 |
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| 189 |
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Interest and related charges |
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| 305 |
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| 250 |
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| 905 |
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| 715 |
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Income from operations including noncontrolling interests before income tax expense |
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| 968 |
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| 958 |
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| 2,470 |
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| 2,282 |
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Income tax expense |
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| 272 |
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| 230 |
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| 683 |
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| 561 |
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Net Income Including Noncontrolling Interests |
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| 696 |
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| 728 |
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| 1,787 |
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| 1,721 |
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Noncontrolling Interests |
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| 31 |
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| 38 |
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| 100 |
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| 55 |
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Net Income Attributable to Dominion Energy |
| $ | 665 |
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| $ | 690 |
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| $ | 1,687 |
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| $ | 1,666 |
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Earnings Per Common Share |
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Net income attributable to Dominion Energy - Basic |
| $ | 1.03 |
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| $ | 1.10 |
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| $ | 2.66 |
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| $ | 2.72 |
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Net income attributable to Dominion Energy - Diluted |
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| 1.03 |
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| 1.10 |
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| 2.66 |
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| 2.71 |
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Dividends Declared Per Common Share |
| $ | 0.7700 |
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| $ | 0.7000 |
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| $ | 2.2800 |
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| $ | 2.1000 |
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The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
|
| Three Months Ended September 30, |
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| Nine Months Ended September 30, |
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| 2017 |
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| 2016 |
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| 2016 |
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(millions) |
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Net income including noncontrolling interests |
| $ | 696 |
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| $ | 728 |
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| $ | 1,787 |
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| $ | 1,721 |
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Other comprehensive income, net of taxes: |
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Net deferred gains on derivatives-hedging activities(1) |
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| 11 |
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| 14 |
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| 82 |
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| 56 |
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Changes in unrealized net gains on investment securities(2) |
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| 48 |
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| 31 |
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| 141 |
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| 72 |
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Changes in net unrecognized pension and other postretirement benefit costs(3) |
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| — |
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| 15 |
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| — |
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| 15 |
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Amounts reclassified to net income: |
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Net derivative gains-hedging activities(4) |
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| (15 | ) |
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| (34 | ) |
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| (56 | ) |
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| (141 | ) |
Net realized gains on investment securities(5) |
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| (4 | ) |
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| (13 | ) |
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| (36 | ) |
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| (23 | ) |
Net pension and other postretirement benefit costs(6) |
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| 14 |
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| 9 |
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| 38 |
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| 25 |
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Changes in other comprehensive income (loss) from equity method investees(7) |
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| — |
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| — |
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| 2 |
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| (1 | ) |
Total other comprehensive income |
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| 54 |
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| 22 |
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| 171 |
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| 3 |
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Comprehensive income including noncontrolling interests |
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| 750 |
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| 750 |
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| 1,958 |
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| 1,724 |
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Comprehensive income attributable to noncontrolling interests |
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| 31 |
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| 38 |
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| 100 |
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| 55 |
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Comprehensive income attributable to Dominion Energy |
| $ | 719 |
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| $ | 712 |
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| $ | 1,858 |
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| $ | 1,669 |
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| Three Months Ended September 30, |
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| Nine Months Ended September 30, |
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| 2020 |
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| 2019 |
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| 2020 |
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| 2019 |
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(millions) |
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Operating Revenue(1) |
| $ | 531 |
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| $ | 502 |
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| $ | 1,597 |
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| $ | 1,598 |
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Operating Expenses |
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Purchased gas(1) |
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| 14 |
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| 3 |
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| 22 |
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| 12 |
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Other energy-related purchases |
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| — |
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| 1 |
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| 1 |
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| 2 |
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Other operations and maintenance: |
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Affiliated suppliers |
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| 31 |
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| 32 |
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| 110 |
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| 125 |
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Other |
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| 105 |
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| 134 |
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| 341 |
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| 427 |
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Depreciation and amortization |
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| 95 |
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| 92 |
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| 282 |
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| 274 |
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Other taxes |
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| 40 |
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| 40 |
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| 117 |
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| 118 |
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Impairment of assets and other charges (benefits) |
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| (19 | ) |
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| — |
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| 463 |
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| 13 |
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Gains on sales of assets |
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| — |
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| (2 | ) |
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| — |
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| (2 | ) |
Total operating expenses |
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| 266 |
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| 300 |
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| 1,336 |
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| 969 |
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Income from continuing operations |
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| 265 |
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| 202 |
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| 261 |
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| 629 |
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Earnings from equity method investees |
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| 7 |
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| 8 |
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| 30 |
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| 30 |
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Other income(1) |
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| 22 |
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| 46 |
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| 117 |
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| 131 |
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Interest and related charges(1) |
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| 186 |
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| 88 |
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| 294 |
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| 261 |
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Income from continuing operations before income tax expense |
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| 108 |
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| 168 |
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| 114 |
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| 529 |
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Income tax expense (benefit) |
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| (10 | ) |
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| 38 |
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| (40 | ) |
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| 104 |
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Net income from continuing operations |
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| 118 |
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| 130 |
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| 154 |
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| 425 |
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Net income from discontinued operations |
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| 0 |
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| 45 |
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| 0 |
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| 125 |
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Net income including noncontrolling interests |
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| 118 |
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| 175 |
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| 154 |
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| 550 |
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Noncontrolling interests |
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| 32 |
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| 24 |
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|
| 97 |
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|
| 90 |
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Net Income Attributable to Eastern Energy |
| $ | 86 |
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| $ | 151 |
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| $ | 57 |
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| $ | 460 |
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(1) |
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The accompanying notes are an integral part of DominionEastern Energy’s Consolidated Financial Statements.
5
DOMINIONEASTERN ENERGY INC.GAS HOLDINGS, LLC
CONSOLIDATED BALANCE SHEETSSTATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
|
| September 30, 2017 |
|
| December 31, 2016(1) |
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(millions) |
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ASSETS |
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Current Assets |
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Cash and cash equivalents |
| $ | 227 |
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| $ | 261 |
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Customer receivables (less allowance for doubtful accounts of $16 and $18) |
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| 1,292 |
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| 1,523 |
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Other receivables (less allowance for doubtful accounts of $3 and $2) |
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| 212 |
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|
| 183 |
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Inventories |
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| 1,527 |
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| 1,524 |
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Regulatory assets |
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| 311 |
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| 244 |
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Other |
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| 425 |
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| 513 |
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Total current assets |
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| 3,994 |
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| 4,248 |
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Investments |
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Nuclear decommissioning trust funds |
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| 4,881 |
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| 4,484 |
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Investment in equity method affiliates |
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| 1,895 |
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| 1,561 |
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Other |
|
| 320 |
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| 298 |
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Total investments |
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| 7,096 |
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| 6,343 |
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Property, Plant and Equipment |
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Property, plant and equipment |
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| 73,610 |
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| 69,556 |
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Accumulated depreciation, depletion and amortization |
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| (20,799 | ) |
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| (19,592 | ) |
Total property, plant and equipment, net |
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| 52,811 |
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| 49,964 |
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Deferred Charges and Other Assets |
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Goodwill |
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| 6,405 |
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| 6,399 |
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Regulatory assets |
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| 2,503 |
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| 2,473 |
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Other |
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| 2,582 |
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|
| 2,183 |
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Total deferred charges and other assets |
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| 11,490 |
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|
| 11,055 |
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Total assets |
| $ | 75,391 |
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| $ | 71,610 |
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| Three Months Ended September 30, |
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| Nine Months Ended September 30, |
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| 2020 |
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| 2019 |
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| 2020 |
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| 2019 |
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(millions) |
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Net income including noncontrolling interests |
| $ | 118 |
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| $ | 175 |
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| $ | 154 |
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| $ | 550 |
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Other comprehensive income (loss), net of taxes: |
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Net deferred gains (losses) on derivatives-hedging activities(1) |
|
| 12 |
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|
| (36 | ) |
|
| (79 | ) |
|
| (87 | ) |
Changes in unrecognized pension and other postretirement benefits(2) |
|
| (4 | ) |
|
| (1 | ) |
|
| (4 | ) |
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| 28 |
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Amounts reclassified to net income (loss): |
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|
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|
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|
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Net derivative (gains) losses-hedging activities(3) |
|
| 99 |
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|
| 9 |
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|
| 103 |
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|
| 10 |
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Net pension and other postretirement benefit costs(4) |
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| 0 |
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|
| 1 |
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|
| 3 |
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|
| 4 |
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Total other comprehensive income (loss) |
|
| 107 |
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|
| (27 | ) |
|
| 23 |
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|
| (45 | ) |
Comprehensive income including noncontrolling interests |
|
| 225 |
|
|
| 148 |
|
|
| 177 |
|
|
| 505 |
|
Comprehensive income attributable to noncontrolling interests |
|
| 32 |
|
|
| 24 |
|
|
| 97 |
|
|
| 89 |
|
Comprehensive income attributable to Eastern Energy |
| $ | 193 |
|
| $ | 124 |
|
| $ | 80 |
|
| $ | 416 |
|
��
(1) |
|
(2) | Net of $2 million and $0 million tax for the three months ended September 30, 2020 and 2019, respectively, and $2 million and $(11) million tax for the nine months ended September 30, 2020 and 2019, respectively. |
(3) | Net of $(34) million and $(3) million tax for the three months ended September 30, 2020 and 2019, respectively, and $(36) million and $(3) million tax for the nine months ended September 30, 2020 and 2019, respectively. |
(4) | Net of $(1) million and $0 million tax for the three months ended September 30, 2020 and 2019, respectively, and $(2) million and $(1) million tax for the nine months ended September 30, 2020 and 2019, respectively. |
The accompanying notes are an integral part of DominionEastern Energy’s Consolidated Financial Statements.
EASTERN ENERGY INC.GAS HOLDINGS, LLC
CONSOLIDATED BALANCE SHEETS—(Continued)SHEETS
(Unaudited)
|
| September 30, 2017 |
|
| December 31, 2016(1) |
| ||
(millions) |
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Securities due within one year |
| $ | 2,788 |
|
| $ | 1,709 |
|
Short-term debt |
|
| 3,060 |
|
|
| 3,155 |
|
Accounts payable |
|
| 757 |
|
|
| 1,000 |
|
Accrued interest, payroll and taxes |
|
| 843 |
|
|
| 798 |
|
Regulatory liabilities |
|
| 88 |
|
|
| 163 |
|
Other |
|
| 1,023 |
|
|
| 1,290 |
|
Total current liabilities |
|
| 8,559 |
|
|
| 8,115 |
|
Long-Term Debt |
|
|
|
|
|
|
|
|
Long-term debt |
|
| 25,529 |
|
|
| 24,878 |
|
Junior subordinated notes |
|
| 3,980 |
|
|
| 2,980 |
|
Remarketable subordinated notes |
|
| 1,377 |
|
|
| 2,373 |
|
Total long-term debt |
|
| 30,886 |
|
|
| 30,231 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes and investment tax credits |
|
| 9,379 |
|
|
| 8,602 |
|
Regulatory liabilities |
|
| 2,906 |
|
|
| 2,622 |
|
Other |
|
| 5,159 |
|
|
| 5,200 |
|
Total deferred credits and other liabilities |
|
| 17,444 |
|
|
| 16,424 |
|
Total liabilities |
|
| 56,889 |
|
|
| 54,770 |
|
Commitments and Contingencies (see Note 15) |
|
|
|
|
|
|
|
|
Equity |
|
|
|
|
|
|
|
|
Common stock – no par(2) |
|
| 9,789 |
|
|
| 8,550 |
|
Retained earnings |
|
| 7,119 |
|
|
| 6,854 |
|
Accumulated other comprehensive loss |
|
| (628 | ) |
|
| (799 | ) |
Total common shareholders' equity |
|
| 16,280 |
|
|
| 14,605 |
|
Noncontrolling interests |
|
| 2,222 |
|
|
| 2,235 |
|
Total equity |
|
| 18,502 |
|
|
| 16,840 |
|
Total liabilities and equity |
| $ | 75,391 |
|
| $ | 71,610 |
|
|
| September 30, 2020 |
|
| December 31, 2019(1) |
| ||
(millions) |
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 40 |
|
| $ | 27 |
|
Customer receivables (less allowance for doubtful accounts of $7 and $2) |
|
| 155 |
|
|
| 173 |
|
Other receivables(2) |
|
| 3 |
|
|
| 26 |
|
Affiliated receivables |
|
| 152 |
|
|
| 362 |
|
Affiliated notes receivable |
|
| 240 |
|
|
| 0 |
|
Inventories |
|
| 128 |
|
|
| 122 |
|
Prepayments |
|
| 90 |
|
|
| 73 |
|
Gas imbalances(2) |
|
| 22 |
|
|
| 52 |
|
Other |
|
| 26 |
|
|
| 23 |
|
Total current assets |
|
| 856 |
|
|
| 858 |
|
Investments |
|
|
|
|
|
|
|
|
Affiliated notes receivable |
|
| 0 |
|
|
| 3,437 |
|
Investment in equity method affiliates |
|
| 279 |
|
|
| 312 |
|
Total investments |
|
| 279 |
|
|
| 3,749 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
| 14,999 |
|
|
| 15,166 |
|
Accumulated depreciation and amortization |
|
| (3,773 | ) |
|
| (3,538 | ) |
Total property, plant and equipment, net |
|
| 11,226 |
|
|
| 11,628 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Goodwill |
|
| 1,471 |
|
|
| 1,471 |
|
Other(2) |
|
| 1,115 |
|
|
| 1,078 |
|
Total deferred charges and other assets |
|
| 2,586 |
|
|
| 2,549 |
|
Total assets |
| $ | 14,947 |
|
| $ | 18,784 |
|
(1) |
|
(2) |
|
The accompanying notes are an integral part of DominionEastern Energy’s Consolidated Financial Statements.
7
EASTERN ENERGY GAS HOLDINGS, LLC
CONSOLIDATED BALANCE SHEETS—(Continued)
(Unaudited)
|
| September 30, 2020 |
|
| December 31, 2019(1) |
| ||
(millions) |
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Securities due within one year |
| $ | 1,199 |
|
| $ | 700 |
|
Short-term debt |
|
| 0 |
|
|
| 62 |
|
Accounts payable |
|
| 81 |
|
|
| 59 |
|
Payables to affiliates |
|
| 97 |
|
|
| 82 |
|
Affiliated current borrowings |
|
| 7 |
|
|
| 260 |
|
Accrued interest, payroll and taxes |
|
| 160 |
|
|
| 128 |
|
Derivative liabilities |
|
| 186 |
|
|
| 33 |
|
Other(2) |
|
| 159 |
|
|
| 128 |
|
Total current liabilities |
|
| 1,889 |
|
|
| 1,452 |
|
Long-Term Debt |
|
|
|
|
|
|
|
|
Long-term debt |
|
| 4,337 |
|
|
| 4,821 |
|
Finance leases |
|
| 4 |
|
|
| 5 |
|
Total long-term debt |
|
| 4,341 |
|
|
| 4,826 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes |
|
| 1,189 |
|
|
| 1,288 |
|
Other |
|
| 978 |
|
|
| 989 |
|
Total deferred credits and other liabilities |
|
| 2,167 |
|
|
| 2,277 |
|
Total liabilities |
|
| 8,397 |
|
|
| 8,555 |
|
Commitments and Contingencies (see Note 14) |
|
|
|
|
|
|
|
|
Equity |
|
|
|
|
|
|
|
|
Membership interests |
|
| 5,343 |
|
|
| 9,031 |
|
Accumulated other comprehensive loss |
|
| (164 | ) |
|
| (187 | ) |
Total members' equity |
|
| 5,179 |
|
|
| 8,844 |
|
Noncontrolling interests |
|
| 1,371 |
|
|
| 1,385 |
|
Total equity |
|
| 6,550 |
|
|
| 10,229 |
|
Total liabilities and equity |
| $ | 14,947 |
|
| $ | 18,784 |
|
(1) | Eastern Energy’s Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date. |
(2) | See Note 16 for amounts attributable to related parties. |
The accompanying notes are an integral part of Eastern Energy’s Consolidated Financial Statements.
8
EASTERN ENERGY, INC. GAS HOLDINGS, LLC
CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
QUARTER-TO-DATE
|
| Common Stock |
|
| Dominion Energy Shareholders |
|
| Total Common |
|
|
|
|
|
|
|
|
| |||||||||||
|
| Shares |
|
| Amount |
|
| Retained Earnings |
|
| AOCI |
|
| Shareholders' Equity |
|
| Noncontrolling Interests |
|
| Total Equity |
| |||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015 |
|
| 596 |
|
| $ | 6,680 |
|
| $ | 6,458 |
|
| $ | (474 | ) |
| $ | 12,664 |
|
| $ | 938 |
|
| $ | 13,602 |
|
Net income including noncontrolling interests |
|
|
|
|
|
|
|
|
|
| 1,666 |
|
|
|
|
|
|
| 1,666 |
|
|
| 55 |
|
|
| 1,721 |
|
Contributions from SunEdison to Four Brothers and Three Cedars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| — |
|
|
| 178 |
|
|
| 178 |
|
Sale of interest in merchant solar projects |
|
|
|
|
|
| 22 |
|
|
|
|
|
|
|
|
|
|
| 22 |
|
|
| 117 |
|
|
| 139 |
|
Purchase of Dominion Energy Midstream common units |
|
|
|
|
|
| (3 | ) |
|
|
|
|
|
|
|
|
|
| (3 | ) |
|
| (14 | ) |
|
| (17 | ) |
Issuance of common stock |
|
| 31 |
|
|
| 2,079 |
|
|
|
|
|
|
|
|
|
|
| 2,079 |
|
|
|
|
|
|
| 2,079 |
|
Stock awards (net of change in unearned compensation) |
|
|
|
|
|
| 10 |
|
|
|
|
|
|
|
|
|
|
| 10 |
|
|
|
|
|
|
| 10 |
|
Present value of stock purchase contract payments related to RSNs |
|
|
|
|
|
| (191 | ) |
|
|
|
|
|
|
|
|
|
| (191 | ) |
|
|
|
|
|
| (191 | ) |
Dividends and distributions |
|
|
|
|
|
|
|
|
|
| (1,287 | ) |
|
|
|
|
|
| (1,287 | ) |
|
| (39 | ) |
|
| (1,326 | ) |
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 3 |
|
|
| 3 |
|
|
|
|
|
|
| 3 |
|
Other |
|
|
|
|
|
| (5 | ) |
|
|
|
|
|
|
|
|
|
| (5 | ) |
|
| (1 | ) |
|
| (6 | ) |
September 30, 2016 |
|
| 627 |
|
| $ | 8,592 |
|
| $ | 6,837 |
|
| $ | (471 | ) |
| $ | 14,958 |
|
| $ | 1,234 |
|
| $ | 16,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016 |
|
| 628 |
|
| $ | 8,550 |
|
| $ | 6,854 |
|
| $ | (799 | ) |
| $ | 14,605 |
|
| $ | 2,235 |
|
| $ | 16,840 |
|
Net income including noncontrolling interests |
|
|
|
|
|
|
|
|
|
| 1,687 |
|
|
|
|
|
|
| 1,687 |
|
|
| 100 |
|
|
| 1,787 |
|
Contributions from NRG to Four Brothers and Three Cedars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| — |
|
|
| 9 |
|
|
| 9 |
|
Issuance of common stock |
|
| 16 |
|
|
| 1,232 |
|
|
|
|
|
|
|
|
|
|
| 1,232 |
|
|
|
|
|
|
| 1,232 |
|
Stock awards (net of change in unearned compensation) |
|
|
|
|
|
| 17 |
|
|
|
|
|
|
|
|
|
|
| 17 |
|
|
|
|
|
|
| 17 |
|
Dividends and distributions |
|
|
|
|
|
|
|
|
|
| (1,435 | ) |
|
|
|
|
|
| (1,435 | ) |
|
| (123 | ) |
|
| (1,558 | ) |
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
| 171 |
|
|
| 171 |
|
|
|
|
|
|
| 171 |
|
Other |
|
|
|
|
|
| (10 | ) |
|
| 13 |
|
| . |
|
|
| 3 |
|
| 1 |
|
|
| 4 |
| ||
September 30, 2017 |
|
| 644 |
|
| $ | 9,789 |
|
| $ | 7,119 |
|
| $ | (628 | ) |
| $ | 16,280 |
|
| $ | 2,222 |
|
| $ | 18,502 |
|
|
| Predecessor Equity |
|
| Membership Interests |
|
| AOCI |
|
| Total Members' Equity |
|
| Noncontrolling Interests |
|
| Total |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2019 |
| $ | 2,859 |
|
| $ | 4,729 |
|
| $ | (186 | ) |
| $ | 7,402 |
|
| $ | 1,427 |
|
| $ | 8,829 |
|
Net income |
|
| 59 |
|
|
| 92 |
|
|
|
|
|
|
| 151 |
|
|
| 24 |
|
|
| 175 |
|
Dividends and distributions |
|
| (189 | ) |
|
|
|
|
|
|
|
|
|
| (189 | ) |
|
| (51 | ) |
|
| (240 | ) |
Other comprehensive loss, net of tax |
|
|
|
|
|
|
|
|
|
| (27 | ) |
|
| (27 | ) |
|
|
|
|
|
| (27 | ) |
Other |
|
| 4 |
|
|
|
|
|
|
|
|
|
|
| 4 |
|
|
|
|
|
|
| 4 |
|
September 30, 2019 |
| $ | 2,733 |
|
| $ | 4,821 |
|
| $ | (213 | ) |
| $ | 7,341 |
|
| $ | 1,400 |
|
| $ | 8,741 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2020 |
| $ | — |
|
| $ | 7,352 |
|
| $ | (271 | ) |
| $ | 7,081 |
|
| $ | 1,375 |
|
| $ | 8,456 |
|
Net income |
|
|
|
|
|
| 86 |
|
|
|
|
|
|
| 86 |
|
|
| 32 |
|
|
| 118 |
|
Dividends and distributions |
|
|
|
|
|
| (2,394 | ) |
|
|
|
|
|
| (2,394 | ) |
|
| (36 | ) |
|
| (2,430 | ) |
Equity contributions from Dominion Energy Questar |
|
|
|
|
|
| 299 |
|
|
|
|
|
|
| 299 |
|
|
|
|
|
|
| 299 |
|
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
| 107 |
|
|
| 107 |
|
|
|
|
|
|
| 107 |
|
September 30, 2020 |
| $ | — |
|
| $ | 5,343 |
|
| $ | (164 | ) |
| $ | 5,179 |
|
| $ | 1,371 |
|
| $ | 6,550 |
|
YEAR-TO-DATE
|
| Predecessor Equity |
|
| Membership Interests |
|
| AOCI |
|
| Total Members' Equity |
|
| Noncontrolling Interests |
|
| Total |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018 |
| $ | 1,804 |
|
| $ | 4,566 |
|
| $ | (169 | ) |
| $ | 6,201 |
|
| $ | 2,664 |
|
| $ | 8,865 |
|
Net income |
|
| 205 |
|
|
| 255 |
|
|
|
|
|
|
| 460 |
|
|
| 90 |
|
|
| 550 |
|
Acquisition of public interest in Dominion Energy Midstream |
|
| 1,181 |
|
|
|
|
|
|
|
|
|
|
| 1,181 |
|
|
| (1,221 | ) |
|
| (40 | ) |
Dividends and distributions |
|
| (457 | ) |
|
|
|
|
|
|
|
|
|
| (457 | ) |
|
| (132 | ) |
|
| (589 | ) |
Other comprehensive loss, net of tax |
|
|
|
|
|
|
|
|
|
| (44 | ) |
|
| (44 | ) |
|
| (1 | ) |
|
| (45 | ) |
September 30, 2019 |
| $ | 2,733 |
|
| $ | 4,821 |
|
| $ | (213 | ) |
| $ | 7,341 |
|
| $ | 1,400 |
|
| $ | 8,741 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019 |
| $ | — |
|
| $ | 9,031 |
|
| $ | (187 | ) |
| $ | 8,844 |
|
| $ | 1,385 |
|
| $ | 10,229 |
|
Net income |
|
|
|
|
|
| 57 |
|
|
|
|
|
|
| 57 |
|
|
| 97 |
|
|
| 154 |
|
Dividends and distributions |
|
|
|
|
|
| (4,044 | ) |
|
|
|
|
|
| (4,044 | ) |
|
| (111 | ) |
|
| (4,155 | ) |
Equity contributions from Dominion Energy Questar |
|
|
|
|
|
| 299 |
|
|
|
|
|
|
| 299 |
|
|
|
|
|
|
| 299 |
|
Other comprehensive income, net of tax |
|
|
|
|
|
|
|
|
|
| 23 |
|
|
| 23 |
|
|
|
|
|
|
| 23 |
|
September 30, 2020 |
| $ | — |
|
| $ | 5,343 |
|
| $ | (164 | ) |
| $ | 5,179 |
|
| $ | 1,371 |
|
| $ | 6,550 |
|
The accompanying notes are an integral part of DominionEastern Energy’s Consolidated Financial Statements.
9
EASTERN ENERGY INC.GAS HOLDINGS, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, |
| 2017 |
|
| 2016 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
Net income including noncontrolling interests |
| $ | 1,787 |
|
| $ | 1,721 |
|
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization (including nuclear fuel) |
|
| 1,649 |
|
|
| 1,325 |
|
Deferred income taxes and investment tax credits |
|
| 652 |
|
|
| 481 |
|
Proceeds from assignment of tower rental portfolio |
|
| 91 |
|
|
| — |
|
Gains on the sales of assets and equity method investment in Iroquois |
|
| (61 | ) |
|
| (50 | ) |
Contribution to pension plan |
|
| (75 | ) |
|
| — |
|
Other adjustments |
|
| (95 | ) |
|
| (78 | ) |
Changes in: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
| 247 |
|
|
| 19 |
|
Inventories |
|
| (34 | ) |
|
| (10 | ) |
Deferred fuel and purchased gas costs, net |
|
| (81 | ) |
|
| 84 |
|
Prepayments |
|
| 34 |
|
|
| 71 |
|
Accounts payable |
|
| (158 | ) |
|
| (89 | ) |
Accrued interest, payroll and taxes |
|
| 61 |
|
|
| 205 |
|
Margin deposit assets and liabilities |
|
| 51 |
|
|
| 1 |
|
Pension and other postretirement benefits |
|
| (132 | ) |
|
| (91 | ) |
Other operating assets and liabilities |
|
| (272 | ) |
|
| (203 | ) |
Net cash provided by operating activities |
|
| 3,664 |
|
|
| 3,386 |
|
Investing Activities |
|
|
|
|
|
|
|
|
Plant construction and other property additions (including nuclear fuel) |
|
| (4,122 | ) |
|
| (4,536 | ) |
Acquisition of Dominion Energy Questar, net of cash acquired |
|
| — |
|
|
| (4,372 | ) |
Acquisition of solar development projects |
|
| (343 | ) |
|
| (21 | ) |
Proceeds from sales of securities |
|
| 1,496 |
|
|
| 1,009 |
|
Purchases of securities |
|
| (1,555 | ) |
|
| (1,065 | ) |
Contributions to equity method affiliates |
|
| (343 | ) |
|
| (124 | ) |
Other |
|
| (6 | ) |
|
| 80 |
|
Net cash used in investing activities |
|
| (4,873 | ) |
|
| (9,029 | ) |
Financing Activities |
|
|
|
|
|
|
|
|
Repayment of short-term debt, net |
|
| (95 | ) |
|
| (713 | ) |
Issuance of short-term notes |
|
| — |
|
|
| 1,200 |
|
Repayment and repurchase of short-term notes |
|
| (250 | ) |
|
| (600 | ) |
Issuance of long-term debt |
|
| 3,480 |
|
|
| 5,730 |
|
Repayment and repurchase of long-term debt |
|
| (1,529 | ) |
|
| (1,169 | ) |
Proceeds from sale of interest in merchant solar projects |
|
| — |
|
|
| 117 |
|
Contributions from NRG and SunEdison to Four Brothers and Three Cedars |
|
| 9 |
|
|
| 178 |
|
Issuance of common stock |
|
| 1,233 |
|
|
| 2,079 |
|
Common dividend payments |
|
| (1,435 | ) |
|
| (1,287 | ) |
Other |
|
| (238 | ) |
|
| (248 | ) |
Net cash provided by financing activities |
|
| 1,175 |
|
|
| 5,287 |
|
Decrease in cash and cash equivalents |
|
| (34 | ) |
|
| (356 | ) |
Cash and cash equivalents at beginning of period |
|
| 261 |
|
|
| 607 |
|
Cash and cash equivalents at end of period |
| $ | 227 |
|
| $ | 251 |
|
Supplemental Cash Flow Information |
|
|
|
|
|
|
|
|
Significant noncash investing and financing activities(1): |
|
|
|
|
|
|
|
|
Accrued capital expenditures |
| $ | 355 |
|
| $ | 341 |
|
|
|
The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue(1) |
| $ | 2,154 |
|
| $ | 2,211 |
|
| $ | 5,732 |
|
| $ | 5,877 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric fuel and other energy-related purchases(1) |
|
| 549 |
|
|
| 516 |
|
|
| 1,414 |
|
|
| 1,527 |
|
Purchased (excess) electric capacity |
|
| 21 |
|
|
| (6 | ) |
|
| (8 | ) |
|
| 107 |
|
Other operations and maintenance: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliated suppliers |
|
| 76 |
|
|
| 73 |
|
|
| 229 |
|
|
| 238 |
|
Other |
|
| 297 |
|
|
| 370 |
|
|
| 897 |
|
|
| 1,041 |
|
Depreciation and amortization |
|
| 288 |
|
|
| 270 |
|
|
| 854 |
|
|
| 765 |
|
Other taxes |
| �� | 76 |
|
|
| 74 |
|
|
| 233 |
|
|
| 218 |
|
Total operating expenses |
|
| 1,307 |
|
|
| 1,297 |
|
|
| 3,619 |
|
|
| 3,896 |
|
Income from operations |
|
| 847 |
|
|
| 914 |
|
|
| 2,113 |
|
|
| 1,981 |
|
Other income |
|
| 13 |
|
|
| 13 |
|
|
| 57 |
|
|
| 47 |
|
Interest and related charges(1) |
|
| 128 |
|
|
| 118 |
|
|
| 373 |
|
|
| 345 |
|
Income before income tax expense |
|
| 732 |
|
|
| 809 |
|
|
| 1,797 |
|
|
| 1,683 |
|
Income tax expense |
|
| 273 |
|
|
| 306 |
|
|
| 664 |
|
|
| 637 |
|
Net Income |
| $ | 459 |
|
| $ | 503 |
|
| $ | 1,133 |
|
| $ | 1,046 |
|
|
|
Nine Months Ended September 30, |
| 2020 |
|
| 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
Net income including noncontrolling interests |
| $ | 154 |
|
| $ | 550 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
| 282 |
|
|
| 344 |
|
Deferred income taxes |
|
| (103 | ) |
|
| 40 |
|
Charge related to a voluntary retirement program |
|
| 0 |
|
|
| 40 |
|
Impairment of assets and other charges |
|
| 463 |
|
|
| 13 |
|
Gains on sales of assets |
|
| 0 |
|
|
| (7 | ) |
Other adjustments |
|
| 30 |
|
|
| 67 |
|
Changes in: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
| 41 |
|
|
| 107 |
|
Affiliated receivables and payables |
|
| 225 |
|
|
| (34 | ) |
Inventories |
|
| (6 | ) |
|
| (51 | ) |
Prepayments |
|
| (17 | ) |
|
| 31 |
|
Accounts payable |
|
| 12 |
|
|
| (110 | ) |
Accrued interest, payroll and taxes |
|
| 32 |
|
|
| (45 | ) |
Customer deposits |
|
| 4 |
|
|
| (82 | ) |
Pension and other postretirement benefits |
|
| (46 | ) |
|
| (105 | ) |
Other operating assets and liabilities |
|
| 188 |
|
|
| (34 | ) |
Net cash provided by operating activities |
|
| 1,259 |
|
|
| 724 |
|
Investing Activities |
|
|
|
|
|
|
|
|
Plant construction and other property additions |
|
| (258 | ) |
|
| (537 | ) |
Repayment of loan by Dominion Energy to Cove Point |
|
| 0 |
|
|
| 2,986 |
|
Repayment of loans by affiliates |
|
| 3,422 |
|
|
| 0 |
|
Advances to affiliates, net of repayments |
|
| (225 | ) |
|
| 0 |
|
Other |
|
| (9 | ) |
|
| (19 | ) |
Net cash provided by investing activities |
|
| 2,930 |
|
|
| 2,430 |
|
Financing Activities |
|
|
|
|
|
|
|
|
Issuance (repayment) of short-term debt, net |
|
| (62 | ) |
|
| 270 |
|
Issuance (repayment) of affiliated current borrowings, net |
|
| (253 | ) |
|
| 32 |
|
Repayment of long-term debt |
|
| 0 |
|
|
| (3,300 | ) |
Issuance of affiliated long-term debt |
|
| 0 |
|
|
| 395 |
|
Repayment of credit facility borrowings |
|
| 0 |
|
|
| (73 | ) |
Equity contributions from Dominion Energy Questar |
|
| 299 |
|
|
| 0 |
|
Dividends and distributions |
|
| (4,155 | ) |
|
| (589 | ) |
Other |
|
| (1 | ) |
|
| (1 | ) |
Net cash used in financing activities |
|
| (4,172 | ) |
|
| (3,266 | ) |
Increase (decrease) in cash, restricted cash and equivalents |
|
| 17 |
|
|
| (112 | ) |
Cash, restricted cash and equivalents at beginning of period |
|
| 39 |
|
|
| 198 |
|
Cash, restricted cash and equivalents at end of period |
| $ | 56 |
|
| $ | 86 |
|
Supplemental Cash Flow Information |
|
|
|
|
|
|
|
|
Significant noncash investing and financing activities: |
|
|
|
|
|
|
|
|
Accrued capital expenditures |
| $ | 44 |
|
| $ | 19 |
|
Financing leases |
|
| 1 |
|
|
| 10 |
|
The accompanying notes are an integral part of Virginia Power’sEastern Energy’s Consolidated Financial Statements.
VIRGINIA ELECTRIC AND POWER COMPANY10
(Unaudited)
|
| September 30, 2017 |
|
| December 31, 2016(1) |
| ||
(millions) |
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 16 |
|
| $ | 11 |
|
Customer receivables (less allowance for doubtful accounts of $9 and $10) |
|
| 920 |
|
|
| 892 |
|
Other receivables (less allowance for doubtful accounts of $1 at both dates) |
|
| 36 |
|
|
| 99 |
|
Affiliated receivables |
|
| 1 |
|
|
| 112 |
|
Inventories (average cost method) |
|
| 853 |
|
|
| 853 |
|
Other(2) |
|
| 309 |
|
|
| 281 |
|
Total current assets |
|
| 2,135 |
|
|
| 2,248 |
|
Investments |
|
|
|
|
|
|
|
|
Nuclear decommissioning trust funds |
|
| 2,292 |
|
|
| 2,106 |
|
Other |
|
| 3 |
|
|
| 3 |
|
Total investments |
|
| 2,295 |
|
|
| 2,109 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
| 41,813 |
|
|
| 40,030 |
|
Accumulated depreciation and amortization |
|
| (13,144 | ) |
|
| (12,436 | ) |
Total property, plant and equipment, net |
|
| 28,669 |
|
|
| 27,594 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Regulatory assets |
|
| 838 |
|
|
| 770 |
|
Pension and other postretirement benefit assets(2) |
|
| 182 |
|
|
| 130 |
|
Other(2) |
|
| 462 |
|
|
| 457 |
|
Total deferred charges and other assets |
|
| 1,482 |
|
|
| 1,357 |
|
Total assets |
| $ | 34,581 |
|
| $ | 33,308 |
|
|
|
|
|
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED BALANCE SHEETS—(Continued)
(Unaudited)
|
| September 30, 2017 |
|
| December 31, 2016(1) |
| ||
(millions) |
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDER’S EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Securities due within one year |
| $ | 851 |
|
| $ | 678 |
|
Short-term debt |
|
| 320 |
|
|
| 65 |
|
Accounts payable |
|
| 337 |
|
|
| 444 |
|
Payables to affiliates |
|
| 167 |
|
|
| 109 |
|
Affiliated current borrowings |
|
| 36 |
|
|
| 262 |
|
Accrued interest, payroll and taxes |
|
| 307 |
|
|
| 239 |
|
Other(2) |
|
| 536 |
|
|
| 725 |
|
Total current liabilities |
|
| 2,554 |
|
|
| 2,522 |
|
Long-Term Debt |
|
| 10,495 |
|
|
| 9,852 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes and investment tax credits |
|
| 5,357 |
|
|
| 5,103 |
|
Asset retirement obligations |
|
| 1,300 |
|
|
| 1,262 |
|
Regulatory liabilities |
|
| 2,202 |
|
|
| 1,962 |
|
Other(2) |
|
| 863 |
|
|
| 742 |
|
Total deferred credits and other liabilities |
|
| 9,722 |
|
|
| 9,069 |
|
Total liabilities |
|
| 22,771 |
|
|
| 21,443 |
|
Commitments and Contingencies (see Note 15) |
|
|
|
|
|
|
|
|
Common Shareholder’s Equity |
|
|
|
|
|
|
|
|
Common stock – no par(3) |
|
| 5,738 |
|
|
| 5,738 |
|
Other paid-in capital |
|
| 1,113 |
|
|
| 1,113 |
|
Retained earnings |
|
| 4,904 |
|
|
| 4,968 |
|
Accumulated other comprehensive income |
|
| 55 |
|
|
| 46 |
|
Total common shareholder’s equity |
|
| 11,810 |
|
|
| 11,865 |
|
Total liabilities and shareholder’s equity |
| $ | 34,581 |
|
| $ | 33,308 |
|
|
|
|
|
|
|
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
VIRGINIA ELECTRIC AND POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, |
| 2017 |
|
| 2016 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
Net income |
| $ | 1,133 |
|
| $ | 1,046 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization (including nuclear fuel) |
|
| 999 |
|
|
| 903 |
|
Deferred income taxes and investment tax credits |
|
| 262 |
|
|
| 369 |
|
Proceeds from assignment of tower rental portfolio |
|
| 91 |
|
|
| — |
|
Other adjustments |
|
| (28 | ) |
|
| (15 | ) |
Changes in: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
| 32 |
|
|
| (99 | ) |
Affiliated receivables and payables |
|
| 159 |
|
|
| 306 |
|
Inventories |
|
| 1 |
|
|
| 37 |
|
Prepayments |
|
| (3 | ) |
|
| 15 |
|
Deferred fuel expenses, net |
|
| (48 | ) |
|
| 79 |
|
Accounts payable |
|
| (33 | ) |
|
| 4 |
|
Accrued interest, payroll and taxes |
|
| 67 |
|
|
| 131 |
|
Other operating assets and liabilities |
|
| (162 | ) |
|
| 8 |
|
Net cash provided by operating activities |
|
| 2,470 |
|
|
| 2,784 |
|
Investing Activities |
|
|
|
|
|
|
|
|
Plant construction and other property additions |
|
| (1,917 | ) |
|
| (1,835 | ) |
Purchases of nuclear fuel |
|
| (133 | ) |
|
| (106 | ) |
Proceeds from sales of securities |
|
| 654 |
|
|
| 478 |
|
Purchases of securities |
|
| (681 | ) |
|
| (513 | ) |
Other |
|
| (29 | ) |
|
| (11 | ) |
Net cash used in investing activities |
|
| (2,106 | ) |
|
| (1,987 | ) |
Financing Activities |
|
|
|
|
|
|
|
|
Issuance (repayment) of short-term debt, net |
|
| 255 |
|
|
| (691 | ) |
Repayment of affiliated current borrowings, net |
|
| (226 | ) |
|
| (376 | ) |
Issuance of long-term debt |
|
| 1,500 |
|
|
| 750 |
|
Repayment of long-term debt |
|
| (679 | ) |
|
| (476 | ) |
Common dividend payments to parent |
|
| (1,199 | ) |
|
| — |
|
Other |
|
| (10 | ) |
|
| (4 | ) |
Net cash used in financing activities |
|
| (359 | ) |
|
| (797 | ) |
Increase in cash and cash equivalents |
|
| 5 |
|
|
| — |
|
Cash and cash equivalents at beginning of period |
|
| 11 |
|
|
| 18 |
|
Cash and cash equivalents at end of period |
| $ | 16 |
|
| $ | 18 |
|
Supplemental Cash Flow Information |
|
|
|
|
|
|
|
|
Significant noncash investing activities: |
|
|
|
|
|
|
|
|
Accrued capital expenditures |
| $ | 158 |
|
| $ | 209 |
|
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
DOMINION ENERGY GAS HOLDINGS, LLC
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue(1) |
| $ | 401 |
|
| $ | 382 |
|
| $ | 1,313 |
|
| $ | 1,181 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased gas(1) |
|
| 19 |
|
|
| 21 |
|
|
| 100 |
|
|
| 71 |
|
Other energy-related purchases |
|
| 4 |
|
|
| 4 |
|
|
| 11 |
|
|
| 8 |
|
Other operations and maintenance: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliated suppliers |
|
| 20 |
|
|
| 20 |
|
|
| 65 |
|
|
| 63 |
|
Other |
|
| 53 |
|
|
| 113 |
|
|
| 312 |
|
|
| 268 |
|
Depreciation and amortization |
|
| 57 |
|
|
| 55 |
|
|
| 167 |
|
|
| 150 |
|
Other taxes |
|
| 42 |
|
|
| 36 |
|
|
| 139 |
|
|
| 127 |
|
Total operating expenses |
|
| 195 |
|
|
| 249 |
|
|
| 794 |
|
|
| 687 |
|
Income from operations |
|
| 206 |
|
|
| 133 |
|
|
| 519 |
|
|
| 494 |
|
Earnings from equity method investee |
|
| 4 |
|
|
| 5 |
|
|
| 15 |
|
|
| 14 |
|
Other income |
|
| 6 |
|
|
| 2 |
|
|
| 16 |
|
|
| 8 |
|
Interest and related charges(1) |
|
| 25 |
|
|
| 23 |
|
|
| 72 |
|
|
| 68 |
|
Income from operations before income taxes |
|
| 191 |
|
|
| 117 |
|
|
| 478 |
|
|
| 448 |
|
Income tax expense |
|
| 74 |
|
|
| 34 |
|
|
| 176 |
|
|
| 162 |
|
Net Income |
| $ | 117 |
|
| $ | 83 |
|
| $ | 302 |
|
| $ | 286 |
|
|
|
The accompanying notes are an integral part of Dominion Energy Gas' Consolidated Financial Statements.
DOMINION ENERGY GAS HOLDINGS, LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
| $ | 117 |
|
| $ | 83 |
|
| $ | 302 |
|
| $ | 286 |
|
Other comprehensive income (loss), net of taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred gains (losses) on derivatives-hedging activities(1) |
|
| 1 |
|
|
| 9 |
|
|
| 3 |
|
|
| (6 | ) |
Amounts reclassified to net income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative gains-hedging activities(2) |
|
| (4 | ) |
|
| (1 | ) |
|
| (5 | ) |
|
| (3 | ) |
Net pension and other postretirement benefit costs(3) |
|
| 1 |
|
|
| 1 |
|
|
| 3 |
|
|
| 2 |
|
Total other comprehensive income (loss) |
|
| (2 | ) |
|
| 9 |
|
|
| 1 |
|
|
| (7 | ) |
Comprehensive income |
| $ | 115 |
|
| $ | 92 |
|
| $ | 303 |
|
| $ | 279 |
|
|
|
|
|
|
|
The accompanying notes are an integral part of Dominion Energy Gas' Consolidated Financial Statements.
DOMINION ENERGY GAS HOLDINGS, LLC
CONSOLIDATED BALANCE SHEETS
(Unaudited)
|
| September 30, 2017 |
|
| December 31, 2016(1) |
| ||
(millions) |
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 13 |
|
| $ | 23 |
|
Restricted cash |
|
| 29 |
|
|
| 20 |
|
Customer receivables (less allowance for doubtful accounts of $1 at both dates) |
|
| 190 |
|
|
| 281 |
|
Other receivables (less allowance for doubtful accounts of $1 at both dates)(2) |
|
| 72 |
|
|
| 13 |
|
Affiliated receivables |
|
| 17 |
|
|
| 17 |
|
Inventories |
|
| 90 |
|
|
| 70 |
|
Other(2) |
|
| 110 |
|
|
| 158 |
|
Total current assets |
|
| 521 |
|
|
| 582 |
|
Investments |
|
| 97 |
|
|
| 99 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
| 10,971 |
|
|
| 10,475 |
|
Accumulated depreciation and amortization |
|
| (2,978 | ) |
|
| (2,851 | ) |
Total property, plant and equipment, net |
|
| 7,993 |
|
|
| 7,624 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Pension and other postretirement benefit assets(2) |
|
| 1,714 |
|
|
| 1,557 |
|
Other(2) |
|
| 1,303 |
|
|
| 1,280 |
|
Total deferred charges and other assets |
|
| 3,017 |
|
|
| 2,837 |
|
Total assets |
| $ | 11,628 |
|
| $ | 11,142 |
|
|
|
|
|
The accompanying notes are an integral part of Dominion Energy Gas' Consolidated Financial Statements.
DOMINION ENERGY GAS HOLDINGS, LLC
CONSOLIDATED BALANCE SHEETS—(Continued)
(Unaudited)
|
| September 30, 2017 |
|
| December 31, 2016(1) |
| ||
(millions) |
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Short-term debt |
| $ | 620 |
|
| $ | 460 |
|
Accounts payable |
|
| 161 |
|
|
| 221 |
|
Payables to affiliates |
|
| 18 |
|
|
| 29 |
|
Affiliated current borrowings |
|
| 34 |
|
|
| 118 |
|
Accrued interest, payroll and taxes |
|
| 197 |
|
|
| 225 |
|
Other(2) |
|
| 157 |
|
|
| 162 |
|
Total current liabilities |
|
| 1,187 |
|
|
| 1,215 |
|
Long-Term Debt |
|
| 3,564 |
|
|
| 3,528 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Deferred income taxes and investment tax credits |
|
| 2,622 |
|
|
| 2,438 |
|
Other(2) |
|
| 429 |
|
|
| 425 |
|
Total deferred credits and other liabilities |
|
| 3,051 |
|
|
| 2,863 |
|
Total liabilities |
|
| 7,802 |
|
|
| 7,606 |
|
Commitments and Contingencies (see Note 15) |
|
|
|
|
|
|
|
|
Equity |
|
|
|
|
|
|
|
|
Membership interests |
|
| 3,948 |
|
|
| 3,659 |
|
Accumulated other comprehensive loss |
|
| (122 | ) |
|
| (123 | ) |
Total equity |
|
| 3,826 |
|
|
| 3,536 |
|
Total liabilities and equity |
| $ | 11,628 |
|
| $ | 11,142 |
|
|
|
|
|
The accompanying notes are an integral part of Dominion Energy Gas' Consolidated Financial Statements.
DOMINION ENERGY GAS HOLDINGS, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, |
| 2017 |
|
| 2016 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
Net income |
| $ | 302 |
|
| $ | 286 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Gains on the sales of assets and equity method investment in Iroquois |
|
| (61 | ) |
|
| (50 | ) |
Depreciation and amortization |
|
| 167 |
|
|
| 150 |
|
Deferred income taxes and investment tax credits |
|
| 176 |
|
|
| 204 |
|
Other adjustments |
|
| (9 | ) |
|
| 3 |
|
Changes in: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
| 88 |
|
|
| 56 |
|
Affiliated receivables and payables |
|
| (11 | ) |
|
| 91 |
|
Inventories |
|
| (20 | ) |
|
| (17 | ) |
Deferred purchased gas costs, net |
|
| 11 |
|
|
| 7 |
|
Prepayments |
|
| 39 |
|
|
| 15 |
|
Accounts payable |
|
| (68 | ) |
|
| (76 | ) |
Accrued interest, payroll and taxes |
|
| (28 | ) |
|
| (7 | ) |
Pension and other postretirement benefits |
|
| (98 | ) |
|
| (97 | ) |
Other operating assets and liabilities |
|
| (13 | ) |
|
| (62 | ) |
Net cash provided by operating activities |
|
| 475 |
|
|
| 503 |
|
Investing Activities |
|
|
|
|
|
|
|
|
Plant construction and other property additions |
|
| (535 | ) |
|
| (610 | ) |
Proceeds from sale of equity method investment in Iroquois |
|
| — |
|
|
| 7 |
|
Proceeds from assignments of shale development rights |
|
| 5 |
|
|
| 10 |
|
Other |
|
| (16 | ) |
|
| (10 | ) |
Net cash used in investing activities |
|
| (546 | ) |
|
| (603 | ) |
Financing Activities |
|
|
|
|
|
|
|
|
Issuance (repayment) of short-term debt, net |
|
| 160 |
|
|
| (331 | ) |
Issuance of long-term debt |
|
| — |
|
|
| 680 |
|
Repayment of affiliated current borrowings, net |
|
| (84 | ) |
|
| (95 | ) |
Distribution payments to parent |
|
| (15 | ) |
|
| (150 | ) |
Other |
|
| — |
|
|
| (9 | ) |
Net cash provided by financing activities |
|
| 61 |
|
|
| 95 |
|
Decrease in cash and cash equivalents |
|
| (10 | ) |
|
| (5 | ) |
Cash and cash equivalents at beginning of period |
|
| 23 |
|
|
| 13 |
|
Cash and cash equivalents at end of period |
| $ | 13 |
|
| $ | 8 |
|
Supplemental Cash Flow Information |
|
|
|
|
|
|
|
|
Significant noncash investing activities: |
|
|
|
|
|
|
|
|
Accrued capital expenditures |
| $ | 54 |
|
| $ | 42 |
|
The accompanying notes are an integral part of Dominion Energy Gas' Consolidated Financial Statements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1. Nature of Operations
DominionEastern Energy headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas. Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Dominion Energy Gas is a holding company that conducts business activities through a regulatedFERC-regulated interstate natural gas transmission pipeline and underground storage systemsystems in the Northeast, mid-Atlanticeastern region of the U.S., as well as the Cove Point LNG Facility and Midwest states, regulatedowns a 50% noncontrolling interest in Iroquois. Through October 31, 2020, Eastern Energy also conducted business activities through FERC-regulated interstate natural gas transportationtransmission pipeline and distributionunderground storage systems in the Rocky Mountain Region of the U.S. and owned a 50% noncontrolling interest in White River Hub. Beginning in September 2020, Eastern Energy manages its daily operations in Ohio,through one segment, which includes its gas transmission and gas gathering and processing activities primarily in West Virginia, Ohio and Pennsylvania.storage operations. See Note 3 for a descriptioninformation on the acquisition of operations acquired inEastern Energy by BHE and the Dominion Energy Questar Combination.Gas Restructuring.
Note 2. Significant Accounting Policies
As permitted by the rules and regulations of the SEC, the Companies'Eastern Energy’s 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'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016.2019.
In the Companies'Eastern Energy’s opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly theirits financial position as ofat September 30, 2017, their2020, its results of operations and changes in equity for the three and nine months ended September 30, 20172020 and 2016, their2019 and its cash flows for the nine months ended September 30, 20172020 and 2016 and Dominion Energy's changes in equity for the nine months ended September 30, 2017 and 2016.2019. Such adjustments are normal and recurring in nature unless otherwise noted.
The Companies makeEastern Energy makes certain estimates and assumptions in preparing theirits 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'Eastern Energy’s accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, theirits accounts, those of theirits respective majority-owned subsidiaries and non-wholly-owned entities in which they haveit has a controlling financial interest. For certain partnership structures, income is allocated based onBrookfield’s 25% interest in Cove Point (effective December 2019) and the liquidation value of the underlying contractual arrangements. At September 30, 2017, Dominion Energy owns the general partner, 50.9% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream. The public’s ownership interest in Dominion Energy Midstream is(through January 2019) are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Also, at September 30, 2017, Dominion Energy 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 Energy merchant solar projects, is reflected as noncontrolling interest in DominionEastern Energy’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' 2016Eastern Energy’s 2019 Consolidated Financial Statements and Notes have been reclassified to conform to the 20172020 presentation for comparative purposes. Thepurposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.
Amounts disclosed for Dominion Energy are inclusive of Virginia Power and/or Dominion Energy Gas, where applicable. With the exception of the items described below, thereThere have been no significant changes from Note 2 to the Consolidated Financial Statements in the Companies'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016.2019, with the exception of the items described below.
Property, Plant11
Cash, Restricted Cash and EquipmentEquivalents
InThe following table provides a reconciliation of the first quartertotal cash, restricted cash and equivalents reported within Eastern Energy’s Consolidated Balance Sheets to the corresponding amounts reported within the Consolidated Statements 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 $32 million ($20 million after-tax)Cash Flows for the nine months ended September 30, 20172020 and is expected2019:
|
| Cash, Restricted Cash and Equivalents at End of Period |
|
| Cash, Restricted Cash and Equivalents at Beginning of Period |
| ||||||||||
|
| September 30, 2020 |
|
| September 30, 2019 |
|
| December 31, 2019 |
|
| December 31, 2018 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents(1) |
| $ | 40 |
|
| $ | 74 |
|
| $ | 27 |
|
| $ | 108 |
|
Restricted cash and equivalents(2) |
|
| 16 |
|
|
| 12 |
|
|
| 12 |
|
|
| 90 |
|
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows |
| $ | 56 |
|
| $ | 86 |
|
| $ | 39 |
|
| $ | 198 |
|
(1) | At September 30, 2019 and December 31, 2018,$10 million and $9 million of cash and cash equivalents were included in current assets of discontinued operations, respectively. |
(2) Restricted cash and equivalent balances are presented within other current assets in the Consolidated Balance Sheets.
Property, Plant and Equipment
In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header Project. As a result of the cancellation of the Atlantic Coast Pipeline Project, in the second quarter of 2020 Eastern Energy recorded a charge of $482 million ($359 million after-tax) in impairment of assets and other charges (benefits) in its Consolidated Statements of Income associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million ARO. In the third quarter of 2020, Eastern Energy recorded an additional charge of $10 million ($7 million after-tax) associated with the probable abandonment of a significant portion of the project and a $29 million ($20 million after-tax) benefit from a revision to increase annual depreciation bythe previously established ARO, both of which were recorded in impairment of assets and other charges (benefits) in Eastern Energy’s Consolidated Statements of Income. As DETI evaluates its future use, approximately $40 million ($25 million after-tax). Additionally, Dominionremains within property, plant and equipment for a potential modified project.
Goodwill
Eastern Energy revisedhas evaluated goodwill annually as of April 1 and whenever an event occurs or circumstances change in the depreciable lives for its merchant generation assets, excluding Millstone, which resulted in a decrease in depreciation expense of $19 million ($12 million after-tax) forinterim that would more-likely-than-not reduce the nine months ended September 30, 2017 and is expected to decrease annual depreciation by approximately $26 million ($16 million after-tax).
In January 2017, the Financial Accounting Standards Board issued revised accounting guidance to clarify the definitionfair value of a business. The revised guidance affects the evaluation of whether a transaction should be accounted for as an acquisition or disposition of an asset or a business, which may impactreporting unit below its carrying amount. Eastern Energy evaluated goodwill on April 1, 2020 and related financial statement disclosures. The Companies have adopted this guidanceintends to evaluate goodwill annually on a prospective basisOctober 31, effective October 1, 2017. The adoption of the pronouncement will result in additional transactions being accounted for as asset acquisitions or dispositions.31, 2020, to align with BHE’s policy.
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, with a retrospective adoption for income statement presentation and a prospective adoption 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 any of our state commissions do not adopt the change in capitalization requirements for regulatory reporting.
Note 3. Acquisitions and Dispositions
Acquisition of Eastern Energy by BHE
In July 2020, Dominion Energy
Acquisition entered into an agreement to sell substantially all of its gas transmission and storage operations, including Eastern Energy, to BHE. Approval of the transaction under the Hart-Scott Rodino Act was not obtained within 75 days and Dominion Energy and BHE mutually agreed to a dual-phase closing consisting of two separate disposal groups identified as the GT&S Transaction and the Q-Pipe Transaction. A separate agreement was entered into between Dominion Energy and BHE in October 2020 for the Q-Pipe Transaction, which is currently anticipated to close in early 2021, contingent on clearance or approval under the Hart-Scott-Rodino Act, and other customary closing and regulatory conditions. In November 2020, Eastern Energy finalized a restructuring whereby Eastern Energy disposed of Dominion Energy Questar
In September 2016, Dominion Energy completed the Dominion Energy Questar Combination Pipeline and Dominion Energy Questar became a wholly-owned subsidiary of50% noncontrolling interest in Cove Point to Dominion Energy. DominionThis restructuring was accounted for by Eastern Energy Questar,as a Rockies-based integrated natural gas company, included Questar Gas, Wexpro Companyreorganization of entities under common control and the disposition was reflected as an equity transaction. The disposition was not reported as a discontinued operation as the disposal did not represent a strategic shift in the way management had intended to run the business.
12
In November 2020, the GT&S Transaction was completed and Eastern Energy, with the exception of Dominion Energy 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.as discussed above, became an indirect wholly-owned subsidiary of BHE. Dominion Energy Questar Pipeline provides FERC-regulated interstate natural gas transportationretained a 50% noncontrolling interest in Cove Point as well as the assets and storage services in Utah, Wyomingobligations of the pension and western Colorado. The Dominion Energy Questar Combination provides Dominion Energy with pipeline infrastructure that provides a principal source of gas supply to Western states. Dominion Energy Questar’s regulated businesses also provide further balance between Dominion Energy’s electric and gas operations.
In accordanceother postretirement employee benefit plans associated with the terms of the Dominion Energy Questar Combination, at closing, each share of issuedoperations sold and outstanding Dominion Energy Questar common stock was converted into the rightrelating to receive $25.00 per share in cash. The total consideration was $4.4 billion based on 175.5 million shares of Dominion Energy Questar outstanding atservices provided before closing.
Dominion Energy financed the Dominion Energy 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 175 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, 20168 for more information on the DominionGT&S Transaction.
Based on the recorded balances at September 30, 2020, Eastern Energy Questar Combinationexpects to record a distribution of net assets of approximately $700 million, including purchase price allocation, regulatory matters andgoodwill of approximately $185 million, for the contributiondistribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream. During the third quarterand a distribution of 2017, certain modifications were madenet assets of approximately $900 million related to the valuation amountspension and other postretirement employee benefit plans retained by Dominion Energy. Additionally, Eastern Energy expects to record an approximately $2.7 billion increase in noncontrolling interests for regulatory liabilities, current liabilities and deferred income taxes, resulting in a $6 million net increase to goodwill recorded in Dominion Energy’s Consolidated Balance Sheets. The modifications relate primarily to the finalization of Dominion Energy Questar’s 2016 tax return for the period January 1, 2016 through the Dominion Energy Questar Combination, as well as certain regulatory adjustments.
Results of Operations and Pro Forma Information
The impact of the Dominion Energy Questar Combination on Dominion Energy’s operating revenue and net income attributable to Dominion Energyretained 50% noncontrolling interest in Cove Point. These equity transactions will be recorded in the Consolidated Statements of Income for both the three and nine months ended September 30, 2016, was an increase of $23 million and $5 million, respectively.
Dominion Energy incurred transaction and transition costs, of which $14 million and $34 million was recorded in other operations and maintenance expense for the three and nine months ended September 30, 2017, respectively, in Dominion Energy’s Consolidated Statements of Income. Dominion Energy incurred transaction and transition costs, of which $40 million and $47 million was recorded in other operations and maintenance expense for the three and nine months ended September 30, 2016, respectively, and $13 million was recorded in interest and related charges for both the three and nine months ended September 30, 2016, in Dominion Energy’s Consolidated Statements of Income. These costs consist of the amortization of financing costs, the charitable contribution commitment described in Note 3 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2016, employee-related expenses, professional fees and other miscellaneous costs.
The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the Dominion Energy 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.
|
| Three Months Ended September 30, 2016(1) |
|
| Nine Months Ended September 30, 2016(1) |
| ||
(millions, except EPS) |
|
|
|
|
|
|
|
|
Operating Revenue |
| $ | 3,261 |
|
| $ | 9,410 |
|
Net income attributable to Dominion Energy |
|
| 732 |
|
|
| 1,835 |
|
Earnings Per Common Share – Basic |
| $ | 1.17 |
|
| $ | 2.99 |
|
Earnings Per Common Share – Diluted |
| $ | 1.17 |
|
| $ | 2.99 |
|
|
|
Wholly-Owned Merchant Solar Projects
In January 2017, Dominion Energy entered into an agreement to acquire 100% of the equity interests of a solar project in North Carolina from Cypress Creek Renewables, LLC for cash consideration. In May 2017, Dominion Energy closed on the acquisition for $154 million, all of which was allocated to property, plant and equipment. The facility commenced commercial operations in June 2017, at a cost of $160 million, including the initial acquisition cost, and generates approximately 79 MW.
In September 2016, Dominion Energy entered into an agreement to acquire 100% of the equity interests of a solar project in Virginia from Community Energy Solar, LLC for cash consideration. In February 2017, Dominion Energy 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 Energy entered into an agreement to acquire 100% of the equity interests of two solar projects in California from Solar Frontier Americas Holding LLC for cash consideration. In March 2017, Dominion Energy closed on the acquisition of one of the solar projects for $77 million, all of which was allocated to property, plant and equipment. The facility commenced commercial operations in June 2017, at a cost of $78 million, including the initial acquisition cost, and generates approximately 30 MW. In April 2017, Dominion Energy discontinued efforts on the acquisition of the additional 20 MW solar project from Solar Frontier Americas Holding LLC.
In May 2017, Dominion Energy entered into an agreement to acquire 100% of the equity interests of two solar projects in Virginia from Hecate Energy Virginia C&C LLC for cash consideration of $56 million. Dominion Energy completed the acquisition of one of the projects in June 2017 for $16 million and the facility commenced commercial operations in August 2017. The second acquisition was completed in September 2017 for $40 million with commencement of commercial operations expected to occur by the end of 2017. The projects are expected to cost approximately $60 million once constructed, including the initial acquisition costs, and to generate approximately 30 MW combined.
In June 2017, Dominion Energy entered into an agreement to acquire 100% of the equity interests of four solar projects in North Carolina from Strata Solar Development, LLC and Moorings Farm 2 Holdco, LLC for cash consideration of $40 million. Dominion Energy completed the acquisition of two of the projects in June 2017 for $20 million. The final two acquisitions were completed in October 2017 for $20 million. Commencement of commercial operations of all the projects is expected to occur by the end of 2017. The projects are expected to cost approximately $45 million once constructed, including the initial acquisition costs, and to generate approximately 19 MW combined.
Long-term power purchase, interconnection and operation and maintenance agreements have been executed for all of the projects described above. These projects are included in Power Generation. Dominion Energy has claimed or will claim federal investment tax credits on these solar projects.
Sale of Interest in Merchant Solar Projects
In September 2015, Dominion Energy 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 Energy’s remaining 67% ownership in the projects upon the occurrence of certain events, none of which had occurred at September 30, 2017 nor are expected to occur in the remainder of 2017.
Sale of Certain Retail Energy Marketing Assets
In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy marketing operations for total consideration of $143 million, subject to customary approvals and certain adjustments. Pursuant to the agreement, Dominion Energy will enter into a commission agreement with the buyer upon the first closing under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a ten-year term. Dominion Energy is expected to recognize a benefit in other operations and maintenance expense upon each phase of closing, approximately $78 million ($48 million after-tax)Balance Sheets in the fourth quarter of 2017 and approximately $65 million ($40 million after-tax) in 2018.2020.
Virginia Power
Acquisition of Solar Projects
In September 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The first acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2018, and cost approximately $140 million once constructed, including the initial acquisition cost. The second acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2019, and cost approximately $140 million once constructed, including the initial acquisition cost. The projects are expected to generate approximately 155 MW combined. Virginia Power anticipates claiming federal investment tax credits on these solar projects.
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 $2 million and $10 million in other income for the three and nine months ended September 30, 2017, respectively, with the remaining $36 million to be recognized ratably through 2023.
Dominion Energy Gas Restructuring
Assignment of Shale Development Rights
In December 2013,The Dominion Energy Gas closed an agreement withRestructuring was considered to be a natural gas producerreorganization of entities under common control. As a result, Eastern Energy’s basis in DCP and DMLPHCII, which included the general partner of Dominion Energy Midstream, a controlling 75% interest in Cove Point, DECG, Dominion Energy Questar Pipeline, a 50% noncontrolling interest in White River Hub and a 25.93% noncontrolling interest in Iroquois, is equal to convey over time approximately 79,000 acresDominion Energy’s cost basis in the assets and liabilities of Marcellus Shale development rights underneath onesuch entities since the applicable inception dates of its natural gas storage fields. The agreement provided for payments tocommon control. In November 2019, following completion of the Dominion Energy Gas subjectRestructuring, DCP and DMLPHCII are wholly-owned subsidiaries of Eastern Energy and therefore are consolidated by Eastern Energy. The accompanying Consolidated Financial Statements and Notes of Eastern Energy have been retrospectively adjusted to customary adjustments,include the historical results and financial position of up to approximately $200 million over a period of nine years,DCP and an overriding royaltyDMLPHCII. The 25% interest in gas produced fromCove Point retained by Dominion Energy, and subsequently sold to Brookfield in December 2019, and the acreage. In March 2015,non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest.
The Dominion Energy Gas Restructuring includes the disposition of East Ohio and DGP by Eastern Energy in November 2019. This restructuring represented a strategic shift in the naturaloperations of Eastern Energy as Eastern Energy’s operations consist of LNG import/export and storage and regulated gas producer closed on an amendmenttransmission and storage operations. As a result, the accompanying Consolidated Financial Statements and Notes of Eastern Energy have been retrospectively adjusted to include the agreement, which includedhistorical results and financial position of East Ohio and DGP as discontinued operations until November 2019. As the immediate conveyance of approximately 9,000 acres of Marcellus Shale development rights and a two year extension of the term of the original agreement. In April 2016, Dominion Energy Gas andRestructuring is considered to be a reorganization of entities under common control, Eastern Energy has reflected the natural gas producer closed ondisposition as an amendment toequity transaction. The following table represents selected information regarding the agreement,results of operations of East Ohio, which included the immediate conveyance of a 32% partial interestare reported as discontinued operations in the remaining approximately 70,000 acres. This conveyance resulted in the recognition of $35 million ($21 million after-tax) of previously deferred revenue to other operations and maintenance expense in Dominion Energy Gas’Eastern Energy’s Consolidated Statements of Income. In August 2017, Dominion Energy GasIncome:
|
| Three Months Ended September 30, 2019 |
|
| Nine Months Ended September 30, 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 155 |
|
| $ | 538 |
|
Depreciation and amortization |
|
| 23 |
|
|
| 66 |
|
Other operating expenses |
|
| 90 |
|
|
| 364 |
|
Other income |
|
| 20 |
|
|
| 55 |
|
Interest and related charges |
|
| 11 |
|
|
| 30 |
|
Income tax expense |
|
| 8 |
|
|
| 25 |
|
Net income from discontinued operations |
| $ | 43 |
|
| $ | 108 |
|
Capital expenditures and the natural gas producer signed an amendmentsignificant noncash items relating to the agreement, whichEast Ohio included the finalizationfollowing:
|
| Nine Months Ended September 30, 2019 |
| |
(millions) |
|
|
|
|
Capital expenditures |
| $ | 267 |
|
Significant noncash items |
|
|
|
|
Charge related to a voluntary retirement program |
|
| 20 |
|
Accrued capital expenditures |
|
| 10 |
|
13
The following table represents selected information regarding the results of contractual matters on previous conveyances, the conveyanceoperations of Dominion Energy Gas’ remaining 68% interestDGP, which are reported as discontinued operations in approximately 70,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. Dominion Energy Gas will receive total consideration of $130 million, with $65 million to be received by the end of the fourth quarter 2017 and $65 million to be received by the end of the third quarter of 2018 in connection with the final conveyance. As
a result of this amendment in the third quarter of 2017, Dominion Energy Gas recognized a $56 million ($33 million after-tax) gain included in other operations and maintenance expense in Dominion Energy Gas’Eastern Energy’s Consolidated Statements of Income associated with the finalization of the contractual matters on previous conveyances. Additionally, Dominion Energy Gas is expected to recognize an approximately $9 million ($5 million after-tax) gain in the fourth quarter of 2017 associated with the elimination of its overriding royalty interest and an approximately $65 million ($40 million after-tax) gain associated with the final conveyance of acreage.
In November 2014, Dominion Energy 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 Energy 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 Energy Gas’ Consolidated Statements of Income. In July 2016, in connection with the existing agreement, Dominion Energy 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 Energy Gas’ Consolidated Statements of Income. In July 2017, in connection with the existing agreement, Dominion Energy Gas conveyed an additional 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 Energy Gas’ Consolidated Statements of Income. Income:
|
| Three Months Ended September 30, 2019 |
|
| Nine Months Ended September 30, 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 31 |
|
| $ | 110 |
|
Depreciation and amortization |
|
| 1 |
|
|
| 4 |
|
Other operating expenses |
|
| 27 |
|
|
| 83 |
|
Income tax expense |
|
| 1 |
|
|
| 6 |
|
Net income from discontinued operations |
| $ | 2 |
|
| $ | 17 |
|
Capital expenditures and significant noncash items of DGP included the following:
|
| Nine Months Ended September 30, 2019 |
| |
(millions) |
|
|
|
|
Capital expenditures |
| $ | 10 |
|
14
Note 4. Operating Revenue
The Companies’Eastern Energy’s operating revenue consists of the following:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
| $ | 2,108 |
|
| $ | 2,147 |
|
| $ | 5,590 |
|
| $ | 5,707 |
|
Nonregulated |
|
| 380 |
|
|
| 399 |
|
|
| 1,114 |
|
|
| 1,123 |
|
Gas sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
|
| 97 |
|
|
| 46 |
|
|
| 696 |
|
|
| 137 |
|
Nonregulated |
|
| 69 |
|
|
| 87 |
|
|
| 323 |
|
|
| 259 |
|
Gas transportation and storage |
|
| 406 |
|
|
| 378 |
|
|
| 1,328 |
|
|
| 1,162 |
|
Other |
|
| 119 |
|
|
| 75 |
|
|
| 325 |
|
|
| 263 |
|
Total operating revenue |
| $ | 3,179 |
|
| $ | 3,132 |
|
| $ | 9,376 |
|
| $ | 8,651 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated electric sales |
| $ | 2,108 |
|
| $ | 2,147 |
|
| $ | 5,590 |
|
| $ | 5,707 |
|
Other |
|
| 46 |
|
|
| 64 |
|
|
| 142 |
|
|
| 170 |
|
Total operating revenue |
| $ | 2,154 |
|
| $ | 2,211 |
|
| $ | 5,732 |
|
| $ | 5,877 |
|
Dominion Energy Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated |
| $ | 12 |
|
| $ | 28 |
|
| $ | 59 |
|
| $ | 69 |
|
Nonregulated |
|
| 2 |
|
|
| 1 |
|
|
| 12 |
|
|
| 8 |
|
Gas transportation and storage |
|
| 324 |
|
|
| 303 |
|
|
| 1,062 |
|
|
| 955 |
|
Other |
|
| 63 |
|
|
| 50 |
|
|
| 180 |
|
|
| 149 |
|
Total operating revenue |
| $ | 401 |
|
| $ | 382 |
|
| $ | 1,313 |
|
| $ | 1,181 |
|
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated gas transportation and storage(1) |
| $ | 311 |
|
| $ | 306 |
|
| $ | 957 |
|
| $ | 952 |
|
Nonregulated gas transportation and storage |
|
| 175 |
|
|
| 153 |
|
|
| 525 |
|
|
| 501 |
|
Management service revenue(1) |
|
| 16 |
|
|
| 37 |
|
|
| 76 |
|
|
| 126 |
|
Regulated gas sales - wholesale |
|
| 25 |
|
|
| 0 |
|
|
| 27 |
|
|
| 2 |
|
Nonregulated gas sales(1) |
|
| 1 |
|
|
| 1 |
|
|
| 2 |
|
|
| 4 |
|
Other regulated revenues(2) |
|
| 1 |
|
|
| 3 |
|
|
| 4 |
|
|
| 8 |
|
Other nonregulated revenues(1)(2) |
|
| 1 |
|
|
| 1 |
|
|
| 3 |
|
|
| 2 |
|
Total operating revenue from contracts with customers |
|
| 530 |
|
|
| 501 |
|
|
| 1,594 |
|
|
| 1,595 |
|
Other revenues(1) |
|
| 1 |
|
|
| 1 |
|
|
| 3 |
|
|
| 3 |
|
Total operating revenue |
| $ | 531 |
|
| $ | 502 |
|
| $ | 1,597 |
|
| $ | 1,598 |
|
(1) See Note 16 for amounts attributable to related parties and affiliates.
(2) | Amounts above include sales which are considered to be goods transferred at a point in time. Such amounts included $1 million for both the three months ended September 30, 2020 and 2019, and $2 million and $4 million for the nine months ended September 30, 2020 and 2019, respectively, primarily consisting of natural gas liquid sales. |
The table below discloses the aggregate amount of the transaction price allocated to fixed-price performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and when Eastern Energy expects to recognize this revenue. These revenues relate to contracts containing fixed prices where Eastern Energy will earn the associated revenue over time as its stands ready to perform services provided. This disclosure does not include revenue related to performance obligations that are part of a contract with original durations of one year or less. In addition, this disclosure does not include expected consideration related to performance obligations for which Eastern Energy elects to recognize revenue in the amount it has a right to invoice.
Revenue expected to be recognized on multi-year contracts in place at September 30, 2020 |
| 2020 |
|
| 2021 |
|
| 2022 |
|
| 2023 |
|
| 2024 |
|
| Thereafter |
|
| Total |
| |||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 468 |
|
| $ | 1,790 |
|
| $ | 1,669 |
|
| $ | 1,476 |
|
| $ | 1,304 |
|
| $ | 13,412 |
|
| $ | 20,119 |
|
Contract assets represent an entity’s right to consideration in exchange for goods and services that the entity has transferred to a customer. Eastern Energy’s contract asset balances were $32 million and $40 million at September 30, 2020 and December 31, 2019, respectively. Eastern Energy’s contract assets are recorded in other deferred charges and other assets in the Consolidated Balance Sheets. Contract liabilities represent an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration, or the amount that is due, from the customer. At both September 30, 2020 and December 31, 2019, Eastern Energy’s contract liability balances were $20 million. Eastern Energy’s contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets.
Eastern Energy recognizes revenue as it fulfills its obligations to provide service to its customers. During the nine months ended September 30, 2020 and 2019, Eastern Energy recognized $1 million and $30 million, respectively, from the beginning contract liability balance.
15
Note 5. Income Taxes
For continuing operations, including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies'Eastern Energy’s effective income tax rate as follows:
|
| Dominion Energy |
|
| Virginia Power |
|
| Dominion Energy Gas |
|
|
|
|
| ||||||||||||||||||||
Nine Months Ended September 30, |
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2020 |
|
| 2019 |
|
| ||||||||
U.S. statutory rate |
|
| 35.0 | % |
|
| 35.0 | % |
|
| 35.0 | % |
|
| 35.0 | % |
|
| 35.0 | % |
|
| 35.0 | % |
|
| 21.0 | % |
|
| 21.0 | % |
|
Increases (reductions) resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State taxes, net of federal benefit |
|
| 2.9 |
|
|
| 3.7 |
|
|
| 3.7 |
|
|
| 3.9 |
|
|
| 2.7 |
|
|
| 0.8 |
|
|
| (10.4 | ) |
|
| 3.6 |
|
|
Investment tax credits |
|
| (5.7 | ) |
|
| (10.4 | ) |
|
| (0.8 | ) |
|
| — |
|
|
| — |
|
|
| — |
| |||||||||
Production tax credits |
|
| (0.7 | ) |
|
| (0.8 | ) |
|
| (0.5 | ) |
|
| (0.5 | ) |
|
| — |
|
|
| — |
| |||||||||
State legislative change |
|
| — |
|
|
| (0.8 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
| |||||||||
Reversal of excess deferred income taxes |
|
| (4.4 | ) |
|
| (0.9 | ) |
| ||||||||||||||||||||||||
Write-off of regulatory assets |
|
| 8.2 |
|
|
| 0 |
|
| ||||||||||||||||||||||||
Changes in tax status |
|
| (20.9 | ) |
|
| 0 |
|
| ||||||||||||||||||||||||
AFUDC - equity |
|
| (1.3 | ) |
|
| (0.7 | ) |
|
| (0.6 | ) |
|
| (0.6 | ) |
|
| (0.8 | ) |
|
| (0.1 | ) |
|
| (1.7 | ) |
|
| (0.5 | ) |
|
Absence of tax on noncontrolling interest |
|
| (17.9 | ) |
|
| (3.7 | ) |
| ||||||||||||||||||||||||
Other, net |
|
| (2.6 | ) |
|
| (1.4 | ) |
|
| 0.2 |
|
|
| 0.1 |
|
|
| (0.1 | ) |
|
| 0.5 |
|
|
| (8.9 | ) |
|
| 0.2 |
|
|
Effective tax rate |
|
| 27.6 | % |
|
| 24.6 | % |
|
| 37.0 | % |
|
| 37.9 | % |
|
| 36.8 | % |
|
| 36.2 | % |
|
| (35.0 | )% |
|
| 19.7 | % |
|
For Eastern Energy’s rate-regulated subsidiaries, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. Eastern Energy’s rate regulated subsidiaries have recorded an estimate of excess deferred income tax amortization in 2020. The reversal of these excess deferred income taxes will impact the effective tax rate and rates in 2017 for the Companies reflect the completion of audits by state tax authorities that resulted in the recognition of previously unrecognized tax benefits. At December 31, 2016, Virginia Power’s unrecognized tax benefits included state refund claims for open tax years through 2011. Management believed settlement of the claims, including interest thereon, within the next twelve months was remote. In June 2017, Virginia Power received and accepted a cash offercharged to settle the refund claims. As a result of the settlement, Virginia Power decreased its unrecognized tax benefits by $8 million, and recognized a $2 million tax benefit, which impacted its effective tax rate. Also in connection with this settlement, Virginia Power realized interest income of $11 million, which is reflected in other income in the Consolidated Statements of Income. Otherwise, at September 30, 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.customers. See Note 513 to the Consolidated Financial Statements in the Companies'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 20162019 for more information.
For the nine months ended September 30, 2020, Eastern Energy’s effective tax rate is primarily a function of the nominal year-to-date pre-tax income driven by charges associated with the Supply Header Project as discussed in Note 2. In addition, the effective tax rate reflects an income tax benefit of $24 million associated with finalizing the effects of changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring.
In March 2020, the CARES Act was enacted which includes several significant business tax provisions that modify or temporarily suspend certain provisions of the 2017 Tax Reform Act. The CARES Act provisions are intended to improve cash flow and liquidity by, among other things, providing a temporary five-year carryback for certain net operating losses, accelerating the refund of previously generated corporate alternative minimum tax credits and temporarily loosening the business interest limitation to 50% of adjusted taxable income for certain businesses. While Eastern Energy intends to utilize the income tax provisions of the CARES Act where applicable, they are not expected to provide a material benefit.
In July 2020, the U.S. Department of Treasury issued final regulations providing guidance about the limitation on the deduction for business interest expenses and issued proposed regulations on the application of these rules to certain pass-through entities and partners in those entities under the 2017 Tax Reform Act as modified by the CARES Act. Eastern Energy is currently assessing the impact of these regulations, but expects interest expense to be deductible in 2020.
As of September 30, 2020, there have been no material changes in unrecognized tax benefits. Dominion Energy will retain Eastern Energy’s existing unrecognized tax benefits in connection with the GT&S Transaction. See Note 5 to the Consolidated Financial Statements in Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2019, for a discussion of these unrecognized tax benefits.
16
Note 6. Earnings Per ShareAccumulated Other Comprehensive Income
The following table presents the calculation of Dominion Energy’s basic and diluted EPS:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Dominion Energy |
| $ | 665 |
|
| $ | 690 |
|
| $ | 1,687 |
|
| $ | 1,666 |
|
Average shares of common stock outstanding – Basic |
|
| 642.5 |
|
|
| 625.9 |
|
|
| 633.4 |
|
|
| 612.8 |
|
Net effect of dilutive securities(1) |
|
| — |
|
|
| 0.1 |
|
|
| — |
|
|
| 1.0 |
|
Average shares of common stock outstanding – Diluted |
|
| 642.5 |
|
|
| 626.0 |
|
|
| 633.4 |
|
|
| 613.8 |
|
Earnings Per Common Share – Basic |
| $ | 1.03 |
|
| $ | 1.10 |
|
| $ | 2.66 |
|
| $ | 2.72 |
|
Earnings Per Common Share – Diluted |
| $ | 1.03 |
|
| $ | 1.10 |
|
| $ | 2.66 |
|
| $ | 2.71 |
|
|
|
The 2014 Equity Units and 2016 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2017 and 2016, as the dilutive stock price threshold was not met. The Dominion Energy Midstream convertible preferred units are potentially dilutive securities but had no effect on the calculation of diluted EPS for the three and nine months ended September 30, 2017.
Note 7. Accumulated Other Comprehensive Income
Dominion Energy
The following table presents DominionEastern Energy’s changes in AOCI by component, net of tax:
|
| Deferred Gains and Losses on Derivatives-Hedging Activities |
|
| Unrealized Gains and Losses on Investment Securities |
|
| Unrecognized Pension and Other Postretirement Benefit Costs |
|
| Other Comprehensive Income (Loss) From Equity Method Investee |
|
| Total |
| |||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (250 | ) |
| $ | 630 |
|
| $ | (1,058 | ) |
| $ | (4 | ) |
| $ | (682 | ) |
Other comprehensive income before reclassifications: gains |
|
| 11 |
|
|
| 48 |
|
|
| — |
|
|
| — |
|
|
| 59 |
|
Amounts reclassified from AOCI(1): (gains) losses |
|
| (15 | ) |
|
| (4 | ) |
|
| 14 |
|
|
| — |
|
|
| (5 | ) |
Net current-period other comprehensive income (loss) |
|
| (4 | ) |
|
| 44 |
|
|
| 14 |
|
|
| — |
|
|
| 54 |
|
Ending balance |
| $ | (254 | ) |
| $ | 674 |
|
| $ | (1,044 | ) |
| $ | (4 | ) |
| $ | (628 | ) |
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (241 | ) |
| $ | 535 |
|
| $ | (781 | ) |
| $ | (6 | ) |
| $ | (493 | ) |
Other comprehensive income before reclassifications: gains |
|
| 14 |
|
|
| 31 |
|
|
| 15 |
|
|
| — |
|
|
| 60 |
|
Amounts reclassified from AOCI(1): (gains) losses |
|
| (34 | ) |
|
| (13 | ) |
|
| 9 |
|
|
| — |
|
|
| (38 | ) |
Net current-period other comprehensive income (loss) |
|
| (20 | ) |
|
| 18 |
|
|
| 24 |
|
|
| — |
|
|
| 22 |
|
Ending balance |
| $ | (261 | ) |
| $ | 553 |
|
| $ | (757 | ) |
| $ | (6 | ) |
| $ | (471 | ) |
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (280 | ) |
| $ | 569 |
|
| $ | (1,082 | ) |
| $ | (6 | ) |
| $ | (799 | ) |
Other comprehensive income before reclassifications: gains |
|
| 82 |
|
|
| 141 |
|
|
| — |
|
|
| 2 |
|
|
| 225 |
|
Amounts reclassified from AOCI(1): (gains) losses |
|
| (56 | ) |
|
| (36 | ) |
|
| 38 |
|
|
| — |
|
|
| (54 | ) |
Net current-period other comprehensive income |
|
| 26 |
|
|
| 105 |
|
|
| 38 |
|
|
| 2 |
|
|
| 171 |
|
Ending balance |
| $ | (254 | ) |
| $ | 674 |
|
| $ | (1,044 | ) |
| $ | (4 | ) |
| $ | (628 | ) |
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (176 | ) |
| $ | 504 |
|
| $ | (797 | ) |
| $ | (5 | ) |
| $ | (474 | ) |
Other comprehensive income before reclassifications: gains (losses) |
|
| 56 |
|
|
| 72 |
|
|
| 15 |
|
|
| (1 | ) |
|
| 142 |
|
Amounts reclassified from AOCI(1): (gains) losses |
|
| (141 | ) |
|
| (23 | ) |
|
| 25 |
|
|
| — |
|
|
| (139 | ) |
Net current-period other comprehensive income (loss) |
|
| (85 | ) |
|
| 49 |
|
|
| 40 |
|
|
| (1 | ) |
|
| 3 |
|
Ending balance |
| $ | (261 | ) |
| $ | 553 |
|
| $ | (757 | ) |
| $ | (6 | ) |
| $ | (471 | ) |
|
| Deferred gains and losses on derivatives- hedging activities |
|
| Unrecognized pension costs |
|
| Total |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (168 | ) |
| $ | (103 | ) |
| $ | (271 | ) |
Other comprehensive income before reclassifications: gains (losses) |
|
| 12 |
|
|
| (4 | ) |
|
| 8 |
|
Amounts reclassified from AOCI: (gains) losses(1) |
|
| 99 |
|
|
| 0 |
|
|
| 99 |
|
Net current period other comprehensive income (loss) |
|
| 111 |
|
|
| (4 | ) |
|
| 107 |
|
Ending balance |
| $ | (57 | ) |
| $ | (107 | ) |
| $ | (164 | ) |
Three Months Ended September 30, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (74 | ) |
| $ | (112 | ) |
| $ | (186 | ) |
Other comprehensive income before reclassifications: gains (losses) |
|
| (36 | ) |
|
| (1 | ) |
|
| (37 | ) |
Amounts reclassified from AOCI: (gains) losses(1) |
|
| 9 |
|
|
| 1 |
|
|
| 10 |
|
Net current period other comprehensive income (loss) |
|
| (27 | ) |
|
| — |
|
|
| (27 | ) |
Ending balance |
| $ | (101 | ) |
| $ | (112 | ) |
| $ | (213 | ) |
Nine Months Ended September 30, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (81 | ) |
| $ | (106 | ) |
| $ | (187 | ) |
Other comprehensive income before reclassifications: gains (losses) |
|
| (79 | ) |
|
| (4 | ) |
|
| (83 | ) |
Amounts reclassified from AOCI: (gains) losses(1) |
|
| 103 |
|
|
| 3 |
|
|
| 106 |
|
Net current period other comprehensive income (loss) |
|
| 24 |
|
|
| (1 | ) |
|
| 23 |
|
Ending balance |
| $ | (57 | ) |
| $ | (107 | ) |
| $ | (164 | ) |
Nine Months Ended September 30, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (25 | ) |
| $ | (144 | ) |
| $ | (169 | ) |
Other comprehensive income before reclassifications: gains (losses) |
|
| (87 | ) |
|
| 28 |
|
|
| (59 | ) |
Amounts reclassified from AOCI: (gains) losses(1) |
|
| 10 |
|
|
| 4 |
|
|
| 14 |
|
Net current period other comprehensive income (loss) |
|
| (77 | ) |
|
| 32 |
|
|
| (45 | ) |
Less other comprehensive income (loss) attributable to noncontrolling interest |
|
| (1 | ) |
|
| 0 |
|
|
| (1 | ) |
Ending balance |
| $ | (101 | ) |
| $ | (112 | ) |
| $ | (213 | ) |
(1) | See table below for details about these reclassifications. |
17
The following table presents DominionEastern Energy’s reclassifications out of AOCI by component:
Details About AOCI Components |
| Amounts Reclassified From AOCI |
|
| Affected Line Item in the Consolidated Statements of Income | |
(millions) |
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
| $ | (32 | ) |
| Operating revenue |
|
|
| 1 |
|
| Electric fuel and other energy-related purchases |
Interest rate contracts |
|
| 16 |
|
| Interest and related charges |
Foreign currency contracts |
|
| (10 | ) |
| Other income |
|
|
| (25 | ) |
|
|
Tax |
|
| 10 |
|
| Income tax expense |
|
| $ | (15 | ) |
|
|
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
|
Realized (gain) loss on sale of securities |
| $ | (10 | ) |
| Other income |
Impairment |
|
| 4 |
|
| Other income |
|
|
| (6 | ) |
|
|
Tax |
|
| 2 |
|
| Income tax expense |
|
| $ | (4 | ) |
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Prior service (credit) costs |
| $ | (5 | ) |
| Other operations and maintenance |
Actuarial (gains) losses |
|
| 26 |
|
| Other operations and maintenance |
|
|
| 21 |
|
|
|
Tax |
|
| (7 | ) |
| Income tax expense |
|
| $ | 14 |
|
|
|
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
| $ | (64 | ) |
| Operating revenue |
|
|
| 1 |
|
| Purchased gas |
|
|
| 1 |
|
| Electric fuel and other energy-related purchases |
Interest rate contracts |
|
| 10 |
|
| Interest and related charges |
Foreign currency contracts |
|
| (3 | ) |
| Other income |
|
|
| (55 | ) |
|
|
Tax |
|
| 21 |
|
| Income tax expense |
|
| $ | (34 | ) |
|
|
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
|
Realized (gain) loss on sale of securities |
| $ | (25 | ) |
| Other income |
Impairment |
|
| 5 |
|
| Other income |
|
|
| (20 | ) |
|
|
Tax |
|
| 7 |
|
| Income tax expense |
|
| $ | (13 | ) |
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Prior service (credit) costs |
| $ | (4 | ) |
| Other operations and maintenance |
Actuarial (gains) losses |
|
| 17 |
|
| Other operations and maintenance |
|
|
| 13 |
|
|
|
Tax |
|
| (4 | ) |
| Income tax expense |
|
| $ | 9 |
|
|
|
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
| $ | (114 | ) |
| Operating revenue |
|
|
| (1 | ) |
| Electric fuel and other energy-related purchases |
Interest rate contracts |
|
| 39 |
|
| Interest and related charges |
Details About AOCI Components |
| Amounts Reclassified From AOCI |
|
| Affected Line Item in the Consolidated Statements of Income | |||||||
Details about AOCI components |
| Amounts reclassified from AOCI |
|
| Affected line item in the Consolidated Statements of Income | |||||||
(millions) |
|
|
|
|
|
| ||||||
Three Months Ended September 30, 2020 |
|
|
|
|
|
| ||||||
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
| ||||||
Interest rate contracts |
| $ | 145 |
|
| Interest and related charges | ||||||
|
| (15 | ) |
| Other income |
|
| (12 | ) |
| Other income | |
|
|
| (91 | ) |
|
| ||||||
Total |
|
| 133 |
|
|
| ||||||
Tax |
|
| 35 |
|
| Income tax expense |
|
| (34 | ) |
| Income tax expense (benefit) |
|
| $ | (56 | ) |
|
| ||||||
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
| ||||||
Realized (gain) loss on sale of securities |
| $ | (74 | ) |
| Other income | ||||||
Impairment |
|
| 18 |
|
| Other income | ||||||
|
|
| (56 | ) |
|
| ||||||
Total, net of tax |
| $ | 99 |
|
|
| ||||||
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
| ||||||
Actuarial losses |
| $ | 1 |
|
| Other income | ||||||
Total |
|
| 1 |
|
|
| ||||||
Tax |
|
| 20 |
|
| Income tax expense |
|
| (1 | ) |
| Income tax expense (benefit) |
|
| $ | (36 | ) |
|
| ||||||
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
| ||||||
Prior service (credit) costs |
| $ | (16 | ) |
| Other operations and maintenance | ||||||
Actuarial (gains) losses |
|
| 79 |
|
| Other operations and maintenance | ||||||
|
|
| 63 |
|
|
| ||||||
Tax |
|
| (25 | ) |
| Income tax expense | ||||||
|
| $ | 38 |
|
|
| ||||||
Nine Months Ended September 30, 2016 |
|
|
|
|
|
| ||||||
Total, net of tax |
| $ | 0 |
|
|
| ||||||
Three Months Ended September 30, 2019 |
|
|
|
|
|
| ||||||
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
| $ | (266 | ) |
| Operating revenue |
| $ | (2 | ) |
| Net income from discontinued operations |
|
|
| 9 |
|
| Purchased gas | ||||||
|
|
| 8 |
|
| Electric fuel and other energy-related purchases | ||||||
Interest rate contracts |
|
| 21 |
|
| Interest and related charges |
|
| 2 |
|
| Interest and related charges |
Foreign currency contracts |
|
| (1 | ) |
| Other income |
|
| 12 |
|
| Other income |
|
|
| (229 | ) |
|
| ||||||
Total |
|
| 12 |
|
|
| ||||||
Tax |
|
| 88 |
|
| Income tax expense |
|
| (3 | ) |
| Income tax expense (benefit) |
|
| $ | (141 | ) |
|
| ||||||
Unrealized (gains) and losses on investment securities: |
|
|
|
|
|
| ||||||
Realized (gain) loss on sale of securities |
| $ | (55 | ) |
| Other income | ||||||
Impairment |
|
| 19 |
|
| Other income | ||||||
|
|
| (36 | ) |
|
| ||||||
Total, net of tax |
| $ | 9 |
|
|
| ||||||
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
| ||||||
Actuarial losses |
| $ | 1 |
|
| Other income | ||||||
Total |
|
| 1 |
|
|
| ||||||
Tax |
|
| 13 |
|
| Income tax expense |
|
| 0 |
|
| Income tax expense (benefit) |
|
| $ | (23 | ) |
|
| ||||||
Total, net of tax |
| $ | 1 |
|
|
| ||||||
Nine Months Ended September 30, 2020 |
|
|
|
|
|
| ||||||
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
| ||||||
Interest rate contracts |
| $ | 151 |
|
| Interest and related charges | ||||||
Foreign currency contracts |
|
| (12 | ) |
| Other income | ||||||
Total |
|
| 139 |
|
|
| ||||||
Tax |
|
| (36 | ) |
| Income tax expense (benefit) | ||||||
Total, net of tax |
| $ | 103 |
|
|
| ||||||
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Prior service (credit) costs |
| $ | (11 | ) |
| Other operations and maintenance | ||||||
Actuarial (gains) losses |
|
| 52 |
|
| Other operations and maintenance | ||||||
|
|
| 41 |
|
|
| ||||||
Actuarial losses |
| $ | 5 |
|
| Other income | ||||||
Total |
|
| 5 |
|
|
| ||||||
Tax |
|
| (16 | ) |
| Income tax expense |
|
| (2 | ) |
| Income tax expense (benefit) |
|
| $ | 25 |
|
|
| ||||||
Total, net of tax |
| $ | 3 |
|
|
| ||||||
Nine Months Ended September 30, 2019 |
|
|
|
|
|
| ||||||
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
| ||||||
Commodity contracts |
| $ | (4 | ) |
| Net income from discontinued operations | ||||||
Interest rate contracts |
|
| 3 |
|
| Interest and related charges | ||||||
Foreign currency contracts |
|
| 14 |
|
| Other income | ||||||
Total |
|
| 13 |
|
|
| ||||||
Tax |
|
| (3 | ) |
| Income tax expense (benefit) | ||||||
Total, net of tax |
| $ | 10 |
|
|
| ||||||
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
| ||||||
Actuarial losses |
| $ | 5 |
|
| Other income | ||||||
Total |
|
| 5 |
|
|
| ||||||
Tax |
|
| (1 | ) |
| Income tax expense (benefit) | ||||||
Total, net of tax |
| $ | 4 |
|
|
| ||||||
The following table presents Dominion Energy Gas’ changes in AOCI by component, net of tax:
|
| Deferred Gains and Losses on Derivatives-Hedging Activities |
|
| Unrecognized Pension and Other Postretirement Benefit Costs |
|
| Total |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (23 | ) |
| $ | (97 | ) |
| $ | (120 | ) |
Other comprehensive income before reclassifications: gains |
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Amounts reclassified from AOCI(1): (gains) losses |
|
| (4 | ) |
|
| 1 |
|
|
| (3 | ) |
Net current-period other comprehensive income (loss) |
|
| (3 | ) |
|
| 1 |
|
|
| (2 | ) |
Ending balance |
| $ | (26 | ) |
| $ | (96 | ) |
| $ | (122 | ) |
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (34 | ) |
| $ | (81 | ) |
| $ | (115 | ) |
Other comprehensive income before reclassifications: gains |
|
| 9 |
|
|
| — |
|
|
| 9 |
|
Amounts reclassified from AOCI(1): (gains) losses |
|
| (1 | ) |
|
| 1 |
|
|
| — |
|
Net current-period other comprehensive income |
|
| 8 |
|
|
| 1 |
|
|
| 9 |
|
Ending balance |
| $ | (26 | ) |
| $ | (80 | ) |
| $ | (106 | ) |
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (24 | ) |
| $ | (99 | ) |
| $ | (123 | ) |
Other comprehensive income before reclassifications: gains |
|
| 3 |
|
|
| — |
|
|
| 3 |
|
Amounts reclassified from AOCI(1): (gains) losses |
|
| (5 | ) |
|
| 3 |
|
|
| (2 | ) |
Net current-period other comprehensive income (loss) |
|
| (2 | ) |
|
| 3 |
|
|
| 1 |
|
Ending balance |
| $ | (26 | ) |
| $ | (96 | ) |
| $ | (122 | ) |
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (17 | ) |
| $ | (82 | ) |
| $ | (99 | ) |
Other comprehensive income before reclassifications: losses |
|
| (6 | ) |
|
| — |
|
|
| (6 | ) |
Amounts reclassified from AOCI(1): (gains) losses |
|
| (3 | ) |
|
| 2 |
|
|
| (1 | ) |
Net current-period other comprehensive income (loss) |
|
| (9 | ) |
|
| 2 |
|
|
| (7 | ) |
Ending balance |
| $ | (26 | ) |
| $ | (80 | ) |
| $ | (106 | ) |
|
|
The following table presents Dominion Energy Gas' reclassifications out of AOCI by component:
Details About AOCI Components |
| Amounts Reclassified From AOCI |
|
| Affected Line Item in the Consolidated Statements of Income | |
(millions) |
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
| $ | 2 |
|
| Operating revenue |
Interest rate contracts |
|
| 1 |
|
| Interest and related charges |
Foreign currency contracts |
|
| (10 | ) |
| Other income |
|
|
| (7 | ) |
|
|
Tax |
|
| 3 |
|
| Income tax expense |
|
| $ | (4 | ) |
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Actuarial (gains) losses |
| $ | 2 |
|
| Other operations and maintenance |
|
|
| 2 |
|
|
|
Tax |
|
| (1 | ) |
| Income tax expense |
|
| $ | 1 |
|
|
|
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
| $ | (1 | ) |
| Operating revenue |
Interest rate contracts |
|
| 1 |
|
| Interest and related charges |
Foreign currency contracts |
|
| (3 | ) |
| Other income |
|
|
| (3 | ) |
|
|
Tax |
|
| 2 |
|
| Income tax expense |
|
| $ | (1 | ) |
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Actuarial (gains) losses |
| $ | 2 |
|
| Other operations and maintenance |
|
|
| 2 |
|
|
|
Tax |
|
| (1 | ) |
| Income tax expense |
|
| $ | 1 |
|
|
|
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
| $ | 4 |
|
| Operating revenue |
Interest rate contracts |
|
| 3 |
|
| Interest and related charges |
Foreign currency contracts |
|
| (15 | ) |
| Other income |
|
|
| (8 | ) |
|
|
Tax |
|
| 3 |
|
| Income tax expense |
|
| $ | (5 | ) |
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Actuarial (gains) losses |
| $ | 5 |
|
| Other operations and maintenance |
|
|
| 5 |
|
|
|
Tax |
|
| (2 | ) |
| Income tax expense |
|
| $ | 3 |
|
|
|
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
Deferred (gains) and losses on derivatives-hedging activities: |
|
|
|
|
|
|
Commodity contracts |
| $ | (6 | ) |
| Operating revenue |
Interest rate contracts |
|
| 2 |
|
| Interest and related charges |
Foreign currency contracts |
|
| (1 | ) |
| Other income |
|
|
| (5 | ) |
|
|
Tax |
|
| 2 |
|
| Income tax expense |
|
| $ | (3 | ) |
|
|
Unrecognized pension and other postretirement benefit costs: |
|
|
|
|
|
|
Actuarial (gains) losses |
| $ | 4 |
|
| Other operations and maintenance |
|
|
| 4 |
|
|
|
Tax |
|
| (2 | ) |
| Income tax expense |
|
| $ | 2 |
|
|
|
Note 8.7. Fair Value Measurements
The Companies'Eastern Energy’s fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in the Companies'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016.2019. See Note 98 in this report for further information about the Companies'Eastern Energy’s derivatives and hedge accounting activities.
The Companies enter into certain physical and financial forwards, futures, options and swaps, which All of Eastern Energy’s derivatives 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 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 changes2 in third-party pricing sources.
The following table presents Dominion Energy's quantitative information about Level 3 fair value measurements at September 30, 2017. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.
|
| Fair Value (millions) |
|
| Valuation Techniques |
| Unobservable Input |
|
| Range |
| Weighted Average(1) |
| ||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical and financial forwards and futures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas(2) |
| $ | 91 |
|
| Discounted cash flow |
| Market price (per Dth) | (3) |
| (2) - 7 |
|
| — |
|
FTRs |
|
| 19 |
|
| Discounted cash flow |
| Market price (per MWh) | (3) |
| (3) - 7 |
|
| 1 |
|
Physical options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
| 2 |
|
| Option model |
| Market price (per Dth) | (3) |
| 2 - 7 |
|
| 4 |
|
|
|
|
|
|
|
|
| Price volatility | (4) |
| 24% - 46% |
|
| 32 | % |
Electricity |
|
| 42 |
|
| Option model |
| Market price (per MWh) | (3) |
| 21 - 50 |
|
| 34 |
|
|
|
|
|
|
|
|
| Price volatility | (4) |
| 0% - 78% |
|
| 28 | % |
Total assets |
| $ | 154 |
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial forwards: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FTRs |
| $ | 1 |
|
| Discounted cash flow |
| Market price (per MWh) | (3) |
| (5) - 7 |
|
| 1 |
|
Total liabilities |
| $ | 1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:hierarchy.
|
|
|
| |||
|
|
|
| |||
|
|
|
| |||
|
|
|
| |||
|
|
|
|
Recurring Fair Value Measurements
Dominion Energy
The following table presents Dominion Energy’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 59 |
|
| $ | 154 |
|
| $ | 213 |
|
Interest rate |
|
| — |
|
|
| 11 |
|
|
| — |
|
|
| 11 |
|
Foreign currency |
|
| — |
|
|
| 25 |
|
|
| — |
|
|
| 25 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 3,288 |
|
|
| — |
|
|
| — |
|
|
| 3,288 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| — |
|
|
| 452 |
|
|
| — |
|
|
| 452 |
|
Government securities |
|
| 475 |
|
|
| 631 |
|
|
| — |
|
|
| 1,106 |
|
Cash equivalents and other |
|
| 7 |
|
|
| — |
|
|
| — |
|
|
| 7 |
|
Total assets |
| $ | 3,770 |
|
| $ | 1,178 |
|
| $ | 154 |
|
| $ | 5,102 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 41 |
|
| $ | 1 |
|
| $ | 42 |
|
Interest rate |
|
| — |
|
|
| 72 |
|
|
| — |
|
|
| 72 |
|
Foreign currency |
|
| — |
|
|
| 4 |
|
|
| — |
|
|
| 4 |
|
Total liabilities |
| $ | — |
|
| $ | 117 |
|
| $ | 1 |
|
| $ | 118 |
|
December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 115 |
|
| $ | 147 |
|
| $ | 262 |
|
Interest rate |
|
| — |
|
|
| 17 |
|
|
| — |
|
|
| 17 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 2,913 |
|
|
| — |
|
|
| — |
|
|
| 2,913 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| — |
|
|
| 487 |
|
|
| — |
|
|
| 487 |
|
Government securities |
|
| 424 |
|
|
| 614 |
|
|
| — |
|
|
| 1,038 |
|
Cash equivalents and other |
|
| 5 |
|
|
| — |
|
|
| — |
|
|
| 5 |
|
Total assets |
| $ | 3,342 |
|
| $ | 1,233 |
|
| $ | 147 |
|
| $ | 4,722 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 88 |
|
| $ | 8 |
|
| $ | 96 |
|
Interest rate |
|
| — |
|
|
| 53 |
|
|
| — |
|
|
| 53 |
|
Foreign currency |
|
| — |
|
|
| 6 |
|
|
| — |
|
|
| 6 |
|
Total liabilities |
| $ | — |
|
| $ | 147 |
|
| $ | 8 |
|
| $ | 155 |
|
|
|
The following table presents the net change in Dominion Energy's assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | 152 |
|
| $ | 124 |
|
| $ | 139 |
|
| $ | 95 |
|
Total realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
| (11 | ) |
|
| (7 | ) |
|
| (36 | ) |
|
| (23 | ) |
Included in other comprehensive income |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2 |
|
Included in regulatory assets/liabilities |
|
| 11 |
|
|
| (37 | ) |
|
| 34 |
|
|
| (5 | ) |
Settlements |
|
| 1 |
|
|
| 9 |
|
|
| 13 |
|
|
| 27 |
|
Transfers out of Level 3 |
|
| — |
|
|
| — |
|
|
| 3 |
|
|
| (7 | ) |
Ending balance |
| $ | 153 |
|
| $ | 89 |
|
| $ | 153 |
|
| $ | 89 |
|
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date |
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
| $ | — |
|
The following table presents Dominion Energy’s classification of gains and losses included in earnings in the Level 3 fair value category.
|
| Operating Revenue |
|
| Electric Fuel and Other Energy - Related Purchases |
|
| Total |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Total gains (losses) included in earnings |
| $ | 1 |
|
| $ | (12 | ) |
| $ | (11 | ) |
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date |
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Total gains (losses) included in earnings |
| $ | — |
|
| $ | (7 | ) |
| $ | (7 | ) |
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Total gains (losses) included in earnings |
| $ | 1 |
|
| $ | (37 | ) |
| $ | (36 | ) |
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date |
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Total gains (losses) included in earnings |
| $ | — |
|
| $ | (23 | ) |
| $ | (23 | ) |
The following table presents Virginia Power's quantitative information about Level 3 fair value measurements at September 30, 2017. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.
|
| Fair Value (millions) |
|
| Valuation Techniques |
| Unobservable Input |
|
| Range |
| Weighted Average(1) |
| ||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical and financial forwards and futures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas(2) |
| $ | 91 |
|
| Discounted cash flow |
| Market price (per Dth) | (3) |
| (2) - 7 |
|
| (1 | ) |
FTRs |
|
| 19 |
|
| Discounted cash flow |
| Market price (per MWh) | (3) |
| (1) - 7 |
|
| 1 |
|
Physical options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
| 1 |
|
| Option model |
| Market price (per Dth) | (3) |
| 2 - 7 |
|
| 4 |
|
|
|
|
|
|
|
|
| Price volatility | (4) |
| 24% - 46% |
|
| 32 | % |
Electricity |
|
| 42 |
|
| Option model |
| Market price (per MWh) | (3) |
| 21 - 50 |
|
| 34 |
|
|
|
|
|
|
|
|
| Price volatility | (4) |
| 0% - 78% |
|
| 28 | % |
Total assets |
| $ | 153 |
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial forwards: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FTRs |
| $ | 1 |
|
| Discounted cash flow |
| Market price (per MWh) | (3) |
| (5) - 7 |
|
| 1 |
|
Total liabilities |
| $ | 1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
|
|
|
| |||
|
|
|
| |||
|
|
|
| |||
|
|
|
| |||
|
|
|
|
The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 15 |
|
| $ | 153 |
|
| $ | 168 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 1,471 |
|
|
| — |
|
|
| — |
|
|
| 1,471 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| — |
|
|
| 234 |
|
|
| — |
|
|
| 234 |
|
Government securities |
|
| 193 |
|
|
| 302 |
|
|
| — |
|
|
| 495 |
|
Total assets |
| $ | 1,664 |
|
| $ | 551 |
|
| $ | 153 |
|
| $ | 2,368 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 5 |
|
| $ | 1 |
|
| $ | 6 |
|
Interest rate |
|
| — |
|
|
| 55 |
|
|
| — |
|
|
| 55 |
|
Total liabilities |
| $ | — |
|
| $ | 60 |
|
| $ | 1 |
|
| $ | 61 |
|
December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 43 |
|
| $ | 145 |
|
| $ | 188 |
|
Interest rate |
|
| — |
|
|
| 6 |
|
|
| — |
|
|
| 6 |
|
Investments(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
| 1,302 |
|
|
| — |
|
|
| — |
|
|
| 1,302 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| — |
|
|
| 277 |
|
|
| — |
|
|
| 277 |
|
Government securities |
|
| 136 |
|
|
| 291 |
|
|
| — |
|
|
| 427 |
|
Total assets |
| $ | 1,438 |
|
| $ | 617 |
|
| $ | 145 |
|
| $ | 2,200 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 8 |
|
| $ | 2 |
|
| $ | 10 |
|
Interest rate |
|
| — |
|
|
| 21 |
|
|
| — |
|
|
| 21 |
|
Total liabilities |
| $ | — |
|
| $ | 29 |
|
| $ | 2 |
|
| $ | 31 |
|
|
|
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:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance |
| $ | 152 |
|
| $ | 125 |
|
| $ | 143 |
|
| $ | 93 |
|
Total realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
| (12 | ) |
|
| (7 | ) |
|
| (37 | ) |
|
| (24 | ) |
Included in regulatory assets/liabilities |
|
| 11 |
|
|
| (37 | ) |
|
| 34 |
|
|
| (5 | ) |
Settlements |
|
| 1 |
|
|
| 7 |
|
|
| 12 |
|
|
| 24 |
|
Ending balance |
| $ | 152 |
|
| $ | 88 |
|
| $ | 152 |
|
| $ | 88 |
|
The gains and losses included in earnings in the Level 3 fair value category were classified in electric fuel and other energy-related purchases in Virginia Power's Consolidated Statements of Income for the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016.
Dominion Energy Gas
The following table presents Dominion Energy Gas' assets and liabilities for derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions.
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
Foreign currency |
|
| — |
|
|
| 25 |
|
|
| — |
|
|
| 25 |
|
Total assets |
| $ | — |
|
| $ | 26 |
|
| $ | — |
|
| $ | 26 |
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 6 |
|
| $ | — |
|
| $ | 6 |
|
Foreign currency |
|
| — |
|
|
| 4 |
|
|
| — |
|
|
| 4 |
|
Total liabilities |
| $ | — |
|
| $ | 10 |
|
| $ | — |
|
| $ | 10 |
|
December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 3 |
|
| $ | 2 |
|
| $ | 5 |
|
Foreign currency |
|
| — |
|
|
| 6 |
|
|
| — |
|
|
| 6 |
|
Total liabilities |
| $ | — |
|
| $ | 9 |
|
| $ | 2 |
|
| $ | 11 |
|
The following table presents the net change in Dominion Energy Gas' assets and liabilities for derivatives measured at fair value on a recurring basis and included in the Level 3 fair value category. There were no net changes in assets and liabilities for derivatives measured at fair value on a recurring basis and included in the Level 3 fair value category for the three months ended September 30, 2017 and 2016.
|
| Nine Months Ended September 30, |
| |||||
|
| 2017 |
|
| 2016 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Beginning balance |
| $ | (2 | ) |
| $ | 6 |
|
Total realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
Included in other comprehensive income (loss) |
|
| (1 | ) |
|
| 2 |
|
Transfers out of Level 3 |
|
| 3 |
|
|
| (8 | ) |
Ending balance |
| $ | — |
|
| $ | — |
|
There were no gains or losses included in earnings in the Level 3 fair value category for the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016.
Fair Value of Financial Instruments
Substantially all of the Companies'Eastern Energy’s 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 Dominion Energy’s other current assets),and equivalents, 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'Eastern Energy’s financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||
|
| Carrying Amount |
|
| Estimated Fair Value(1) |
|
| Carrying Amount |
|
| Estimated Fair Value(1) |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, including securities due within one year(2) |
| $ | 28,317 |
|
| $ | 30,639 |
|
| $ | 26,587 |
|
| $ | 28,273 |
|
Junior subordinated notes(3) |
|
| 3,980 |
|
|
| 4,128 |
|
|
| 2,980 |
|
|
| 2,893 |
|
Remarketable subordinated notes(3) |
|
| 1,377 |
|
|
| 1,421 |
|
|
| 2,373 |
|
|
| 2,418 |
|
Virginia Power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, including securities due within one year(3) |
| $ | 11,346 |
|
| $ | 12,686 |
|
| $ | 10,530 |
|
| $ | 11,584 |
|
Dominion Energy Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt(4) |
| $ | 3,564 |
|
| $ | 3,705 |
|
| $ | 3,528 |
|
| $ | 3,603 |
|
|
| September 30, 2020 |
|
| December 31, 2019 |
| ||||||||||
|
| Carrying Amount |
|
| Estimated Fair Value(1) |
|
| Carrying Amount |
|
| Estimated Fair Value(1) |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt(2) |
| $ | 5,536 |
|
| $ | 6,042 |
|
| $ | 5,520 |
|
| $ | 5,738 |
|
(1) | Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt |
(2) | Carrying amount includes |
|
|
|
|
Note 9.8. Derivatives and Hedge Accounting Activities
The Companies'Eastern Energy’s accounting policies, objectives and strategies for using derivative instruments are discussed in Note 2 to the Consolidated Financial Statements in the Companies'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016.2019. See Note 87 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 Energy'sEastern Energy’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 Energy Gas' derivative contracts consist of over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a counterparty. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions.third party. 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-counterOver-the-counter transactions and all exchange contracts arecan be subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts could 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. See Note 15 for further information regarding credit-related contingent features for derivative instruments.
19
Balance Sheet Presentation
The tables below present Dominion Energy'sEastern Energy’s derivative asset and liability balances by type of financial instrument, beforeif the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and after the effects of offsetting:cash collateral received or paid:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||||||||||
|
| Gross Amounts of Recognized Assets |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
| Gross Amounts of Recognized Assets |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 186 |
|
| $ | — |
|
| $ | 186 |
|
| $ | 211 |
|
| $ | — |
|
| $ | 211 |
|
Exchange |
|
| 24 |
|
|
| — |
|
|
| 24 |
|
|
| 44 |
|
|
| — |
|
|
| 44 |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 11 |
|
|
| — |
|
|
| 11 |
|
|
| 17 |
|
|
| — |
|
|
| 17 |
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 25 |
|
|
| — |
|
|
| 25 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total derivatives, subject to a master netting or similar arrangement |
|
| 246 |
|
|
| — |
|
|
| 246 |
|
|
| 272 |
|
|
| — |
|
|
| 272 |
|
Total derivatives, not subject to a master netting or similar arrangement |
|
| 3 |
|
|
| — |
|
|
| 3 |
|
|
| 7 |
|
|
| — |
|
|
| 7 |
|
Total |
| $ | 249 |
|
| $ | — |
|
| $ | 249 |
|
| $ | 279 |
|
| $ | — |
|
| $ | 279 |
|
|
| September 30, 2020 |
|
| December 31, 2019 |
| ||||||||||||||||||||||||||
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
| ||||||||||||||||||||||||||
|
| Gross Assets Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Received |
|
| Net Amounts |
|
| Gross Assets Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Received |
|
| Net Amounts |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 6 |
|
| $ | 6 |
|
| $ | 0 |
|
| $ | 0 |
|
| $ | 8 |
|
| $ | 8 |
|
| $ | 0 |
|
| $ | 0 |
|
Total derivatives, subject to a master netting or similar arrangement |
| $ | 6 |
|
| $ | 6 |
|
| $ | 0 |
|
| $ | 0 |
|
| $ | 8 |
|
| $ | 8 |
|
| $ | 0 |
|
| $ | 0 |
|
|
|
|
|
| September 30, 2017 |
|
|
|
|
|
|
|
|
|
| December 31, 2016 |
|
|
|
|
| |||||||||||
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
| |||||||||||
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Received |
|
| Net Amounts |
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Received |
|
| Net Amounts |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 186 |
|
| $ | 8 |
|
| $ | — |
|
| $ | 178 |
|
| $ | 211 |
|
| $ | 14 |
|
| $ | — |
|
| $ | 197 |
|
Exchange |
|
| 24 |
|
|
| 21 |
|
|
| — |
|
|
| 3 |
|
|
| 44 |
|
|
| 44 |
|
|
| — |
|
|
| — |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 11 |
|
|
| 6 |
|
|
| — |
|
|
| 5 |
|
|
| 17 |
|
|
| 9 |
|
|
| — |
|
|
| 8 |
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 25 |
|
|
| 4 |
|
|
| — |
|
|
| 21 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total |
| $ | 246 |
|
| $ | 39 |
|
| $ | — |
|
| $ | 207 |
|
| $ | 272 |
|
| $ | 67 |
|
| $ | — |
|
| $ | 205 |
|
| September 30, 2017 |
|
| December 31, 2016 |
| |||||||||||||||||||
|
| Gross Amounts of Recognized Liabilities |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
| Gross Amounts of Recognized Liabilities |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 19 |
|
| $ | — |
|
| $ | 19 |
|
| $ | 23 |
|
| $ | — |
|
| $ | 23 |
|
Exchange |
|
| 21 |
|
|
| — |
|
|
| 21 |
|
|
| 71 |
|
|
| — |
|
|
| 71 |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 72 |
|
|
| — |
|
|
| 72 |
|
|
| 53 |
|
|
| — |
|
|
| 53 |
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 4 |
|
|
| — |
|
|
| 4 |
|
|
| 6 |
|
|
| — |
|
|
| 6 |
|
Total derivatives, subject to a master netting or similar arrangement |
|
| 116 |
|
|
| — |
|
|
| 116 |
|
|
| 153 |
|
|
| — |
|
|
| 153 |
|
Total derivatives, not subject to a master netting or similar arrangement |
|
| 2 |
|
|
| — |
|
|
| 2 |
|
|
| 2 |
|
|
| — |
|
|
| 2 |
|
Total |
| $ | 118 |
|
| $ | — |
|
| $ | 118 |
|
| $ | 155 |
|
| $ | — |
|
| $ | 155 |
|
|
|
|
|
| September 30, 2017 |
|
|
|
|
|
|
|
|
|
| December 31, 2016 |
|
|
|
|
|
| September 30, 2020 |
|
| December 31, 2019 |
| |||||||||||||||||||||||||||||||||||||
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
| |||||||||||||||||||||||||||||||||||||
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Paid |
|
| Net Amounts |
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Paid |
|
| Net Amounts |
|
| Gross Liabilities Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Paid |
|
| Net Amounts |
|
| Gross Liabilities Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Paid |
|
| Net Amounts |
| ||||||||||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||
Over-the-counter |
| $ | 19 |
|
| $ | 8 |
|
| $ | — |
|
| $ | 11 |
|
| $ | 23 |
|
| $ | 14 |
|
| $ | — |
|
| $ | 9 |
| ||||||||||||||||||||||||||||||||
Exchange |
|
| 21 |
|
|
| 21 |
|
|
| — |
|
|
| — |
|
|
| 71 |
|
|
| 44 |
|
|
| 27 |
|
|
| — |
| ||||||||||||||||||||||||||||||||
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 72 |
|
|
| 6 |
|
|
| — |
|
|
| 66 |
|
|
| 53 |
|
|
| 9 |
|
|
| — |
|
|
| 44 |
|
| $ | 182 |
|
| $ | 2 |
|
| $ | 0 |
|
| $ | 180 |
|
| $ | 83 |
|
| $ | 5 |
|
| $ | 0 |
|
| $ | 78 |
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 4 |
|
|
| 4 |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
|
| 4 |
|
|
| 4 |
|
|
| 0 |
|
|
| 0 |
|
|
| 3 |
|
|
| 3 |
|
|
| 0 |
|
|
| 0 |
|
Total |
| $ | 116 |
|
| $ | 39 |
|
| $ | — |
|
| $ | 77 |
|
| $ | 153 |
|
| $ | 67 |
|
| $ | 27 |
|
| $ | 59 |
| ||||||||||||||||||||||||||||||||
Total derivatives, subject to a master netting or similar arrangement |
| $ | 186 |
|
| $ | 6 |
|
| $ | 0 |
|
| $ | 180 |
|
| $ | 86 |
|
| $ | 8 |
|
| $ | 0 |
|
| $ | 78 |
| ||||||||||||||||||||||||||||||||
Volumes
The following table presents the volume of DominionEastern Energy’s derivative activity at September 30, 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.2020.
|
| Current |
|
| Noncurrent |
| ||
Natural Gas (bcf): |
|
|
|
|
|
|
|
|
Fixed price(1) |
|
| 62 |
|
|
| 17 |
|
Basis |
|
| 165 |
|
|
| 612 |
|
Electricity (MWh): |
|
|
|
|
|
|
|
|
Fixed price |
|
| 6,749,288 |
|
|
| 902,069 |
|
FTRs |
|
| 72,126,361 |
|
|
| — |
|
Liquids (Gal)(2) |
|
| 36,940,288 |
|
|
| — |
|
Interest rate(3) |
| $ | 1,100,000,000 |
|
| $ | 5,049,890,127 |
|
Foreign currency(3)(4) |
| $ | — |
|
| $ | 280,000,000 |
|
|
| Current |
|
| Noncurrent |
| ||
Interest rate(1) |
| $ | 1,300,000,000 |
|
| $ | 0 |
|
Foreign currency(1) |
| € | 0 |
|
| € | 250,000,000 |
|
(1) |
|
|
|
| Maturity is determined based on final settlement period. |
|
|
For the three and nine months ended September 30, 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 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 Energy’s Consolidated Balance Sheet at September 30, 2017:
|
| AOCI After-Tax |
|
| Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |
|
| Maximum Term | ||
(millions) |
|
|
|
|
|
|
|
|
|
|
Commodities: |
|
|
|
|
|
|
|
|
|
|
Gas |
| $ | (1 | ) |
| $ | (1 | ) |
| 37 months |
Electricity |
|
| 7 |
|
|
| 7 |
|
| 15 months |
Other |
|
| (4 | ) |
|
| (4 | ) |
| 6 months |
Interest rate |
|
| (260 | ) |
|
| (11 | ) |
| 387 months |
Foreign currency |
|
| 4 |
|
|
| (2 | ) |
| 105 months |
Total |
| $ | (254 | ) |
| $ | (11 | ) |
|
|
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 Energy’s derivatives and where they are presented in its Consolidated Balance Sheets:
|
| Fair Value – Derivatives under Hedge Accounting |
|
| Fair Value – Derivatives not under Hedge Accounting |
|
| Total Fair Value |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 19 |
|
| $ | 83 |
|
| $ | 102 |
|
Interest rate |
|
| 9 |
|
|
| — |
|
|
| 9 |
|
Total current derivative assets(1) |
|
| 28 |
|
|
| 83 |
|
|
| 111 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 1 |
|
|
| 110 |
|
|
| 111 |
|
Interest rate |
|
| 2 |
|
|
| — |
|
|
| 2 |
|
Foreign currency |
|
| 25 |
|
|
| — |
|
|
| 25 |
|
Total noncurrent derivative assets(2) |
|
| 28 |
|
|
| 110 |
|
|
| 138 |
|
Total derivative assets |
| $ | 56 |
|
| $ | 193 |
|
| $ | 249 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 15 |
|
| $ | 25 |
|
| $ | 40 |
|
Interest rate |
|
| 21 |
|
|
| — |
|
|
| 21 |
|
Foreign currency |
|
| 4 |
|
|
| — |
|
|
| 4 |
|
Total current derivative liabilities(3) |
|
| 40 |
|
|
| 25 |
|
|
| 65 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| — |
|
|
| 2 |
|
|
| 2 |
|
Interest rate |
|
| 51 |
|
|
| — |
|
|
| 51 |
|
Total noncurrent derivative liabilities(4) |
|
| 51 |
|
|
| 2 |
|
|
| 53 |
|
Total derivative liabilities |
| $ | 91 |
|
| $ | 27 |
|
| $ | 118 |
|
December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 29 |
|
| $ | 101 |
|
| $ | 130 |
|
Interest rate |
|
| 10 |
|
|
| — |
|
|
| 10 |
|
Total current derivative assets(1) |
|
| 39 |
|
|
| 101 |
|
|
| 140 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| — |
|
|
| 132 |
|
|
| 132 |
|
Interest rate |
|
| 7 |
|
|
| — |
|
|
| 7 |
|
Total noncurrent derivative assets(2) |
|
| 7 |
|
|
| 132 |
|
|
| 139 |
|
Total derivative assets |
| $ | 46 |
|
| $ | 233 |
|
| $ | 279 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 51 |
|
| $ | 41 |
|
| $ | 92 |
|
Interest rate |
|
| 33 |
|
|
| — |
|
|
| 33 |
|
Foreign currency |
|
| 3 |
|
|
| — |
|
|
| 3 |
|
Total current derivative liabilities(3) |
|
| 87 |
|
|
| 41 |
|
|
| 128 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 1 |
|
|
| 3 |
|
|
| 4 |
|
Interest rate |
|
| 20 |
|
|
| — |
|
|
| 20 |
|
Foreign currency |
|
| 3 |
|
|
| — |
|
|
| 3 |
|
Total noncurrent derivative liabilities(4) |
|
| 24 |
|
|
| 3 |
|
|
| 27 |
|
Total derivative liabilities |
| $ | 111 |
|
| $ | 44 |
|
| $ | 155 |
|
|
|
|
|
|
|
|
|
The following tables present the gains and losses on Dominion Energy'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 |
| Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1) |
|
| Amount of Gain (Loss) Reclassified From AOCI to Income |
|
| Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2) |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
| $ | 32 |
|
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
|
|
|
| (1 | ) |
|
|
|
|
Total commodity |
| $ | 8 |
|
| $ | 31 |
|
| $ | — |
|
Interest rate(3) |
|
| (4 | ) |
|
| (16 | ) |
|
| (26 | ) |
Foreign currency(4) |
|
| 12 |
|
|
| 10 |
|
|
| — |
|
Total |
| $ | 16 |
|
| $ | 25 |
|
| $ | (26 | ) |
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
| $ | 64 |
|
|
|
|
|
Purchased gas |
|
|
|
|
|
| (1 | ) |
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
|
|
|
| (1 | ) |
|
|
|
|
Total commodity |
| $ | 7 |
|
| $ | 62 |
|
| $ | — |
|
Interest rate(3) |
|
| 3 |
|
|
| (10 | ) |
|
| (16 | ) |
Foreign currency(4) |
|
| 12 |
|
|
| 3 |
|
|
| — |
|
Total |
| $ | 22 |
|
| $ | 55 |
|
| $ | (16 | ) |
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
| $ | 114 |
|
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
|
|
|
| 1 |
|
|
|
|
|
Total commodity |
| $ | 139 |
|
| $ | 115 |
|
| $ | — |
|
Interest rate(3) |
|
| (18 | ) |
|
| (39 | ) |
|
| (60 | ) |
Foreign currency(4) |
|
| 10 |
|
|
| 15 |
|
|
| — |
|
Total |
| $ | 131 |
|
| $ | 91 |
|
| $ | (60 | ) |
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
| $ | 266 |
|
|
|
|
|
Purchased gas |
|
|
|
|
|
| (9 | ) |
|
|
|
|
Electric fuel and other energy-related purchases |
|
|
|
|
|
| (8 | ) |
|
|
|
|
Total commodity |
| $ | 193 |
|
| $ | 249 |
|
| $ | — |
|
Interest rate(3) |
|
| (107 | ) |
|
| (21 | ) |
|
| (258 | ) |
Foreign currency(4) |
|
| 4 |
|
|
| 1 |
|
|
| — |
|
Total |
| $ | 90 |
|
| $ | 229 |
|
| $ | (258 | ) |
|
|
|
|
|
|
|
|
|
| Amount of Gain (Loss) Recognized in Income on Derivatives(1) |
| |||||||||||||
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
Derivatives Not Designated as Hedging Instruments |
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 7 |
|
| $ | 25 |
|
| $ | 22 |
|
| $ | 19 |
|
Purchased gas |
|
| (6 | ) |
|
| (21 | ) |
|
| 2 |
|
|
| (14 | ) |
Electric fuel and other energy-related purchases |
|
| (19 | ) |
|
| (12 | ) |
|
| (51 | ) |
|
| (43 | ) |
Other operations and maintenance |
|
| 1 |
|
|
| — |
|
|
| (1 | ) |
|
| — |
|
Total |
| $ | (17 | ) |
| $ | (8 | ) |
| $ | (28 | ) |
| $ | (38 | ) |
|
|
Virginia Power
Balance Sheet Presentation
The tables below present Virginia Power's derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||||||||||
|
| Gross Amounts of Recognized Assets |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
| Gross Amounts of Recognized Assets |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 156 |
|
| $ | — |
|
| $ | 156 |
|
| $ | 147 |
|
| $ | — |
|
| $ | 147 |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
|
| — |
|
|
| 6 |
|
Total derivatives, subject to a master netting or similar arrangement |
|
| 156 |
|
|
| — |
|
|
| 156 |
|
|
| 153 |
|
|
| — |
|
|
| 153 |
|
Total derivatives, not subject to a master netting or similar arrangement |
|
| 12 |
|
|
| — |
|
|
| 12 |
|
|
| 41 |
|
|
| — |
|
|
| 41 |
|
Total |
| $ | 168 |
|
| $ | — |
|
| $ | 168 |
|
| $ | 194 |
|
| $ | — |
|
| $ | 194 |
|
|
|
|
|
|
| September 30, 2017 |
|
|
|
|
|
|
|
|
|
| December 31, 2016 |
|
|
|
|
| ||||||||||
|
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
| ||||||||||
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Received |
|
| Net Amounts |
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Received |
|
| Net Amounts |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 156 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 155 |
|
| $ | 147 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 145 |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
Total |
| $ | 156 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 155 |
|
| $ | 153 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 151 |
|
| September 30, 2017 |
|
| December 31, 2016 |
| |||||||||||||||||||
|
| Gross Amounts of Recognized Liabilities |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
| Gross Amounts of Recognized Liabilities |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 2 |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 55 |
|
|
| — |
|
|
| 55 |
|
|
| 21 |
|
|
| — |
|
|
| 21 |
|
Total derivatives, subject to a master netting or similar arrangement |
|
| 56 |
|
|
| — |
|
|
| 56 |
|
|
| 23 |
|
|
| — |
|
|
| 23 |
|
Total derivatives, not subject to a master netting or similar arrangement |
|
| 5 |
|
|
| — |
|
|
| 5 |
|
|
| 8 |
|
|
| — |
|
|
| 8 |
|
Total |
| $ | 61 |
|
| $ | — |
|
| $ | 61 |
|
| $ | 31 |
|
| $ | — |
|
| $ | 31 |
|
|
|
|
|
|
| September 30, 2017 |
|
|
|
|
|
|
|
|
|
| December 31, 2016 |
|
|
|
|
| ||||||||||
|
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
| ||||||||||
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Paid |
|
| Net Amounts |
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Paid |
|
| Net Amounts |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 1 |
|
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | 2 |
|
| $ | 2 |
|
| $ | — |
|
| $ | — |
|
Interest rate contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 55 |
|
|
| — |
|
|
| — |
|
|
| 55 |
|
|
| 21 |
|
|
| — |
|
|
| — |
|
|
| 21 |
|
Total |
| $ | 56 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 55 |
|
| $ | 23 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 21 |
|
Volumes
The following table presents the volume of Virginia Power’s derivative activity at September 30, 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.
|
| Current |
|
| Noncurrent |
| ||
Natural Gas (bcf): |
|
|
|
|
|
|
|
|
Fixed price(1) |
|
| 28 |
|
|
| 6 |
|
Basis |
|
| 85 |
|
|
| 562 |
|
Electricity (MWh): |
|
|
|
|
|
|
|
|
Fixed price(1) |
|
| 1,426,093 |
|
|
| 611,629 |
|
FTRs |
|
| 68,673,158 |
|
|
| — |
|
Interest rate(2) |
| $ | 300,000,000 |
|
| $ | 1,150,000,000 |
|
|
|
|
|
Ineffectiveness and AOCI
For the three and nine months ended September 30, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were not material.
The following table presents selected information related to losses on cash flow hedges included in AOCI in Virginia Power’sEastern Energy’s Consolidated Balance Sheet at September 30, 2017:2020:
|
| AOCI After-Tax |
|
| Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |
|
| Maximum Term |
| AOCI After-Tax |
|
| Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |
|
| Maximum Term | ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate |
| $ | (12 | ) |
| $ | (1 | ) |
| 387 months |
| $ | (49 | ) |
| $ | (9 | ) |
| 291 months |
Foreign currency |
|
| (8 | ) |
|
| (3 | ) |
| 69 months | ||||||||||
Total |
| $ | (12 | ) |
| $ | (1 | ) |
|
|
| $ | (57 | ) |
| $ | (12 | ) |
|
|
20
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.
In July 2020, Eastern Energy recorded a loss of $141 million ($105 million after-tax) in interest and related charges in the Consolidated Statements of Income, for cash flow hedges of debt-related items that are probable of not occurring as a result of the GT&S Transaction. The derivatives related to these hedges were settled in October 2020 for a cash payment of $165 million.
Fair Value and Gains and Losses on Derivative Instruments
The following table presentstables present the fair values of Virginia Power’sEastern Energy’s derivatives and where they are presented in its Consolidated Balance Sheets:
|
| Fair Value – Derivatives under Hedge Accounting |
|
| Fair Value – Derivatives not under Hedge Accounting |
|
| Total Fair Value |
|
| Fair Value- Derivatives Under Hedge Accounting |
|
| Fair Value-Derivatives Not Under Hedge Accounting |
|
| Total Fair Value |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
September 30, 2020 |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Commodity |
| $ | — |
|
| $ | 61 |
|
| $ | 61 |
| ||||||||||||
Total current derivative assets(1) |
|
| — |
|
|
| 61 |
|
|
| 61 |
| ||||||||||||
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| — |
|
|
| 107 |
|
|
| 107 |
| ||||||||||||
Total noncurrent derivative assets(2) |
|
| — |
|
|
| 107 |
|
|
| 107 |
| ||||||||||||
Foreign currency |
| $ | 6 |
|
| $ | 0 |
|
| $ | 6 |
| ||||||||||||
Total noncurrent derivative assets(1) |
|
| 6 |
|
|
| 0 |
|
|
| 6 |
| ||||||||||||
Total derivative assets |
| $ | — |
|
| $ | 168 |
|
| $ | 168 |
|
| $ | 6 |
|
| $ | 0 |
|
| $ | 6 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 6 |
|
| $ | 6 |
| ||||||||||||
Interest rate |
|
| 17 |
|
|
| — |
|
|
| 17 |
|
| $ | 0 |
|
| $ | 182 |
|
| $ | 182 |
|
Total current derivative liabilities(3) |
|
| 17 |
|
|
| 6 |
|
|
| 23 |
| ||||||||||||
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Interest rate |
|
| 38 |
|
|
| — |
|
|
| 38 |
| ||||||||||||
Total noncurrent derivatives liabilities (4) |
|
| 38 |
|
|
| — |
|
|
| 38 |
| ||||||||||||
Foreign currency |
|
| 4 |
|
|
| 0 |
|
|
| 4 |
| ||||||||||||
Total current derivative liabilities |
|
| 4 |
|
|
| 182 |
|
|
| 186 |
| ||||||||||||
Total derivative liabilities |
| $ | 55 |
|
| $ | 6 |
|
| $ | 61 |
|
| $ | 4 |
|
| $ | 182 |
|
| $ | 186 |
|
December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
December 31, 2019 |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Commodity |
| $ | — |
|
| $ | 60 |
|
| $ | 60 |
| ||||||||||||
Interest rate |
|
| 6 |
|
|
| — |
|
|
| 6 |
| ||||||||||||
Total current derivative assets(1) |
|
| 6 |
|
|
| 60 |
|
|
| 66 |
| ||||||||||||
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| — |
|
|
| 128 |
|
|
| 128 |
| ||||||||||||
Total noncurrent derivative assets(2) |
|
| — |
|
|
| 128 |
|
|
| 128 |
| ||||||||||||
Foreign currency |
| $ | 8 |
|
| $ | 0 |
|
| $ | 8 |
| ||||||||||||
Total noncurrent derivative assets(1) |
|
| 8 |
|
|
| 0 |
|
|
| 8 |
| ||||||||||||
Total derivative assets |
| $ | 6 |
|
| $ | 188 |
|
| $ | 194 |
|
| $ | 8 |
|
| $ | 0 |
|
| $ | 8 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 10 |
|
| $ | 10 |
| ||||||||||||
Interest rate |
|
| 8 |
|
|
| — |
|
|
| 8 |
|
| $ | 30 |
|
| $ | 0 |
|
| $ | 30 |
|
Total current derivative liabilities(3) |
|
| 8 |
|
|
| 10 |
|
|
| 18 |
| ||||||||||||
Foreign currency |
|
| 3 |
|
|
| 0 |
|
|
| 3 |
| ||||||||||||
Total current derivative liabilities |
|
| 33 |
|
|
| 0 |
|
|
| 33 |
| ||||||||||||
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate |
|
| 13 |
|
|
| — |
|
|
| 13 |
|
|
| 53 |
|
|
| 0 |
|
|
| 53 |
|
Total noncurrent derivative liabilities(4) |
|
| 13 |
|
|
| — |
|
|
| 13 |
| ||||||||||||
Total noncurrent derivative liabilities(2) |
|
| 53 |
|
|
| 0 |
|
|
| 53 |
| ||||||||||||
Total derivative liabilities |
| $ | 21 |
|
| $ | 10 |
|
| $ | 31 |
|
| $ | 86 |
|
| $ | 0 |
|
| $ | 86 |
|
(1) |
|
| Noncurrent |
|
|
| Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in |
21
The following tables presenttable presents the gains and losses on Virginia Power'sEastern Energy’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 |
| Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1) |
|
| Amount of Gain (Loss) Reclassified From AOCI to Income |
|
| Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2) |
| |||||||||||
Derivatives in cash flow hedging relationships |
| Amount of Gain (Loss) Recognized in AOCI on Derivatives(1) |
|
| Amount of Gain (Loss) Reclassified From AOCI to Income |
| ||||||||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Three Months Ended September 30, 2020 |
|
|
|
|
|
|
|
| ||||||||||||
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate(3) |
| $ | (3 | ) |
| $ | — |
|
| $ | (26 | ) | ||||||||
Interest rate(2) |
| $ | 1 |
|
| $ | (145 | ) | ||||||||||||
Foreign currency(3) |
|
| 14 |
|
|
| 12 |
| ||||||||||||
Total |
| $ | (3 | ) |
| $ | — |
|
| $ | (26 | ) |
| $ | 15 |
|
| $ | (133 | ) |
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Three Months Ended September 30, 2019 |
|
|
|
|
|
|
|
| ||||||||||||
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate(3) |
| $ | (2 | ) |
| $ | — |
|
| $ | (16 | ) | ||||||||
Commodity: |
|
|
|
|
|
|
|
| ||||||||||||
Net income from discontinued operations |
|
|
|
|
| $ | 2 |
| ||||||||||||
Total commodity |
| $ | 1 |
|
| $ | 2 |
| ||||||||||||
Interest rate(2) |
|
| (36 | ) |
|
| (2 | ) | ||||||||||||
Foreign currency(3) |
|
| (14 | ) |
|
| (12 | ) | ||||||||||||
Total |
| $ | (2 | ) |
| $ | — |
|
| $ | (16 | ) |
| $ | (49 | ) |
| $ | (12 | ) |
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Nine Months Ended September 30, 2020 |
|
|
|
|
|
|
|
| ||||||||||||
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate(3) |
| $ | (8 | ) |
| $ | (1 | ) |
| $ | (60 | ) | ||||||||
Interest rate(2) |
| $ | (104 | ) |
| $ | (151 | ) | ||||||||||||
Foreign currency(3) |
|
| (3 | ) |
|
| 12 |
| ||||||||||||
Total |
| $ | (8 | ) |
| $ | (1 | ) |
| $ | (60 | ) |
| $ | (107 | ) |
| $ | (139 | ) |
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Nine Months Ended September 30, 2019 |
|
|
|
|
|
|
|
| ||||||||||||
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate(3) |
| $ | (26 | ) |
| $ | (1 | ) |
| $ | (258 | ) | ||||||||
Commodity: |
|
|
|
|
|
|
|
| ||||||||||||
Net income from discontinued operations |
|
|
|
|
| $ | 4 |
| ||||||||||||
Total commodity |
| $ | 3 |
|
| $ | 4 |
| ||||||||||||
Interest rate(2) |
|
| (96 | ) |
|
| (3 | ) | ||||||||||||
Foreign currency(3) |
|
| (24 | ) |
|
| (14 | ) | ||||||||||||
Total |
| $ | (26 | ) |
| $ | (1 | ) |
| $ | (258 | ) |
| $ | (117 | ) |
| $ | (13 | ) |
(1) | Amounts deferred into AOCI have no associated effect in |
(2) |
|
| Amounts recorded in |
|
| Amount of Gain (Loss) Recognized in Income on Derivatives(1) |
| |||||||||||||
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
Derivatives Not Designated as Hedging Instruments |
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity(2) |
| $ | (18 | ) |
| $ | (10 | ) |
| $ | (42 | ) |
| $ | (40 | ) |
Total |
| $ | (18 | ) |
| $ | (10 | ) |
| $ | (42 | ) |
| $ | (40 | ) |
|
|
|
|
Balance Sheet Presentation
The tables below present Dominion Energy Gas' derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting.
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||||||||||
|
| Gross Amounts of Recognized Assets |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
| Gross Amounts of Recognized Assets |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 25 |
|
|
| — |
|
|
| 25 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total derivatives, subject to a master netting or similar arrangement |
|
| 26 |
|
|
| — |
|
|
| 26 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total |
| $ | 26 |
|
| $ | — |
|
| $ | 26 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
|
|
|
|
| September 30, 2017 |
|
|
|
|
|
|
|
|
|
| December 31, 2016 |
|
|
|
|
| |||||||||||
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
| |||||||||||
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Received |
|
| Net Amounts |
|
| Net Amounts of Assets Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Received |
|
| Net Amounts |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 25 |
|
|
| 4 |
|
|
| — |
|
|
| 21 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total |
| $ | 26 |
|
| $ | 4 |
|
| $ | — |
|
| $ | 22 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||||||||||
|
| Gross Amounts of Recognized Liabilities |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
| Gross Amounts of Recognized Liabilities |
|
| Gross Amounts Offset in the Consolidated Balance Sheet |
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 6 |
|
| $ | — |
|
| $ | 6 |
|
| $ | 5 |
|
| $ | — |
|
| $ | 5 |
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 4 |
|
|
| — |
|
|
| 4 |
|
|
| 6 |
|
|
| — |
|
|
| 6 |
|
Total derivatives, subject to a master netting or similar arrangement |
|
| 10 |
|
|
| — |
|
|
| 10 |
|
|
| 11 |
|
|
| — |
|
|
| 11 |
|
Total |
| $ | 10 |
|
| $ | — |
|
| $ | 10 |
|
| $ | 11 |
|
| $ | — |
|
| $ | 11 |
|
|
|
|
|
| September 30, 2017 |
|
|
|
|
|
|
|
| December 31, 2016 |
|
|
| |||||||||||||||
|
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
|
|
|
|
|
| Gross Amounts Not Offset in the Consolidated Balance Sheet |
|
|
|
|
| ||||||||||
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Paid |
|
| Net Amounts |
|
| Net Amounts of Liabilities Presented in the Consolidated Balance Sheet |
|
| Financial Instruments |
|
| Cash Collateral Paid |
|
| Net Amounts |
| ||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
| $ | 6 |
|
| $ | — |
|
| $ | — |
|
| $ | 6 |
|
| $ | 5 |
|
| $ | — |
|
| $ | — |
|
| $ | 5 |
|
Foreign currency contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Over-the-counter |
|
| 4 |
|
|
| 4 |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
Total |
| $ | 10 |
|
| $ | 4 |
|
| $ | — |
|
| $ | 6 |
|
| $ | 11 |
|
| $ | — |
|
| $ | — |
|
| $ | 11 |
|
Volumes
The following table presents the volume of Dominion Energy Gas' derivative activity at September 30, 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.
|
| Current |
|
| Noncurrent |
| ||
Natural Gas (bcf): |
|
|
|
|
|
|
|
|
Fixed price |
|
| 2 |
|
|
| — |
|
Basis |
|
| 2 |
|
|
| — |
|
NGLs (Gal) |
|
| 30,514,288 |
|
|
| — |
|
Foreign currency(1) |
| $ | — |
|
| $ | 280,000,000 |
|
|
|
Ineffectiveness and AOCI
For the three and nine months ended September 30, 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 Dominion Energy Gas' Consolidated Balance Sheet at September 30, 2017:
|
| AOCI After-Tax |
|
| Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax |
|
| Maximum Term | ||
(millions) |
|
|
|
|
|
|
|
|
|
|
Commodities: |
|
|
|
|
|
|
|
|
|
|
NGLs |
| $ | (4 | ) |
| $ | (4 | ) |
| 6 months |
Interest rate |
|
| (26 | ) |
|
| (3 | ) |
| 327 months |
Foreign currency |
|
| 4 |
|
|
| (2 | ) |
| 105 months |
Total |
| $ | (26 | ) |
| $ | (9 | ) |
|
|
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 tables present the fair values of Dominion Energy Gas' derivatives and where they are presented in its Consolidated Balance Sheets:
|
| Fair Value-Derivatives Under Hedge Accounting |
|
| Fair Value-Derivatives Not Under Hedge Accounting |
|
| Total Fair Value |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | — |
|
| $ | 1 |
|
| $ | 1 |
|
Total current derivative assets(1) |
|
| — |
|
|
| 1 |
|
|
| 1 |
|
Noncurrent Assets |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency |
|
| 25 |
|
|
| — |
|
|
| 25 |
|
Total noncurrent derivative assets(2) |
|
| 25 |
|
|
| — |
|
|
| 25 |
|
Total derivative assets |
| $ | 25 |
|
| $ | 1 |
|
| $ | 26 |
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 6 |
|
| $ | — |
|
| $ | 6 |
|
Foreign currency |
|
| 4 |
|
|
| — |
|
|
| 4 |
|
Total current derivative liabilities(3) |
|
| 10 |
|
|
| — |
|
|
| 10 |
|
Total derivative liabilities |
| $ | 10 |
|
| $ | — |
|
| $ | 10 |
|
December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
| $ | 4 |
|
| $ | — |
|
| $ | 4 |
|
Foreign currency |
|
| 3 |
|
|
| — |
|
|
| 3 |
|
Total current derivative liabilities(3) |
|
| 7 |
|
|
| — |
|
|
| 7 |
|
Noncurrent Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Foreign currency |
|
| 3 |
|
|
| — |
|
|
| 3 |
|
Total noncurrent derivative liabilities(4) |
|
| 4 |
|
|
| — |
|
|
| 4 |
|
Total derivative liabilities |
| $ | 11 |
|
| $ | — |
|
| $ | 11 |
|
|
|
|
|
|
|
|
|
The following table presents the gains and losses on Dominion Energy Gas' derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:
Derivatives in Cash Flow Hedging Relationships |
| Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1) |
|
| Amount of Gain (Loss) Reclassified From AOCI to Income |
| ||
(millions) |
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses): |
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
| $ | (2 | ) |
Total commodity |
| $ | (10 | ) |
| $ | (2 | ) |
Interest rate(2) |
|
| — |
|
|
| (1 | ) |
Foreign currency(3) |
|
| 12 |
|
|
| 10 |
|
Total |
| $ | 2 |
|
| $ | 7 |
|
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses): |
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
| $ | 1 |
|
Total commodity |
| $ | — |
|
| $ | 1 |
|
Interest rate(2) |
|
| — |
|
|
| (1 | ) |
Foreign currency(3) |
|
| 12 |
|
|
| 3 |
|
Total |
| $ | 12 |
|
| $ | 3 |
|
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses): |
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
| $ | (4 | ) |
Total commodity |
| $ | (5 | ) |
| $ | (4 | ) |
Interest rate(2) |
|
| — |
|
|
| (3 | ) |
Foreign currency(3) |
|
| 10 |
|
|
| 15 |
|
Total |
| $ | 5 |
|
| $ | 8 |
|
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
Derivative Type and Location of Gains (Losses): |
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
Operating revenue |
|
|
|
|
| $ | 6 |
|
Total commodity |
| $ | (7 | ) |
| $ | 6 |
|
Interest rate(2) |
|
| (8 | ) |
|
| (2 | ) |
Foreign currency(3) |
|
| 4 |
|
|
| 1 |
|
Total |
| $ | (11 | ) |
| $ | 5 |
|
|
|
|
|
(3) | Amounts recorded in |
Derivatives not designated as hedging instruments |
| Amount of Gain (Loss) Recognized in Income on Derivatives |
| |||||||||||||||||||||||||||||
|
| Amount of Gain (Loss) Recognized in Income on Derivatives |
|
| Three Months Ended |
|
| Nine Months Ended |
| |||||||||||||||||||||||
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
| September 30, |
|
| September 30, |
| ||||||||||||||||||||
Derivatives Not Designated as Hedging Instruments |
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||||||||||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||||||||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative type and location of gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Operating revenue |
| $ | — |
|
| $ | 5 |
|
| $ | — |
|
| $ | 3 |
| ||||||||||||||||
Interest rate(1) |
| $ | 5 |
|
| $ | 0 |
|
| $ | (3 | ) |
| $ | 0 |
| ||||||||||||||||
Total |
| $ | — |
|
| $ | 5 |
|
| $ | — |
|
| $ | 3 |
|
| $ | 5 |
|
| $ | 0 |
|
| $ | (3 | ) |
| $ | 0 |
|
Dominion Energy
Equity and Debt Securities
Rabbi Trust Securities
Marketable equity and debt securities and cash equivalents held in Dominion Energy’s rabbi trusts and classified as trading totaled $109 million and $104 million at September 30, 2017 and December 31, 2016, respectively.
Decommissioning Trust Securities
Dominion Energy holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion Energy’s decommissioning trust funds are summarized below:
|
| Amortized Cost |
|
| Total Unrealized Gains(1) |
|
| Total Unrealized Losses(1) |
|
|
| Fair Value |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 1,562 |
|
| $ | 1,664 |
|
| $ | — |
|
|
| $ | 3,226 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| 438 |
|
|
| 15 |
|
|
| (1 | ) |
|
|
| 452 |
|
Government securities |
|
| 1,041 |
|
|
| 28 |
|
|
| (4 | ) |
|
|
| 1,065 |
|
Common/collective trust funds |
|
| 66 |
|
|
| — |
|
|
| — |
|
|
|
| 66 |
|
Cost method investments |
|
| 67 |
|
|
| — |
|
|
| — |
|
|
|
| 67 |
|
Cash equivalents and other(2) |
|
| 5 |
|
|
| — |
|
|
| — |
|
|
|
| 5 |
|
Total |
| $ | 3,179 |
|
| $ | 1,707 |
|
| $ | (5 | ) | (3) |
| $ | 4,881 |
|
December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 1,449 |
|
| $ | 1,408 |
|
| $ | — |
|
|
| $ | 2,857 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| 478 |
|
|
| 13 |
|
|
| (4 | ) |
|
|
| 487 |
|
Government securities |
|
| 978 |
|
|
| 22 |
|
|
| (8 | ) |
|
|
| 992 |
|
Common/collective trust funds |
|
| 67 |
|
|
| — |
|
|
| — |
|
|
|
| 67 |
|
Cost method investments |
|
| 69 |
|
|
| — |
|
|
| — |
|
|
|
| 69 |
|
Cash equivalents and other(2) |
|
| 12 |
|
|
| — |
|
|
| — |
|
|
|
| 12 |
|
Total |
| $ | 3,053 |
|
| $ | 1,443 |
|
| $ | (12 | ) | (3) |
| $ | 4,484 |
|
(1) |
|
|
|
|
|
The fair value of Dominion Energy’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2017 by contractual maturity is as follows:
|
| Amount |
| |
(millions) |
|
|
|
|
Due in one year or less |
| $ | 183 |
|
Due after one year through five years |
|
| 410 |
|
Due after five years through ten years |
|
| 366 |
|
Due after ten years |
|
| 624 |
|
Total |
| $ | 1,583 |
|
Presented below is selected information regarding Dominion Energy’s marketable equity and debt securities held in nuclear decommissioning trust funds.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales |
| $ | 377 |
|
| $ | 300 |
|
| $ | 1,496 |
|
| $ | 1,009 |
|
Realized gains(1) |
|
| 25 |
|
|
| 40 |
|
|
| 142 |
|
|
| 102 |
|
Realized losses(1) |
|
| 16 |
|
|
| 9 |
|
|
| 52 |
|
|
| 43 |
|
|
|
Dominion Energy recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other-than-temporary impairment losses(1) |
| $ | 7 |
|
| $ | 9 |
|
| $ | 33 |
|
| $ | 34 |
|
Losses recorded to the nuclear decommissioning trust regulatory liability |
|
| (2 | ) |
|
| (4 | ) |
|
| (13 | ) |
|
| (15 | ) |
Losses recognized in other comprehensive income (before taxes) |
|
| (1 | ) |
|
| — |
|
|
| (2 | ) |
|
| (1 | ) |
Net impairment losses recognized in earnings |
| $ | 4 |
|
| $ | 5 |
|
| $ | 18 |
|
| $ | 18 |
|
|
|
Virginia Power
Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below:
|
| Amortized Cost |
|
| Total Unrealized Gains(1) |
|
| Total Unrealized Losses(1) |
|
|
| Fair Value |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 729 |
|
| $ | 741 |
|
| $ | — |
|
|
| $ | 1,470 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| 226 |
|
|
| 8 |
|
|
| — |
|
|
|
| 234 |
|
Government securities |
|
| 483 |
|
|
| 13 |
|
|
| (2 | ) |
|
|
| 494 |
|
Common/collective trust funds |
|
| 29 |
|
|
| — |
|
|
| — |
|
|
|
| 29 |
|
Cost method investments |
|
| 67 |
|
|
| — |
|
|
| — |
|
|
|
| 67 |
|
Cash equivalents and other(2) |
|
| (2 | ) |
|
| — |
|
|
| — |
|
|
|
| (2 | ) |
Total |
| $ | 1,532 |
|
| $ | 762 |
|
| $ | (2 | ) | (3) |
| $ | 2,292 |
|
December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable equity securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 677 |
|
| $ | 624 |
|
| $ | — |
|
|
| $ | 1,301 |
|
Fixed income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate debt instruments |
|
| 274 |
|
|
| 6 |
|
|
| (4 | ) |
|
|
| 276 |
|
Government securities |
|
| 420 |
|
|
| 9 |
|
|
| (2 | ) |
|
|
| 427 |
|
Common/collective trust funds |
|
| 26 |
|
|
| — |
|
|
| — |
|
|
|
| 26 |
|
Cost method investments |
|
| 69 |
|
|
| — |
|
|
| — |
|
|
|
| 69 |
|
Cash equivalents and other(2) |
|
| 7 |
|
|
| — |
|
|
| — |
|
|
|
| 7 |
|
Total |
| $ | 1,473 |
|
| $ | 639 |
|
| $ | (6 | ) | (3) |
| $ | 2,106 |
|
|
|
|
|
|
|
The fair value of Virginia Power’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2017 by contractual maturity is as follows:
|
| Amount |
| |
(millions) |
|
|
|
|
Due in one year or less |
| $ | 60 |
|
Due after one year through five years |
|
| 192 |
|
Due after five years through ten years |
|
| 189 |
|
Due after ten years |
|
| 316 |
|
Total |
| $ | 757 |
|
Presented below is selected information regarding Virginia Power’s marketable equity and debt securities held in nuclear decommissioning trust funds.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales |
| $ | 156 |
|
| $ | 131 |
|
| $ | 654 |
|
| $ | 478 |
|
Realized gains(1) |
|
| 9 |
|
|
| 18 |
|
|
| 64 |
|
|
| 48 |
|
Realized losses(1) |
|
| 6 |
|
|
| 4 |
|
|
| 24 |
|
|
| 21 |
|
|
|
Other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds recognized in earnings for Virginia Power were not material for the three and nine months ended September 30, 2017 and 2016.
Note 9. Equity Method Investments
Dominion EnergyIroquois and White River Hub
Atlantic Coast Pipeline
In October 2016, Dominion Energy purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million, which adjusted DominionEastern Energy’s and Duke’s membership interest to 48% and 47%, respectively.
Dominion Energy contributed $84 million and $286 million during the three and nine months ended September 30, 2017 and $74 million and $143 million during the three and nine months ended September 30, 2016, respectively, to Atlantic Coast Pipeline.
Dominion Energy Gas
Iroquois
Dominion Energy Gas' equity earnings totaled $15 million and $14 million for the nine months ended September 30, 2017 and 2016, respectively. Dominion Energy Gas received distributions from this investment of $17$30 million for both the nine months ended September 30, 20172020 and 2016.2019. Eastern Energy recorded contributions of $4 million for the nine months ended September 30, 2019. Eastern Energy received distributions of $63 million and $60 million for the nine months ended September 30, 2020 and 2019, respectively. At September 30, 20172020 and December 31, 2016,2019, the carrying amount of Dominion Energy Gas'Eastern Energy’s investment of $96$279 million and $98$312 million, respectively, exceeded its share of underlying equity in net assets by $8$146 million. The difference reflects equity method goodwill and is not being amortized. In May 2016, Dominion Energy Gas sold 0.65% of the non-controlling partnership interest in Iroquois to TransCanada Corporation for approximately $7 million, which resulted in a $5 million ($3 million after-tax) gain, included in other income in Dominion Energy Gas’ Consolidated Statement of Income.
Note 11.10. Regulatory Assets and Liabilities
Regulatory assets and liabilities include the following:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
|
|
|
|
|
|
Regulatory assets: |
|
|
|
|
|
|
|
|
Deferred rate adjustment clause costs(1) |
| $ | 67 |
|
| $ | 63 |
|
Deferred nuclear refueling outage costs(2) |
|
| 67 |
|
|
| 71 |
|
Unrecovered gas costs(3) |
|
| 51 |
|
|
| 19 |
|
Deferred cost of fuel used in electric generation(4) |
|
| 30 |
|
|
| — |
|
Other |
|
| 96 |
|
|
| 91 |
|
Regulatory assets-current |
|
| 311 |
|
|
| 244 |
|
Unrecognized pension and other postretirement benefit costs(5) |
|
| 1,296 |
|
|
| 1,401 |
|
Deferred rate adjustment clause costs(1) |
|
| 333 |
|
|
| 329 |
|
Derivatives(6) |
|
| 230 |
|
|
| 174 |
|
PJM transmission rates(7) |
|
| 215 |
|
|
| 192 |
|
Income taxes recoverable through future rates(8) |
|
| 157 |
|
|
| 123 |
|
Utility reform legislation(9) |
|
| 134 |
|
|
| 99 |
|
Other |
|
| 138 |
|
|
| 155 |
|
Regulatory assets-noncurrent |
|
| 2,503 |
|
|
| 2,473 |
|
Total regulatory assets |
| $ | 2,814 |
|
| $ | 2,717 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
PIPP(10) |
| $ | 20 |
|
| $ | 28 |
|
Deferred cost of fuel used in electric generation(4) |
|
| 5 |
|
|
| 61 |
|
Other |
|
| 63 |
|
|
| 74 |
|
Regulatory liabilities-current |
|
| 88 |
|
|
| 163 |
|
Provision for future cost of removal and AROs(11) |
|
| 1,477 |
|
|
| 1,427 |
|
Nuclear decommissioning trust(12) |
|
| 1,034 |
|
|
| 902 |
|
Unrecognized pension and other postretirement benefit costs(5) |
|
| 106 |
|
|
| 105 |
|
Derivatives(6) |
|
| 78 |
|
|
| 69 |
|
Other |
|
| 211 |
|
|
| 119 |
|
Regulatory liabilities-noncurrent |
|
| 2,906 |
|
|
| 2,622 |
|
Total regulatory liabilities |
| $ | 2,994 |
|
| $ | 2,785 |
|
Virginia Power |
|
|
|
|
|
|
|
|
Regulatory assets: |
|
|
|
|
|
|
|
|
Deferred nuclear refueling outage costs(2) |
| $ | 67 |
|
| $ | 71 |
|
Deferred rate adjustment clause costs(1) |
|
| 47 |
|
|
| 51 |
|
Deferred cost of fuel used in electric generation(4) |
|
| 30 |
|
|
| — |
|
Other |
|
| 62 |
|
|
| 57 |
|
Regulatory assets-current(13) |
|
| 206 |
|
|
| 179 |
|
Deferred rate adjustment clause costs(1) |
|
| 256 |
|
|
| 246 |
|
PJM transmission rates(7) |
|
| 215 |
|
|
| 192 |
|
Derivatives(6) |
|
| 197 |
|
|
| 133 |
|
Income taxes recoverable through future rates(8) |
|
| 67 |
|
|
| 76 |
|
Other |
|
| 103 |
|
|
| 123 |
|
Regulatory assets-noncurrent |
|
| 838 |
|
|
| 770 |
|
Total regulatory assets |
| $ | 1,044 |
|
| $ | 949 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
Deferred cost of fuel used in electric generation(4) |
| $ | 5 |
|
| $ | 61 |
|
Other |
|
| 38 |
|
|
| 54 |
|
Regulatory liabilities-current(14) |
|
| 43 |
|
|
| 115 |
|
Nuclear decommissioning trust(12) |
|
| 1,034 |
|
|
| 902 |
|
Provision for future cost of removal(11) |
|
| 985 |
|
|
| 946 |
|
Derivatives(6) |
|
| 78 |
|
|
| 69 |
|
|
| September 30, 2020 |
|
| December 31, 2019 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Regulatory assets: |
|
|
|
|
|
|
|
|
Unrecovered gas costs(1) |
| $ | 2 |
|
| $ | 2 |
|
Other |
|
| 6 |
|
|
| 6 |
|
Regulatory assets-current(2) |
|
| 8 |
|
|
| 8 |
|
Interest rate hedges(3) |
|
| 31 |
|
|
| 32 |
|
Other |
|
| 8 |
|
|
| 8 |
|
Regulatory assets-noncurrent(4) |
|
| 39 |
|
|
| 40 |
|
Total regulatory assets |
| $ | 47 |
|
| $ | 48 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
Provision for future cost of removal and AROs(5) |
| $ | 18 |
|
| $ | 18 |
|
Overrecovered gas costs(1) |
|
| 5 |
|
|
| 8 |
|
Other |
|
| 15 |
|
|
| 15 |
|
Regulatory liabilities-current(6) |
|
| 38 |
|
|
| 41 |
|
Income taxes refundable through future rates(7) |
|
| 563 |
|
|
| 560 |
|
Provision for future cost of removal and AROs(5) |
|
| 90 |
|
|
| 95 |
|
Overrecovered other postretirement benefit costs(8) |
|
| 160 |
|
|
| 133 |
|
Other |
|
| 10 |
|
|
| 12 |
|
Regulatory liabilities-noncurrent(9) |
|
| 823 |
|
|
| 800 |
|
Total regulatory liabilities |
| $ | 861 |
|
| $ | 841 |
|
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
(millions) |
|
|
|
|
|
|
|
|
|
| 105 |
|
|
| 45 |
| |
Regulatory liabilities-noncurrent |
|
| 2,202 |
|
|
| 1,962 |
|
Total regulatory liabilities |
| $ | 2,245 |
|
| $ | 2,077 |
|
Dominion Energy Gas |
|
|
|
|
|
|
|
|
Regulatory assets: |
|
|
|
|
|
|
|
|
Deferred rate adjustment clause costs(1) |
| $ | 20 |
|
| $ | 12 |
|
Unrecovered gas costs(3) |
|
| — |
|
|
| 12 |
|
Other |
|
| 2 |
|
|
| 2 |
|
Regulatory assets-current(13) |
|
| 22 |
|
|
| 26 |
|
Unrecognized pension and other postretirement benefit costs(5) |
|
| 300 |
|
|
| 358 |
|
Utility reform legislation(9) |
|
| 134 |
|
|
| 99 |
|
Deferred rate adjustment clause costs(1) |
|
| 77 |
|
|
| 79 |
|
Income taxes recoverable through future rates(8) |
|
| 32 |
|
|
| 23 |
|
Other |
|
| 13 |
|
|
| 18 |
|
Regulatory assets-noncurrent(15) |
|
| 556 |
|
|
| 577 |
|
Total regulatory assets |
| $ | 578 |
|
| $ | 603 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
PIPP(10) |
| $ | 20 |
|
| $ | 28 |
|
Other |
|
| 19 |
|
|
| 7 |
|
Regulatory liabilities-current(14) |
|
| 39 |
|
|
| 35 |
|
Provision for future cost of removal and AROs(11) |
|
| 178 |
|
|
| 174 |
|
Other |
|
| 74 |
|
|
| 45 |
|
Regulatory liabilities-noncurrent(16) |
|
| 252 |
|
|
| 219 |
|
Total regulatory liabilities |
| $ | 291 |
|
| $ | 254 |
|
(1) |
|
|
|
| Reflects unrecovered or overrecovered gas costs at regulated gas operations, which are recovered or refunded through filings with |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Rates charged to customers by |
|
|
|
|
| Current regulatory liabilities are presented in other current liabilities in |
| Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred. |
(9) | Noncurrent regulatory liabilities are presented in other deferred credits and other liabilities in |
At September 30, 2017, $323 million of Dominion Energy's and $242 million of Virginia Power's2020, Eastern Energy’s regulatory assets represented past expendituresinclude $45 million, on which they doit does not currentlyexpect to earn a return.return during the applicable recovery period. With the exception of the $215 million PJM transmission cost allocation matter,certain items discussed above, the majority of these expenditures are expected to be recovered within the next two years.
Note 12.11. Regulatory Matters
Regulatory Matters Involving Potential Loss Contingencies
As a result of issues generated in the ordinary course of business, the Companies areEastern Energy is 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 CompaniesEastern Energy to estimate a range of possible loss. For regulatory matters for which the Companiesthat Eastern Energy 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 areEastern Energy is able to estimate a range of possible loss. For regulatory matters for which the Companies arethat Eastern Energy is 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’Eastern Energy’s 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’Eastern Energy’s financial position, liquidity or results of operations.
FERC - Electric23
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Dominion Energy’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, South Carolina and Utah, under Dominion Energy’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.
In October 2017, FERC issued an order determining the calculation of the incremental costs of undergrounding the transmission projects and affirming that the costs are to be recovered from the wholesale transmission customers with loads located in Virginia. FERC directed Virginia Power to rebill all wholesale transmission customers retroactively to March 2010 within 30 days of when the proceeding becomes final and no longer subject to rehearing. Parties have until November 2017 to seek rehearing. Virginia Power is evaluating the order, which is not expected to have a material effect on results of operations.
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 September 30, 2017, Virginia Power has recorded a contingent liability of $223 million in other deferred credits and other liabilities, which is offset by a $215 million regulatory asset for the amount that will be recovered through retail rates in Virginia.
FERC – Gas
DETI
In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations thatrecommendations. In November 2017, the FERC audit staff issued its audit report which could have the potential to result in adjustments which could be material to Dominion Energy and Dominion Energy Gas’Eastern Energy’s results of operations. In December 2017, DETI submittedprovided its initial response to the audit staff in September 2017. In connectionreport. DETI reached resolution of certain matters with one preliminary recommendation that management did not challenge, DETI recognizedFERC in the secondfourth quarter of 2017, a charge of $15 million ($9 million after-tax) recorded within other operations and maintenance expense in Dominion Energy’s and Dominion Energy Gas’ Consolidated Statements of Income to write-off the balance of a regulatory asset, originally established in 2008, that is no longer considered probable of recovery.2018. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the other preliminary recommendationsremaining finding and no amounts have been recognized.
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’Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016 and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017.
Virginia Regulation
Regulation Act Legislation
The Supreme Court of Virginia previously granted appeals to certain industrial customers of Appalachian Power Company that challenged the constitutionality of legislation enacted in 2015 keeping Appalachian Power Company’s base rates unchanged until at least 2020. This legislation also keeps Virginia Power’s base rates unchanged until at least 2022. In September 2017, the Supreme Court of Virginia affirmed that the legislation is constitutional.
Below is a discussion of significant riders associated with various Virginia Power projects:
Virginia Power previously filed an application with the Virginia Commission to recover through Rider U costs for the first and second phases of a program to underground outage-prone overhead distribution lines. In September 2017, the Virginia Commission approved a total $22 million annual revenue requirement effective October 1, 2017, using a 9.4% ROE, and a total capital investment of $40 million for second phase conversions.
The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2017, Virginia Power requested approval to extend one existing energy efficiency program for five years with a new $25 million cost cap, and proposed a total $31 million revenue requirement for the rate year beginning July 1, 2018, which represents a $3 million increase over the previous year. This case is pending.
The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In October 2017, Virginia Power proposed a $132 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. This case is pending.
The Virginia Commission previously approved Rider US-2 in conjunction with the Scott Solar, Whitehouse, and Woodland solar facilities. In October 2017, Virginia Power proposed a $15 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. This case is pending.
Electric Transmission Projects
Virginia Power previously filed an application with the Virginia Commission for a CPCN to rebuild and rearrange its Idylwood substation in Fairfax County, Virginia. In September 2017, the Virginia Commission granted a CPCN for the project. The total estimated cost of the project is approximately $110 million.
Virginia Power previously filed an application with the Virginia Commission for a CPCN to construct and operate in multiple Virginia counties an approximately 38-mile overhead 230 kV transmission line between the Remington and Gordonsville substations, along with associated facilities. In August 2017, the Virginia Commission granted a CPCN for the project. The total estimated cost of the project is approximately $105 million.
In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry switching station in Surry County to a new Skiffes Creek switching station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek switching station to Virginia Power’s existing Whealton substation in the City of Hampton. As of July 2017, Virginia Power has received all major required permits and approvals and is proceeding with construction of the project. In connection with the receipt of the permit from the U.S. Army Corps of Engineers in July 2017, Virginia Power was required to make payments totaling approximately $90 million to fund improvements to historical and cultural resources near the project. Accordingly, in July 2017, Virginia Power recorded an increase to property, plant and equipment and a corresponding liability for these payment obligations. Through September 30, 2017, Virginia Power had made $70 million of such payments, with the remaining $20 million paid in October 2017. Also in July 2017, the National Parks Conservation Association filed a lawsuit in U.S. District Court for the D.C. Circuit seeking to set aside the permit granted by the U.S. Army Corps of Engineers for the project and requested a preliminary injunction against the permit. In August 2017, the National Trust for Historic Preservation and Preservation Virginia filed a similar lawsuit in U.S. District Court for the D.C. Circuit. In October 2017, the preliminary injunction requests were denied. These lawsuits are pending.
North Carolina Regulation
In August 2017, Virginia Power submitted its annual filing to the North Carolina Utilities Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $15 million increase to the fuel component of its electric rates for the rate year beginning January 1, 2018. This case is pending.
UEX Rider
East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In September 2017, the Ohio Commission approved East Ohio’s application requesting approval of its UEX Rider to reflect a refund of over-recovered accumulated bad debt expense of approximately $12 million as of March 31, 2017, and recovery of prospective net bad debt expense projected to total approximately $22 million for the twelve-month period from April 2017 to March 2018.
Utah and Wyoming Regulation
In October 2017, Questar Gas submitted filings with both the Public Service Commission of Utah and the Wyoming Public Service Commission for an approximately $25 million gas cost increase reflecting forecasted increases in commodity and transportation costs. The Public Service Commission of Utah and the Wyoming Public Service Commission both approved the filings in October 2017 with rates effective November 2017.
West Virginia Regulation
In October 2017, the Public Service Commission of West Virginia approved Hope’s application for new PREP customer rates, for the year beginning November 1, 2017, that provide for projected revenue of $4 million related to capital investments of $21 million, $27 million and $31 million for 2016, 2017 and 2018, respectively.
FERC – Gas
DETI
In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header Project, a project to provide approximately 1,500,000 Dths per day of firm transportation service to various customers. This project is expected to be placed into service in late 2019 and cost approximately $550 million to $600 million to construct, excluding financing costs. In October 2017, DETI received FERC authorization to construct and operate the project facilities.
In September 2017, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $39 million. Also in September 2017, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $6 million. In October 2017, FERC approved these adjustments.2019.
Cove Point
In November 2016,January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with 23 proposed rates to be effective JanuaryMarch 1, 2017.2020. Cove Point proposed an annual cost-of-service of approximately $140$182 million. In December 2016,February 2020, FERC accepted a January 1, 2017approved suspending the changes in rates for five months following the proposed effective date, for all proposed rates but five which were suspendeduntil August 1, 2020, subject to be effective June 1, 2017. refund.
In August 2017,February 2020, Cove Point submitted its annual electric power cost adjustment to FERC requesting approval to recover $28 million. FERC approved the adjustment in March 2020.
DETI
In December 2019, DETI filed an application to request FERC authorization to construct, operate and maintain the Tri-West project to provide 120,000 dekatherms per day of firm transportation service from Pennsylvania to Ohio for delivery to Tennessee Gas Pipeline Company, L.L.C. The application was automatically approved after a proposed stipulation 60-day waiting period from the date of filing and settlement agreement withthe project commenced commercial operations in August 2020 at a cost of $17 million.
In September 2020, DETI submitted its annual transportation cost rate adjustment to FERC which was supported or not opposed byrequesting approval to recover $37 million. Also in September 2020, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $8 million. In October 2020, FERC approved these adjustments.
In January 2018, DETI filed an application to request FERC authorization to construct and operate certain facilities located in Ohio and Pennsylvania for the active parties. UnderSweden Valley project. In June 2019, DETI withdrew its application for the termsproject due to certain regulatory delays. As a result of the settlement agreement, Cove Point’s rates effective October 2017 would resultproject abandonment, during the second quarter of 2019, DETI recorded a charge of $13 million ($10 million after-tax), included in decreases to annual revenuesimpairment of assets and depreciation expenseother charges (benefits) in Eastern Energy’s Consolidated Statements of approximately $18 million and $3 million, respectively, compared to the rates in effect through December 2016. In September 2017, the Presiding Administrative Law Judge certified the uncontested settlement to FERC. Cove Point is awaiting final FERC approval of the settlement. This case is pending.Income.
Note 13.12. Variable Interest Entities
There have been no significant changes regarding the entities the Companies considerEastern Energy considers VIEs as described in Note 1516 to the Consolidated Financial Statements in the Companies'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016.2019.
Dominion
Eastern Energy
Dominion Energy’s securities due within one year purchased shared services from DECGS and long-term debt include $29DEQPS of $3 million and $356$7 million respectively, of debt issued in 2016 by SBL Holdco, a VIE, net of issuance costs that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in certain merchant solar facilities.
Virginia Power had long-term power and capacity contracts with three non-utility generators. Contracts with two of these non-utility generators expired during the third quarter of 2017 leaving a remaining aggregate summer generation capacity of approximately 218 MW. Virginia Power is not subject to any risk of loss from this remaining potential VIE other than its remaining purchase commitments which totaled $213 million as of September 30, 2017. Virginia Power paid $17 million and $37 million for electric capacity and $5 million and $11 million for electric energy to these entities for the three months ended September 30, 2017 and 2016, respectively. Virginia Power paid $732020, $4 million and $111$8 million for electric capacity and $20the three months ended September 30, 2019, $10 million and $23$21 million for electric energy to these entities for the nine months ended September 30, 20172020, and 2016,$13 million and $28 million for the nine months ended September 30, 2019, respectively. Eastern Energy’s Consolidated Balance Sheets included amounts due to both DECGS and DEQPS of $29 million and $15 million at September 30, 2020 and December 31, 2019, respectively, recorded in payable to affiliates.
Virginia Power and DominionEastern Energy Gas
Virginia Power and Dominion Energy Gas purchased shared services from DES, an affiliated VIE, of $83$22 million and $31$25 million for the three months ended September 30, 2017,2020 and 2019, respectively, and $80 million and $31 million for the three months ended September 30, 2016, $251 million and $93$92 million for the nine months ended September 30, 20172020 and $2682019, respectively. Eastern Energy’s Consolidated Balance Sheets include amounts due to DES of $61 million and $95$27 million for the nine months endedat September 30, 2016, respectively.2020 and December 31, 2019, respectively, recorded in payables to affiliates.
Note 14.13. Significant Financing Transactions
Credit Facilities and Short-term Debt
The Companies useEastern Energy uses short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion
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Eastern Energy’s credit ratings and the credit quality of its counterparties.
Dominion Energy
At September 30, 2017, Dominion Energy’s commercial paper and letters of credit outstanding, as well as its capacity available under credit facilities, were as follows:
|
| Facility Limit |
|
| Outstanding Commercial Paper |
|
| Outstanding Letters of Credit |
|
| Facility Capacity Available |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(1) |
| $ | 5,000 |
|
| $ | 3,060 |
|
| $ | — |
|
| $ | 1,940 |
|
Joint revolving credit facility(1) |
|
| 500 |
|
|
| — |
|
|
| 73 |
|
|
| 427 |
|
Total |
| $ | 5,500 |
|
| $ | 3,060 |
|
| $ | 73 |
|
| $ | 2,367 |
|
|
|
Questar Gas’ short-term financing iswas supported through its access as co-borrower to the two joint revolving credit facilities discussed above with Dominion Energy, Virginia Power and Dominion Energy Gas.facility. At September 30, 2017 the aggregate sub-limit for Questar Gas was $250 million.
In addition to the credit facilities mentioned above, SBL Holdco has $30 million2020, a maximum of credit facilities which have a stated maturity date of December 2017 with automatic one-year renewals through the maturity$1.5 billion of the SBL Holdco term loan agreement in 2023. Dominion Solar Projects III, Inc. has $25 million of credit facilities which have a stated maturity date of May 2018 with automatic one-year renewals throughfacility was available to Eastern Energy and the maturity of the Dominion Solar Projects III, Inc. term loan agreement in 2024.sub-limit was $750 million. At September 30, 2017, no amounts were2020, Eastern Energy did not have any commercial paper or letters of credit outstanding under either of these facilities.
Virginia Power
Virginia Power’s short-term financing is supported through its access as co-borrower to the two joint revolving credit facilities. Thesefacility. This credit facilities can befacility was used for working capital, as support for the combined commercial paper programs of the Companiesborrowers under the credit facility and for other general corporate purposes.
At September 30, 2017, Virginia Power’s share of commercial paper and letters of credit outstanding under its joint credit facilities with In October 2020, Dominion Energy Dominion Energy Gas and Questar Gas were as follows:
|
| Facility Limit(1) |
|
| Outstanding Commercial Paper |
|
| Outstanding Letters of Credit |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(1) |
| $ | 5,000 |
|
| $ | 320 |
|
| $ | — |
|
Joint revolving credit facility(1) |
|
| 500 |
|
|
| — |
|
|
| 1 |
|
Total |
| $ | 5,500 |
|
| $ | 320 |
|
| $ | 1 |
|
|
|
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. At September 30, 2017, this facility supports $100 million of certain variable rate tax-exempt financings of Virginia Power.
Dominion Energy Gas
Dominion Energy Gas’ short-term financing is supported by its access as co-borrower to the two joint revolving credit facilities. Thesefacility to remove Eastern Energy as a co-borrower. After the acquisition of Eastern Energy by BHE, short-term liquidity needs may be satisfied through short-term intercompany borrowings from BHE. In November 2020, Eastern Energy entered into a $400 million intercompany revolving credit facilities can be used for working capital, as support for the combined commercial paper programsagreement with BHE GT&S, LLC, an indirect wholly-owned subsidiary of the Companies and for other general corporate purposes.BHE, expiring November 2021 with a recurring one-year extension option. The credit facility has a variable interest rate based on London Interbank Offered Rate plus a fixed spread.
At September 30, 2017,Noncontrolling Interest in Dominion Energy Gas' share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion Energy, Virginia Power and Questar Gas were as follows:Midstream
|
| Facility Limit(1) |
|
| Outstanding Commercial Paper |
|
| Outstanding Letters of Credit |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Joint revolving credit facility(1) |
| $ | 1,000 |
|
| $ | 620 |
|
| $ | — |
|
Joint revolving credit facility(1) |
|
| 500 |
|
|
| — |
|
|
| — |
|
Total |
| $ | 1,500 |
|
| $ | 620 |
|
| $ | — |
|
|
|
Long-term Debt
In January 2017, Dominion Energy 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 Energy issued through private placement $300 million of 3.496% senior notes that mature in 2024. Also in March 2017, Dominion Energy 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.
In May 2017, Dominion Solar Projects III, Inc. borrowed $280 million under a term loan agreement that bears interest at a variable rate. The term loan amortizes over an 18-year period and matures in May 2024. The debt is nonrecourse to Dominion Energy and is securedDominion Energy Midstream closed on an agreement and plan of merger pursuant to which Dominion Energy acquired each outstanding common unit representing limited partner interests in Dominion Energy Midstream not already owned by Dominion Solar Projects III, Inc.’s interest in certain solar facilities.
In June 2017, Dominion Energy issued through private placement $500the issuance of 22.5 million shares of variable rate senior notes that mature in 2019.
In August 2017, Dominion Energy retired its $75 million variable rate Massachusetts Development Finance Agency Solid Waste Disposal Revenue Bonds, Series 2010B that would otherwise have matured in December 2041.
In September 2017, Virginia Power issued $550 million of 3.80% senior notes that mature in 2047. Also in September 2017, Virginia Power issued an additional $200 million of its 2.75% senior notes that mature in 2023.
In October 2017, Questar Gas entered into an agreement with certain investors to issue through private placements in November 2017, $100 million of 3.38% 15-year senior notes and, in April 2018, $50 million of 3.30% 12-year senior notes and $100 million of 3.97% 30-year senior notes.
Remarketable Subordinated Notes
In May 2017, Dominion Energy successfully remarketed the $1.0 billion 2014 Series A 1.50% RSNs due in 2020 pursuant tocommon stock valued at $1.6 billion. Under the terms of the 2014 Equity Units.agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in Dominion Energy Midstream was converted into the right to receive 0.2492 shares of Dominion Energy common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Dominion Energy Midstream was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement. The merger was accounted for by Dominion Energy following the guidance for a change in a parent company’s ownership interest in a consolidated subsidiary. Because Dominion Energy controls Dominion Energy Midstream both before and after the merger, the changes in Dominion Energy’s ownership interest in Dominion Energy Midstream were accounted for as an equity transaction and 0 gain or loss was recognized. In connection with the remarketing,merger, Dominion Energy recognized $40 million of income taxes in equity primarily attributable to establishing additional regulatory liabilities related to excess deferred income taxes and changes in state income taxes.
Subsequent to this activity, as a result of the interest rate onDominion Energy Gas Restructuring, Eastern Energy is considered to have acquired all of the junior subordinated notes was reset to 2.579%, payable on a semi-annual basisoutstanding partnership interests of Dominion Energy Midstream and Dominion Energy ceased to have the ability to redeem the notes at its option or defer interest payments. At September 30, 2017, these securities are included in junior subordinated notes in Dominion Energy’s Consolidated Balance Sheets. DominionMidstream became a wholly-owned subsidiary of Eastern Energy did not receive any proceeds from the remarketing. Remarketing proceeds belonged to the investors holding the related 2014 Equity Units and were temporarily used to purchase a portfolio of treasury securities. Upon maturity of the portfolio, the proceeds were applied on behalf of investors on the related stock purchase contracts settlement date in July 2017 to pay the purchase price to Dominion Energy for the issuance of 12.5 million shares of its common stock related to Dominion Energy’s 2014 Equity Units.
Issuance of Common Stock
In June 2017, Dominion Energy filed an SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at-the-market program. Also in June 2017, Dominion Energy entered into three separate sales agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the New York Stock Exchange at market prices or in such other transactions as are agreed upon by Dominion Energy and the sales agents in conformance with applicable securities laws. No issuances have occurred under these agreements in 2017.
In July 2017, Dominion Energy issued 12.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2014 Equity Units..
Note 15.14. Commitments and Contingencies
As a result of issues generated in the ordinary course of business, the Companies areEastern Energy is 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 CompaniesEastern Energy to estimate a range of possible loss. For such matters for which the Companiesthat Eastern Energy cannot estimate, a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies areEastern Energy is able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies arethat Eastern Energy is 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'Eastern Energy’s 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 theEastern Energy’s financial position, liquidity or results of operations of the Companies.operations.
Environmental Matters
The Companies areEastern Energy 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.
CAA
The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation's air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states
25
may choose to develop regulatory programs that are more restrictive. Many of the Companies'Eastern Energy’s facilities are subject to the CAA'sCAA’s permitting and other requirements.
MATS
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. Virginia Power ceased operating the coal units at Yorktown power station in April 2017 as planned.
In June 2017, the U.S. DOE issued an order to PJM to direct Virginia Power to operate Yorktown power station’s Units 1 and 2 as needed to avoid reliability issues on the Virginia Peninsula. The order was effective for 90 days and can be reissued upon PJM’s request, if necessary, until required electricity transmission upgrades are completed approximately 23 months following the receipt in July 2017 of final permits and approvals for construction. In July 2017, the Sierra Club filed a petition for rehearing of the U.S. DOE order, which was denied by the U.S. DOE in September 2017. In August 2017, PJM filed a request for a 90-day renewal of the U.S. DOE order, which the U.S. DOE subsequently granted in September 2017. In October 2017, the Sierra Club filed a petition for rehearing of the U.S. DOE order granted in September 2017. This matter is pending.
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. Since the MATS rule remains in effect and Dominion Energy is complying with the applicable requirements of the rule, Dominion Energy does not expect any adverse impacts to its operations at this time.
Ozone Standards
InThe EPA published final non-attainment designations for the 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.
The statutory deadline for the EPA to complete attainment designations for a new standard was October 2017. While it is uncertain when the EPA will make final designations, states willJune 2018. States have up to three yearsuntil August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the Companies arestandard, Eastern Energy is unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significantThe expenditures are required to implement additional controls it could adversely affect the Companies’have a material impact on Eastern Energy’s results of operations and cash flows.
In August 2012, the EPA issued the firstan 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 finalanother 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,October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. The amended portions of the 2016 rule were effective immediately upon publication. In August 2020, the EPA issued a notice that it is reviewing and, if appropriate, will issue a rulemakingtwo final amendments related to suspend, revise or rescind the June 2016 finalreconsideration of the NSPS for certainthe oil and natural gas facilities. In June 2017,sector applicable to VOC and methane emissions. Together, the EPA published noticetwo amendments have the effect of reconsideration and partial stayrescinding the methane portion of the ruleNSPS for 90 daysall segments of the oil and proposed extendingnatural gas sector, rescinding all NSPS for the staytransmission and storage segment and modifying some of the NSPS VOC requirements for facilities in the production and processing segments. The two years. In July 2017,amendments have been challenged in the U.S. Court of Appeals for the D.C. Circuit vacatedbut remain in effect pending the 90-day stay. Dominionoutcome of the litigation. Eastern Energy and Dominion Energy Gas are implementing the final regulation. Dominion Energy and Dominion Energy Gas areis 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 PSDprevention of significant deterioration 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 CO2carbon dioxide equivalent emissions under which a source would not be required to apply BACTbest available control technology for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, the CompaniesEastern Energy 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 Energy'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, DETI and Questar Gas (prior to the Dominion Energy Questar Combination) joined the EPA as founding partners in the new Methane Challenge program and submitted implementation plans in September 2016. DECG joined the EPA’s voluntary Natural Gas STAR Program in July 2016 and submitted an implementation plan in September 2016. Dominion Energy and Dominion Energy Gas do not expect the costs related to these programs to have a material impact on their results of operations, financial condition and/or cash flows.
Water
The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The Companies must comply with applicable aspectsAt a minimum, states are required to establish regulatory programs to address all requirements of the CWA. However, states may choose to develop regulatory programs that are more restrictive. Many of Eastern Energy’s facilities are subject to CWA permitting and other state requirements. Eastern Energy does not currently foresee the existing 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 employas having a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement basedmaterial effect 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 Energy and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion Energy anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion Energy 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 Energy’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.flows.
Waste Management and Remediation
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 beoperations of Eastern Energy is subject to additional wastewater treatment requirementsa variety of state and federal laws and regulations governing the management and disposal of solid and hazardous waste, and release of hazardous substances 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 U.S.’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates of the Effluent Limitations Guidelines final rule for compliance with certain wastewater regulations from November 2018 to November 2020; however, the latest date for compliance for these regulations remains December 2023. The EPA is proposing to complete new rulemaking for these waste streams. While the impacts of this rule could be material to Dominion Energy’s and Virginia Power’s results of operations, financial conditioncurrent 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
historical operations. The CERCLA, as amended, providesand similar state laws, may impose joint, several and strict liability for immediate response and removal actions coordinatedcleanup on potentially responsible parties who owned, operated or arranged for disposal at facilities affected by the EPA in the eventa release of threatenedhazardous substances. In addition, many states have created programs to incentivize voluntary remediation of sites where historical releases of hazardous substances into the environmentare identified and authorizes the U.S. government either to clean up sites at which hazardous substances have created actualproperty owners 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 ordereddecide 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.initiate cleanups.
From time to time, DominionEastern Energy Virginia Power, or Dominion Energy Gas may be identified as a potentially responsible party toin connection with the alleged release of hazardous substances or wastes at a Superfund site. The EPA (or a state) can either allow such a party to conductUnder applicable federal 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, Dominionstate laws, Eastern Energy Virginia Power, or Dominion Energy Gas maycould be responsible for costs associated with the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. The Companies doimpacted sites, or subject to contribution claims by other responsible parties for their costs incurred at such sites. Eastern Energy also may identify, evaluate and remediate other potentially impacted sites under voluntary state programs. Remediation costs may be subject to reimbursement under Eastern Energy’s insurance policies, rate recovery mechanisms, or both. Eastern Energy does not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.
Dominion Energy 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 Energy 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, Dominion26
Other Legal Matters
Eastern Energy is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.
See below for discussion on ash pond and landfill closure costs.
Other Legal Matters
The Companies are defendantsdefendant 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 areEastern Energy is 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, DETI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DETI 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. DETI 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 DETI must first comply with the dispute resolution process. In July 2015, the contractor filed a complaint against DETI in U.S. District Court for the Western District of Pennsylvania. In August 2015, DETI 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, DETI filed a motion to dismiss. In March 2017, the court dismissed three of eight counts in the complaint. In May 2017, the contractor withdrew one of the counts in the complaint. This case is pending. DETI has accrued a liability of $6 million for this matter. Dominion Energy 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 Energy Field Services, Inc. (formerly known as 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 Energy, DETI and Dominion Energy 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 Energy and DETI, 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 Energy was voluntarily dismissed from the case; however, DETI and Dominion Energy 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 Energy and Dominion Energy 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. 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. In March 2017, the U.S. District Court for the Eastern District of Virginia 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. In July 2017, the court issued a final order requiring Virginia Power to perform additional specific sediment, water and aquatic life monitoring at and around the
Chesapeake power station for a period of at least two years. The court further directed Virginia Power to apply for a solid waste permit from VDEQ that includes corrective measures to address on-site groundwater impacts. In July 2017, Virginia Power appealed the court’s July 2017 final order to the U.S. Court of Appeals for the Fourth Circuit. In August 2017, the Sierra Club filed a cross appeal. This case is pending.
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. In August 2017, the EPA issued interim guidance outlining the framework for state CCR program approval. The EPA has enforcement authority until 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. In September 2017, the EPA agreed to reconsider portions of the CCR rule in response to two petitions for reconsideration. Dominion Energy cannot forecast potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the 2016 CCR legislation and reconsideration of the CCR rule.
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 has initiated a third-party evaluation of closure alternatives consistent with 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.
Cove Point
Dominion Energy 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. In September 2017, FERC issued its order on remand from the U.S. Court of Appeals for the D.C. Circuit, and reaffirmed its ruling in its prior orders that Cove Point did not violate the prohibition against undue discrimination by agreeing to a capacity reduction and early contract termination with the existing import shipper.
In September 2013, the U.S. 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.
In July 2017, Cove Point submitted an application for a temporary operating permit to the Maryland Department of the Environment, as required prior to the date of first production of LNG for commercial purposes of exporting LNG. In August 2017, Cove Point submitted an application to amend the CPCN issued by the Public Service Commission of Maryland in May 2014 to make necessary updates. These cases are pending.
FERC
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. 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 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.
Greensville County
Virginia Power is constructing Greensville County and related transmission interconnection facilities. In August 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 the VDEQ in June 2016. In August 2017, the Circuit Court upheld the air permit, and no appeals were filed.
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 Energy 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 Energy 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 Energy 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 Energy 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
Dominion Energy
At September 30, 2017, Dominion Energy had issued $48 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded.
In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.3 billion revolving credit facility, also entered in October 2017, with a stated maturity date of October 2021. Dominion Energy’s maximum potential loss exposure under the terms of the guarantee is limited to 48% of the outstanding borrowings under the revolving credit facility, an equal percentage to Dominion Energy’s ownership in Atlantic Coast Pipeline. In October 2017, Dominion Energy recorded a liability of $30 million associated with this guarantee agreement. Through October 2017, Atlantic Coast Pipeline has borrowed $570 million against the revolving credit facility.
Dominion Energy 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 Energy would be obligated to satisfy such obligation. To the extent that a liability subject to a guarantee has been incurred by one of Dominion Energy’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion Energy 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 Energy currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.
At September 30, 2017, Dominion Energy had issued the following subsidiary guarantees:
|
| Maximum Exposure |
| |
(millions) |
|
|
|
|
Commodity transactions(1) |
| $ | 1,967 |
|
Nuclear obligations(2) |
|
| 227 |
|
Cove Point(3) |
|
| 1,900 |
|
Solar(4) |
|
| 1,054 |
|
Other(5) |
|
| 538 |
|
Total(6) |
| $ | 5,686 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Additionally, at September 30, 2017, Dominion2020, Eastern Energy had purchased $141$28 million of surety bonds, including $63 million at Virginia Power and $24 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $73 million to facilitate commercial transactions by its subsidiaries with third parties.bonds. Under the terms of surety bonds, the Companies areEastern Energy or BHE is obligated to indemnify the respective surety bond company for any amounts paid.
Note 16.15. Credit Risk
The Companies'Eastern Energy’s accounting policies for credit risk are discussed in Note 2324 to the Consolidated Financial Statements in the Companies'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016. During the second quarter of 2017, Virginia Power recorded a $16 million ($10 million after-tax) charge related to a proposed settlement with a customer renting space on certain of Virginia Power’s electric distribution poles. This matter was settled during the third quarter of 2017.2019.
At September 30, 2017, Dominion Energy's credit2020, Eastern Energy’s exposure primarily related to energy marketing and price risk management activitieswholesale customers totaled $70$24 million. Of this amount, investment grade counterparties, including those internally rated, represented 49%98%. NoNaN single counterparty, whether investment grade or non-investment grade, exceeded $7$5 million of exposure. At
For the three and nine months ended September 30, 2017, Virginia Power's exposure related to sales to wholesale customers totaled $23 million. Of this amount, investment grade counterparties, including those internally rated, represented 52%. No single counterparty, whether investment grade or non-investment grade, exceeded $6 million2020, the Export Customers comprised approximately 32% and 33%, respectively, of exposure.Eastern Energy’s total operating revenue, with Eastern Energy’s largest customer representing approximately 17% of such amounts during both periods. For the three and nine months ended September 30, 2019, the Export Customers comprised approximately 37% and 34%, respectively, of Eastern Energy’s total operating revenue, with Eastern Energy’s largest customer representing approximately 19% and 18%, respectively, of such amounts during the periods.
Credit-Related Contingent Provisions
The majority of Dominion Energy's derivative instruments contain credit-related contingent provisions. These provisions require Dominion Energy to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of September 30, 2017 and December 31, 2016, Dominion Energy would have been required to post additional collateral to its counterparties of $6 million and $3 million, respectively. 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 Energy had not posted any collateral at September 30, 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 at both September 30, 2017 and December 31, 2016 was $9 million, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and DominionEastern Energy Gas were not material as of September 30, 20172020 and December 31, 2016.2019. See Note 98 for further information about derivative instruments.
Note 17.16. Related-Party Transactions
Virginia Power and DominionEastern Energy Gas engageengages in related-party transactions primarily with other Dominion Energy subsidiaries (affiliates). Virginia Power's and Dominion Energy Gas'Eastern Energy’s 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 DominionThrough November 1, 2020, Eastern Energy Gas arewas included in Dominion Energy's consolidated federal income tax return and, where applicable, combined income tax returns for Dominion Energy are filed in various states. Dominion Energy's transactions with equity method investments are described in Note 10. A discussion of significant related-party transactions follows.
Virginia Power
Transactions with Affiliates
Virginia PowerEastern Energy transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Virginia PowerAdditionally, Eastern Energy provides transportation and storage services to affiliates. Eastern Energy also enters into certain other contracts with affiliates and related parties, including construction services, which are presented separately from contracts involving commodities or services. As of September 30, 2020 and December 31, 2019, Eastern Energy did 0t have any commodity derivative contractsassets or liabilities 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. At September 30, 2017, Virginia Power’s derivative assetsSee Notes 6 and liabilities with affiliates were $13 million and $5 million, respectively. At December 31, 2016, Virginia Power’s derivative assets and liabilities with affiliates were $41 million and $8 million, respectively. See Note 98 for more information. See Note 3 for information regarding the Dominion Energy Gas Restructuring, an affiliated transaction.
Virginia PowerEastern Energy participates in certain Dominion Energy benefit plans as described in Note 21 to the Consolidated Financial Statements in the Companies’Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016.2019. At September 30, 20172020 and December 31, 2016, amounts due to Dominion Energy associated with the Dominion Pension Plan and included in other deferred credits and other liabilities in the Consolidated Balance Sheets were $478 million and $396 million, respectively. At September 30, 2017 and December 31, 2016, Virginia Power's2019, amounts due from Dominion Energy associated with the Dominion Retiree Health and Welfare plan andEnergy Pension Plan included in pensionother deferred charges and other postretirement benefit assets in the Consolidated Balance Sheets were $182$339 million and $130$326 million, respectively. At September 30, 2020 and December 31, 2019, Eastern Energy’s amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan included in other deferred charges and other assets in the Consolidated Balance Sheets were $22 million and $17 million, respectively.
DES, DECGS, DEQPS and other affiliates provide accounting, legal, finance, marketing and certain administrative and technical services to Virginia Power. In addition, Virginia PowerEastern Energy. Eastern Energy provides certain services to affiliates,related parties, including charges for facilities and equipment usage.technical services.
The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES, DECGS and DEQPS to Virginia PowerEastern Energy on the basis of direct and allocated methods in accordance with Virginia Power’sEastern Energy’s services agreements with DES.DES, DECGS and DEQPS. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES, DECGS and DEQPS resources that isare attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES, DECGS
27
and DEQPS service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.
Subsequent to the GT&S Transaction, Eastern Energy’s transactions with other Dominion Energy subsidiaries are no longer related-party transactions.
Presented below are Virginia Power'sEastern Energy’s significant transactions with DES, DECGS, DEQPS and other affiliates:affiliates and related parties:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
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| 2017 |
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| 2016 |
|
| 2017 |
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| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Commodity purchases from affiliates |
| $ | 170 |
|
| $ | 172 |
|
| $ | 519 |
|
| $ | 416 |
|
Services provided by affiliates(1) |
|
| 109 |
|
|
| 105 |
|
|
| 333 |
|
|
| 347 |
|
Services provided to affiliates |
|
| 5 |
|
|
| 5 |
|
|
| 17 |
|
|
| 17 |
|
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
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| 2020 |
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| 2019 |
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| 2020 |
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| 2019 |
| ||||
(millions) |
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|
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|
|
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Sales of natural gas and transportation and storage services |
| $ | 60 |
|
| $ | 60 |
|
| $ | 188 |
|
| $ | 187 |
|
Purchases of natural gas and transportation and storage services |
|
| 3 |
|
|
| 0 |
|
|
| 9 |
|
|
| 0 |
|
Services provided by related parties(1) |
|
| 34 |
|
|
| 41 |
|
|
| 114 |
|
|
| 145 |
|
Services provided to related parties(2) |
|
| 17 |
|
|
| 38 |
|
|
| 78 |
|
|
| 128 |
|
(1) | Includes capitalized expenditures of |
Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $36 million and $262 million in short-term demand note borrowings from Dominion Energy as of September 30, 2017 and December 31, 2016, respectively. Virginia Power had no outstanding borrowings under the Dominion Energy money pool for its nonregulated subsidiaries as of September 30, 2017 and December 31, 2016. Interest charges related to Virginia Power's borrowings from Dominion Energy were immaterial for the three and nine months ended September 30, 2017 and 2016.
There were no issuances of Virginia Power's common stock to Dominion Energy for the three and nine months ended September 30, 2017 and 2016.
Dominion Energy Gas
Transactions with Related Parties
Dominion Energy Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Energy Gas provides transportation and storage services to affiliates. Dominion Energy Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of September 30, 2017 and December 31, 2016, all of Dominion Energy Gas' commodity derivatives were with affiliates. See Notes 7 and 9 for more information.
Dominion Energy Gas participates in certain Dominion Energy benefit plans as described in Note 18. At September 30, 2017 and December 31, 2016, amounts due from Dominion Energy associated with the Dominion Pension Plan included in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $725 million and $697 million, respectively. At September 30, 2017 and December 31, 2016, Dominion Energy Gas' amounts due from Dominion Energy associated with the Dominion Retiree Health and Welfare plan included in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $6 million and $2 million, respectively.
The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Dominion Energy Gas on the basis of direct and allocated methods in accordance with Dominion Energy Gas’ services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. The costs of these services follow:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of natural gas and transportation and storage services from affiliates |
| $ | 2 |
|
| $ | 2 |
|
| $ | 4 |
|
| $ | 7 |
|
Sales of natural gas and transportation and storage services to affiliates |
|
| 15 |
|
|
| 16 |
|
|
| 51 |
|
|
| 51 |
|
Services provided by related parties(1) |
|
| 36 |
|
|
| 36 |
|
|
| 106 |
|
|
| 108 |
|
Services provided to related parties(2) |
|
| 37 |
|
|
| 34 |
|
|
| 113 |
|
|
| 94 |
|
|
|
(2) |
|
The following table presents affiliated and related-party activityrelated party balances reflected in Dominion Energy Gas'Eastern Energy’s Consolidated Balance Sheets:
|
| September 30, 2017 |
|
| December 31, 2016 |
|
| September 30, 2020 |
|
| December 31, 2019 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other receivables(1) |
| $ | 13 |
|
| $ | 10 |
|
| $ | 0 |
|
| $ | 7 |
|
Imbalances receivable from affiliates |
|
| — |
|
|
| 2 |
|
|
| 5 |
|
|
| 8 |
|
Imbalances payable to affiliates(2) |
|
| 1 |
|
|
| 4 |
|
|
| 1 |
|
|
| 1 |
|
Affiliated notes receivable(3) |
|
| 21 |
|
|
| 18 |
| ||||||||
Other deferred charges and other assets |
|
| 8 |
|
|
| 12 |
| ||||||||
(1) | Represents amounts due from Atlantic Coast Pipeline, a related-party VIE. |
(2) | Amounts are presented in other current liabilities in |
|
|
DETI provides services to Atlantic Coast Pipeline which totaled $7 million and $24 million for the three months ended September 30, 2020 and 2019, respectively, and $44 million and $81 million for the nine months ended September 30, 2020 and 2019, respectively, included in operating revenue in Eastern Energy’s Consolidated Statements of Income.
Affiliated receivables at September 30, 2020 and December 31, 2019 included $18 million and $22 million, respectively, of accrued unbilled revenue. This revenue is based on estimated amounts of services provided but not yet billed to various affiliates.
Eastern Energy’s affiliated borrowings and investments are discussed in Note 25 to Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2019.
Eastern Energy had $240 million in affiliated notes receivable under the Dominion Energy Gas'money pool as of September 30, 2020 and 0 outstanding receivables as of December 31, 2019. Interest income related to the affiliated notes receivable was $1 million and $3 million for the three and nine months ended September 30, 2020, respectively.
Interest income on affiliated notes receivable from East Ohio and DGP for borrowings under intercompany revolving credit agreements with Eastern Energy was $4 million and $12 million for the three and nine months ended September 30, 2019, respectively.
Interest income earned on DMLPHCII’s promissory note to Dominion Energy was immaterial for both the three and nine months ended September 30, 2020 and 2019.
Interest income related to Dominion Energy’s promissory note borrowings with Cove Point was $28 million and $82 million for the three and nine months ended September 30, 2019, respectively.
Eastern Energy’s affiliated notes receivable from Dominion Energy totaled $1.8 billion at December 31, 2019. In August 2020, Dominion Energy repaid the remaining principal balance outstanding. Interest income on these promissory notes was $9 million and $32 million for the three and nine months ended September 30, 2020, respectively.
28
At December 31, 2019, Eastern Energy’s affiliated notes receivable from East Ohio totaled $1.7 billion. In June 2020, East Ohio repaid the remaining principal balance outstanding. Interest income on these promissory notes was $33 million for the nine months ended September 30, 2020, and $18 million and $54 million for the three and nine months ended September 30, 2019, respectively.
Eastern Energy’s borrowings under the intercompany revolving credit agreement with Dominion Energy were $34totaled $5 million and $118$251 million as of September 30, 20172020 and December 31, 2016,2019, respectively. Interest charges related to Dominion Energy Gas'Eastern Energy’s total borrowings from Dominion Energy were immaterial$1 million and less than $1 million for the three months ended September 30, 2020 and 2019, respectively, and were $3 million and $2 million for the nine months ended September 30, 2020 and 2019, respectively.
Interest charges related to DCP’s total borrowings from Dominion Energy under an intercompany revolving credit agreement totaled $30 million and $88 million for the three and nine months ended September 30, 20172019, respectively.
DCP had borrowings of $9 million with DES as of December 31, 2019. NaN amounts were outstanding as of September 30, 2020. Interest related to DCP’s total borrowings from DES were $2 million and 2016.
Note 18. Employee Benefit Plans$1 million for the three months ended September 30, 2020 and 2019, respectively, and $3 million for both the nine months ended September 30, 2020 and 2019.
In the first quarter of 2016,2019, Dominion Energy Midstream borrowed $395 million from Dominion Energy under a $400 million promissory note with Dominion Energy that was scheduled to mature in 2022. Interest charges of $4 million and $9 million were incurred for 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 structurethree and push decision making lower while also improving efficiency. Duringnine months ended September 30, 2019, respectively.
For the nine months ended September 30, 2016, Dominion2020 and 2019, Eastern Energy, recorded a $65 million ($40 million after-tax) charge, including $33 million ($20 million after-tax) at Virginia Power and $8 million ($5 million after-tax) atentities acquired in the Dominion Energy Gas primarilyRestructuring, distributed $4.2 billion and $551 million to Dominion Energy, respectively.
Note 17. Employee Benefit Plans
Eastern Energy participated in certain Dominion Energy benefit plans as described in Note 22 to the Consolidated Financial Statements in Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2019. See Note 16 for more information.
The service cost component and non-service cost components of net periodic benefit (credit) cost are reflected in other operations and maintenance expense and other income, respectively, in theirthe Consolidated Statements of Income dueIncome. The components of Eastern Energy’s provision for net periodic benefit cost (credit) for employees represented by collective bargaining units are as follows:
|
| Pension Benefits |
|
| Other Postretirement Benefits |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 2 |
|
| $ | 4 |
|
| $ | 0 |
|
| $ | 0 |
|
Interest cost |
|
| 3 |
|
|
| 7 |
|
|
| 1 |
|
|
| 3 |
|
Expected return on plan assets |
|
| (14 | ) |
|
| (38 | ) |
|
| (4 | ) |
|
| (6 | ) |
Amortization of prior service credit |
|
| 0 |
|
|
| 0 |
|
|
| (1 | ) |
|
| (1 | ) |
Amortization of net actuarial loss |
|
| 1 |
|
|
| 5 |
|
|
| 0 |
|
|
| 0 |
|
Net periodic benefit credit |
| $ | (8 | ) |
| $ | (22 | ) |
| $ | (4 | ) |
| $ | (4 | ) |
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 5 |
|
| $ | 12 |
|
| $ | 1 |
|
| $ | 2 |
|
Interest cost |
|
| 8 |
|
|
| 23 |
|
|
| 3 |
|
|
| 8 |
|
Expected return on plan assets |
|
| (42 | ) |
|
| (116 | ) |
|
| (14 | ) |
|
| (20 | ) |
Amortization of prior service credit |
|
| 0 |
|
|
| 0 |
|
|
| (3 | ) |
|
| (3 | ) |
Amortization of net actuarial loss |
|
| 5 |
|
|
| 15 |
|
|
| 1 |
|
|
| 2 |
|
Curtailment(1) |
|
| 0 |
|
|
| 1 |
|
|
| 0 |
|
|
| 1 |
|
Net periodic benefit credit |
| $ | (24 | ) |
| $ | (65 | ) |
| $ | (12 | ) |
| $ | (10 | ) |
(1) 2019 amounts relate 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.a voluntary retirement program.
Plan Amendment and Remeasurement
In the first quarter of 2017, Dominion Energy and Dominion Energy 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 Energy's and Dominion Energy 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 Energy and Dominion Energy 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.Employer Contributions
29
During the nine months ended September 30, 2017, Dominion Energy recorded a $7 million ($4 million after-tax) charge, including $6 million ($4 million after-tax) at Dominion Energy 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 Energy's provision for net periodic benefit cost (credit) were as follows:
|
| Pension Benefits |
|
| Other Postretirement Benefits |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 35 |
|
| $ | 30 |
|
| $ | 7 |
|
| $ | 7 |
|
Interest cost |
|
| 86 |
|
|
| 79 |
|
|
| 15 |
|
|
| 16 |
|
Expected return on plan assets |
|
| (160 | ) |
|
| (141 | ) |
|
| (32 | ) |
|
| (28 | ) |
Amortization of prior service credit |
|
| — |
|
|
| — |
|
|
| (13 | ) |
|
| (9 | ) |
Amortization of net actuarial loss |
|
| 40 |
|
|
| 29 |
|
|
| 3 |
|
|
| 2 |
|
Settlements |
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Net periodic benefit cost (credit) |
| $ | 2 |
|
| $ | (3 | ) |
| $ | (20 | ) |
| $ | (12 | ) |
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 104 |
|
| $ | 87 |
|
| $ | 20 |
|
| $ | 23 |
|
Interest cost |
|
| 259 |
|
|
| 234 |
|
|
| 45 |
|
|
| 50 |
|
Expected return on plan assets |
|
| (480 | ) |
|
| (419 | ) |
|
| (95 | ) |
|
| (87 | ) |
Amortization of prior service cost (credit) |
|
| 1 |
|
|
| 1 |
|
|
| (38 | ) |
|
| (23 | ) |
Amortization of net actuarial loss |
|
| 121 |
|
|
| 84 |
|
|
| 9 |
|
|
| 5 |
|
Settlements |
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Net periodic benefit cost (credit) |
| $ | 7 |
|
| $ | (13 | ) |
| $ | (59 | ) |
| $ | (32 | ) |
Employer Contributions
During the nine months ended September 30, 2017, Dominion2020, Eastern Energy made no0 contributions to its qualified defined benefit pension plansplan or other postretirement benefit plans, except for a $75 million contribution made in January 2017plans. Eastern Energy does 0t expect to Dominion Energy Questar’smake contributions to its qualified defined benefit pension plan to satisfy a regulatory condition to closingduring the remainder of the Dominion Energy Questar Combination. Dominion Energy2020 and expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs duringon an annual basis.
Pension Remeasurement
In the remainderthird quarter of 2017.
2020, Eastern Energy remeasured a pension plan due to a curtailment resulting from the agreement for Dominion Energy Gasto retain the assets and obligations of the pension benefit plan associated with the GT&S Transaction. The remeasurement resulted in an increase in the pension benefit obligation of $3 million and a decrease in the fair value of the pension plan assets of $7 million for Eastern Energy. The impact of the remeasurement on net periodic pension benefit credit was recognized prospectively from the remeasurement date and is not material. The discount rate used for the remeasurement was 3.16%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2019.
Voluntary Retirement Program
In March 2019, Dominion Energy Gas participatesannounced a voluntary retirement program to employees that met certain age and service requirements. In the second quarter of 2019, upon the determinations made concerning the number of employees that elected to participate in certain Dominionthe program, Eastern Energy benefit plans as describedrecorded a charge of $74 million ($58 million after-tax) included within other operations and maintenance expense ($39 million), other taxes ($2 million), other income ($1 million) and discontinued operations ($32 million) in its Consolidated Statements of Income. See Note 2122 to the Consolidated Financial Statements in the Companies'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016. See Note 172019 for more information.
The components of Dominion Energy Gas' provision for net periodic benefit credit for employees represented by collective bargaining units were as follows:
|
| Pension Benefits |
|
| Other Postretirement Benefits |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 3 |
|
| $ | 3 |
|
| $ | 1 |
|
| $ | 1 |
|
Interest cost |
|
| 7 |
|
|
| 7 |
|
|
| 3 |
|
|
| 3 |
|
Expected return on plan assets |
|
| (34 | ) |
|
| (33 | ) |
|
| (7 | ) |
|
| (5 | ) |
Amortization of prior service credit |
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| — |
|
Amortization of net actuarial loss |
|
| 4 |
|
|
| 3 |
|
|
| 1 |
|
|
| — |
|
Net periodic benefit credit |
| $ | (20 | ) |
| $ | (20 | ) |
| $ | (3 | ) |
| $ | (1 | ) |
Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
| $ | 11 |
|
| $ | 10 |
|
| $ | 3 |
|
| $ | 4 |
|
Interest cost |
|
| 22 |
|
|
| 22 |
|
|
| 9 |
|
|
| 10 |
|
Expected return on plan assets |
|
| (105 | ) |
|
| (100 | ) |
|
| (19 | ) |
|
| (17 | ) |
Amortization of prior service credit |
|
| — |
|
|
| — |
|
|
| (2 | ) |
|
| — |
|
Amortization of net actuarial loss |
|
| 12 |
|
|
| 10 |
|
|
| 2 |
|
|
| 1 |
|
Net periodic benefit credit |
| $ | (60 | ) |
| $ | (58 | ) |
| $ | (7 | ) |
| $ | (2 | ) |
During the nine months ended September 30, 2017, Dominion Energy Gas made no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion Energy 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.
The Companies are organized primarily on the basis of products and services sold in the U.S. In connection with its corporate rebranding, the Companies changed the names of their principal operating segments to Power Delivery, Power Generation and Gas Infrastructure from Dominion Virginia Power, Dominion Generation and Dominion Energy, respectively. A description of the operations included in the Companies’ primary operating segments is as follows:
|
|
|
|
| ||||
|
|
|
| |||||
|
|
| ||||||
|
|
|
| |||||
|
| |||||||
|
|
|
| |||||
|
|
| ||||||
|
|
| ||||||
|
| |||||||
|
|
In addition to the operating segments above, the Companies also report a Corporate and Other segment.
Dominion Energy
The Corporate and Other Segment of Dominion Energy 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 Energy'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 nine months ended September 30, 2017, Dominion Energy reported after-tax net expenses of $17 million for specific items in the Corporate and Other segment, with $1 million of net expenses attributable to its operating segments. In the nine months ended September 30, 2016, Dominion Energy reported after-tax net expenses of $63 million for specific items in the Corporate and Other segment, with $22 million of these net expenses attributable to its operating segments.
The net expense for specific items attributable to Dominion Energy's operating segments in 2016 primarily related to the impact of the following item:
A $59 million ($36 million after-tax) charge related to an organizational design initiative, attributable to:
Power Delivery ($5 million after-tax);
Gas Infrastructure ($12 million after-tax); and
Power Generation ($19 million after-tax).
A $29 million ($18 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation
The following table presents segment information pertaining to Dominion Energy’s operations:
|
| Power Delivery |
|
| Power Generation |
|
| Gas Infrastructure |
|
| Corporate and Other |
|
| Adjustments/ Eliminations |
|
| Consolidated Total |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers |
| $ | 580 |
|
| $ | 1,931 |
|
| $ | 459 |
|
| $ | 3 |
|
| $ | 206 |
|
| $ | 3,179 |
|
Intersegment revenue |
|
| 4 |
|
|
| 3 |
|
|
| 204 |
|
|
| 150 |
|
|
| (361 | ) |
|
| — |
|
Total operating revenue |
|
| 584 |
|
|
| 1,934 |
|
|
| 663 |
|
|
| 153 |
|
|
| (155 | ) |
|
| 3,179 |
|
Net income (loss) attributable to Dominion Energy |
|
| 138 |
|
|
| 369 |
|
|
| 187 |
|
|
| (29 | ) |
|
| — |
|
|
| 665 |
|
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers |
| $ | 614 |
|
| $ | 1,947 |
|
| $ | 359 |
|
| $ | 2 |
|
| $ | 210 |
|
| $ | 3,132 |
|
Intersegment revenue |
|
| 6 |
|
|
| 2 |
|
|
| 205 |
|
|
| 144 |
|
|
| (357 | ) |
|
| — |
|
Total operating revenue |
|
| 620 |
|
|
| 1,949 |
|
|
| 564 |
|
|
| 146 |
|
|
| (147 | ) |
|
| 3,132 |
|
Net income (loss) attributable to Dominion Energy |
|
| 139 |
|
|
| 650 |
|
|
| 135 |
|
|
| (234 | ) |
|
| — |
|
|
| 690 |
|
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers |
| $ | 1,664 |
|
| $ | 5,091 |
|
| $ | 1,949 |
|
| $ | 12 |
|
| $ | 660 |
|
| $ | 9,376 |
|
Intersegment revenue |
|
| 16 |
|
|
| 8 |
|
|
| 645 |
|
|
| 451 |
|
|
| (1,120 | ) |
|
| — |
|
Total operating revenue |
|
| 1,680 |
|
|
| 5,099 |
|
|
| 2,594 |
|
|
| 463 |
|
|
| (460 | ) |
|
| 9,376 |
|
Net income (loss) attributable to Dominion Energy |
|
| 390 |
|
|
| 870 |
|
|
| 613 |
|
|
| (186 | ) |
|
| — |
|
|
| 1,687 |
|
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from external customers |
| $ | 1,682 |
|
| $ | 5,204 |
|
| $ | 1,235 |
|
| $ | 8 |
|
| $ | 522 |
|
| $ | 8,651 |
|
Intersegment revenue |
|
| 17 |
|
|
| 7 |
|
|
| 507 |
|
|
| 469 |
|
|
| (1,000 | ) |
|
| — |
|
Total operating revenue |
|
| 1,699 |
|
|
| 5,211 |
|
|
| 1,742 |
|
|
| 477 |
|
|
| (478 | ) |
|
| 8,651 |
|
Net income (loss) attributable to Dominion Energy |
|
| 363 |
|
|
| 1,066 |
|
|
| 483 |
|
|
| (246 | ) |
|
| — |
|
|
| 1,666 |
|
Intersegment sales and transfers for Dominion Energy are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation.
Virginia Power
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 nine months ended September 30, 2017, Virginia Power reported after-tax net expenses of $7 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segments. In the nine months ended September 30, 2016, Virginia Power reported an after-tax net expense of $18 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segments.
The net expense for specific items attributable to Virginia Power's operating segments in 2017 primarily related to the impact of the following item which was attributable to Power Delivery:
A $16 million ($10 million after-tax) charge arising from a customer settlement.
The net expense for specific items attributable to Virginia Power’s operating segments in 2016 primarily related to the impact of the following item:
A $33 million ($20 million after-tax) charge related to an organizational design initiative, attributable to:
Power Delivery ($5 million after-tax); and
Power Generation ($15 million after-tax).
The following table presents segment information pertaining to Virginia Power’s operations:
|
| Power Delivery |
|
| Power Generation |
|
| Corporate and Other |
|
| Consolidated Total |
| ||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 580 |
|
| $ | 1,574 |
|
| $ | — |
|
| $ | 2,154 |
|
Net income |
|
| 137 |
|
|
| 314 |
|
|
| 8 |
|
|
| 459 |
|
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 617 |
|
| $ | 1,594 |
|
| $ | — |
|
| $ | 2,211 |
|
Net income |
|
| 140 |
|
|
| 359 |
|
|
| 4 |
|
|
| 503 |
|
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 1,670 |
|
| $ | 4,062 |
|
| $ | — |
|
| $ | 5,732 |
|
Net income |
|
| 387 |
|
|
| 735 |
|
|
| 11 |
|
|
| 1,133 |
|
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 1,686 |
|
| $ | 4,191 |
|
| $ | — |
|
| $ | 5,877 |
|
Net income (loss) |
|
| 362 |
|
|
| 699 |
|
|
| (15 | ) |
|
| 1,046 |
|
Dominion Energy Gas
The Corporate and Other Segment of Dominion Energy Gas primarily includes specific items attributable to Dominion Energy 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 Energy Gas as a result of Dominion Energy's basis in the net assets contributed.
In the nine months ended September 30, 2017, Dominion Energy Gas reported after-tax net expenses of $9 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segment. In the nine months ended September 30, 2016, Dominion Energy Gas reported an after-tax net benefit of $5 million for specific items in the Corporate and Other segment, with after-tax net expense of $7 million attributable to its operating segment.
The net expense for specific items in 2017 was due to a $15 million ($9 million after-tax) charge to write-off the balance of a regulatory asset no longer considered probable of recovery.
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 Energy Gas' operations:
|
| Gas Infrastructure |
|
| Corporate and Other |
|
| Consolidated Total |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 401 |
|
| $ | — |
|
| $ | 401 |
|
Net income (loss) |
|
| 121 |
|
|
| (4 | ) |
|
| 117 |
|
Three Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 382 |
|
| $ | — |
|
| $ | 382 |
|
Net income |
|
| 77 |
|
|
| 6 |
|
|
| 83 |
|
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 1,313 |
|
| $ | — |
|
| $ | 1,313 |
|
Net income (loss) |
|
| 318 |
|
|
| (16 | ) |
|
| 302 |
|
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 1,181 |
|
| $ | — |
|
| $ | 1,181 |
|
Net income (loss) |
|
| 288 |
|
|
| (2 | ) |
|
| 286 |
|
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MD&A discusses DominionEastern Energy’s results of operations and general financial condition and Virginia Power's and Dominion Energy Gas' results of operations. MD&A should be read in conjunction with the Companies’Eastern Energy’s Consolidated Financial Statements. Virginia Power and DominionEastern Energy Gas meetmeets the conditions to file under the reduced disclosure format, and therefore havehas omitted certain sections of MD&A.
Contents of MD&A
MD&A consists of the following information:
• | Forward-Looking Statements |
• | Results of Operations |
Forward-Looking Statements
Accounting Matters – Dominion Energy
Dominion Energy
Results of Operations
Segment Results of Operations
Virginia Power
Results of Operations
Dominion Energy Gas
Results of Operations
Liquidity and Capital Resources – Dominion Energy
Future Issues and Other Matters – Dominion Energy
Forward-Looking Statements
This report contains statements concerning the Companies'Eastern Energy’s 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 makeEastern Energy makes forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:
Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;
Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding and changes in water temperatures and availability that can cause outages and property damage to facilities;
Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;
Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances;
Cost of environmental compliance, including those costs related to climate change;
Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;
Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;
Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;
• | Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; |
• | The impact of extraordinary external events, such as the current pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in our markets; |
• | Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations; |
• | Risks of operating businesses in regulated industries that are subject to changing regulatory structures; |
• | Changes to regulated gas transportation and storage rates, including LNG storage, collected by Eastern Energy; |
• | Risks associated with entities in which Eastern Energy shares ownership with third parties, including risks that result from lack of sole decision making authority, disputes that may arise between Eastern Energy and third party participants and difficulties in exiting these arrangements; |
• | Changes in future levels of domestic and international natural gas production, supply or consumption; |
• | Fluctuations in future volumes of LNG imports or exports from the U.S. and other countries worldwide or demand for, purchases of, and prices related to natural gas or LNG; |
• | Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals; |
• | The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects; |
• | Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances; |
• | Cost of environmental compliance, including those costs related to climate change; |
• | Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities; |
• | Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals; |
31
• | Unplanned outages at facilities in which |
Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s and Dominion Energy Gas' earnings and the Companies' liquidity position and the underlying value of their assets;
Counterparty credit and performance risk;
Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;
Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;
Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion Energy and Virginia Power and in benefit plan trusts by Dominion Energy and Dominion Energy Gas;
Fluctuations in interest rates or foreign currency exchange rates;
Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;
Changes in financial or regulatory accounting principles or policies imposed by governing bodies;
Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;
Risks of operating businesses in regulated industries that are subject to changing regulatory structures;
Impacts of acquisitions, including the Dominion Energy Questar Combination, divestitures, transfers of assets to joint ventures or Dominion Energy Midstream, including the contribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream, and retirements of assets based on asset portfolio reviews;
Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;
The timing and execution of Dominion Energy Midstream's growth strategy;
Changes in rules for regional transmission organizations and independent system operators in which Dominion Energy and Virginia Power participate, including changes in rate designs, changes in FERC's interpretation of market rules and new and evolving capacity models;
Political and economic conditions, including inflation and deflation;
Domestic terrorism and other threats to the Companies' physical and intangible assets, as well as threats to cybersecurity;
Changes in demand for the Companies' services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy and Dominion Energy Gas' pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;
Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;
Competition in the development, construction and ownership of certain electric transmission facilities in Virginia Power's service territory in connection with FERC Order 1000;
Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;
Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas;
Changes in operating, maintenance and construction costs;
Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals;
The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated;
• | The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events; |
• | Domestic terrorism and other threats to Eastern Energy’s physical and intangible assets, as well as threats to cybersecurity; |
• | Additional competition in industries in which Eastern Energy operates; |
• | Changes in demand for Eastern Energy’s services, including industrial, commercial and residential growth or decline in Eastern Energy’s service areas, changes in supplies of natural gas delivered to Eastern Energy’s pipeline systems, failure to maintain or replace customer contracts on favorable terms and changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices; |
• | Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures; |
• | Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews; |
• | Adverse outcomes in litigation matters or regulatory proceedings; |
• | Counterparty credit and performance risk; |
• | Fluctuations in interest rates or foreign currency exchange rates; |
• | Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital; |
• | Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; |
The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events.
• | Political and economic conditions, including inflation and deflation; |
• | Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and |
• | Changes in financial or regulatory accounting principles or policies imposed by governing bodies. |
Additionally, other risks that could cause actual results to differ from predicted results are set forth in Part I. Item 1A. Risk Factors in the Companies'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016.2019 and Part II. Item 1A. Risk Factors in Eastern Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.
The Companies'Eastern Energy’s forward-looking statements are based on beliefs and assumptions using information available at the time the statements are made. The Companies cautionEastern Energy cautions the reader not to place undue reliance on theirits forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. The Companies undertakeEastern Energy undertakes no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.
Accounting Matters
Critical Accounting Policies and Estimates
As of September 30, 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.
Dominion Energy
Results of Operations
Presented below is a summary of DominionEastern Energy’s consolidated results:
|
| 2017 |
|
| 2016 |
|
| $ Change |
| |||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
Third Quarter |
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Dominion Energy |
| $ | 665 |
|
| $ | 690 |
|
| $ | (25 | ) |
Diluted EPS |
|
| 1.03 |
|
|
| 1.10 |
|
|
| (0.07 | ) |
Year-To-Date |
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Dominion Energy |
| $ | 1,687 |
|
| $ | 1,666 |
|
| $ | 21 |
|
Diluted EPS |
|
| 2.66 |
|
|
| 2.71 |
|
|
| (0.05 | ) |
|
| Third Quarter |
|
| Year-To-Date |
| ||||||||||||||||||
|
| 2020 |
|
| 2019 |
|
| $ Change |
|
| 2020 |
|
| 2019 |
|
| $ Change |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Eastern Energy |
| $ | 86 |
|
| $ | 151 |
|
| $ | (65 | ) |
| $ | 57 |
|
| $ | 460 |
|
| $ | (403 | ) |
Overview
Third Quarter 20172020 vs. 20162019
Net income attributable to DominionEastern Energy decreased 4%43%, primarily due to lower anticipated renewable energy investmenta charge for cash flow hedges of debt-related items that are probable of not occurring as a result of the GT&S Transaction and the absence of net income from discontinued operations related to the Dominion Energy Gas Restructuring. These decreases were partially offset by an adjustment to finalize the effects of the changes in tax status in connection with the Dominion Energy Gas Restructuring and the absence of credits milder weather during 2017 inassociated with the start-up phase of the Liquefaction Facility.
Year-To-Date 2020 vs. 2019
32
Net income attributable to Eastern Energy decreased 88%, primarily due to charges associated with the probable abandonment of a significant portion of the Supply Header Project related to the Atlantic Coast Pipeline Project, the absence of net income from discontinued operations related to the Dominion Energy’s electric utility service territoryEnergy Gas Restructuring and a decrease in Cove Point import contracts.charge for cash flow hedges of debt-related items that are probable of not occurring as a result of the GT&S Transaction. These decreases were partially offset by the Dominion Energy Questar Combinationabsence of a charge related to a voluntary retirement program and an increaseadjustment to finalize the effects of the changes in gains from agreements to convey shale development rights underneath several natural gas storage fields.
Year-To-Date 2017 vs. 2016
Net income attributable to Dominion Energy increased 1%, primarily due totax status in connection with the Dominion Energy Questar Combination, an electric utility capacity benefit and the absence of 2016 organizational design initiative costs. These increases were substantially offset by lower anticipated renewable energy investment tax credits, an increase in interest expense, milder weather in Dominion Energy’s electric utility service territory and a decrease in Cove Point import contracts.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion Energy’s results of operations:
| Third Quarter |
|
| Year-To-Date |
| |||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| $ Change |
|
| 2017 |
|
| 2016 |
|
| $ Change |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 3,179 |
|
| $ | 3,132 |
|
| $ | 47 |
|
| $ | 9,376 |
|
| $ | 8,651 |
|
| $ | 725 |
|
Electric fuel and other energy-related purchases |
|
| 638 |
|
|
| 606 |
|
|
| 32 |
|
|
| 1,711 |
|
|
| 1,791 |
|
|
| (80 | ) |
Purchased (excess) electric capacity |
|
| 21 |
|
|
| (6 | ) |
|
| 27 |
|
|
| (8 | ) |
|
| 107 |
|
|
| (115 | ) |
Purchased gas |
|
| 24 |
|
|
| 77 |
|
|
| (53 | ) |
|
| 441 |
|
|
| 252 |
|
|
| 189 |
|
Net revenue |
|
| 2,496 |
|
|
| 2,455 |
|
|
| 41 |
|
|
| 7,232 |
|
|
| 6,501 |
|
|
| 731 |
|
Other operations and maintenance |
|
| 649 |
|
|
| 765 |
|
|
| (116 | ) |
|
| 2,166 |
|
|
| 2,133 |
|
|
| 33 |
|
Depreciation, depletion and amortization |
|
| 485 |
|
|
| 400 |
|
|
| 85 |
|
|
| 1,421 |
|
|
| 1,112 |
|
|
| 309 |
|
Other taxes |
|
| 162 |
|
|
| 145 |
|
|
| 17 |
|
|
| 519 |
|
|
| 448 |
|
|
| 71 |
|
Other income |
|
| 73 |
|
|
| 63 |
|
|
| 10 |
|
|
| 249 |
|
|
| 189 |
|
|
| 60 |
|
Interest and related charges |
|
| 305 |
|
|
| 250 |
|
|
| 55 |
|
|
| 905 |
|
|
| 715 |
|
|
| 190 |
|
Income tax expense |
|
| 272 |
|
|
| 230 |
|
|
| 42 |
|
|
| 683 |
|
|
| 561 |
|
|
| 122 |
|
Noncontrolling interests |
|
| 31 |
|
|
| 38 |
|
|
| (7 | ) |
|
| 100 |
|
|
| 55 |
|
|
| 45 |
|
An analysis of Dominion Energy’s results of operations follows:
Third Quarter 2017 vs. 2016
Net revenue increased 2%, primarily reflecting:
A $161 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017;
A $29 million increase due to additional generation output from merchant solar generating projects; and
A $16 million increase from regulated natural gas transmission growth projects placed into service; partially offset by
A $76 million decrease in sales to electric utility retail customers from a decrease in cooling degree days;
A $41 million decrease from Cove Point import contracts;
A $24 million increase in electric capacity related expenses due to the annual PJM capacity performance market effective June 2017 ($68 million), partially offset by a benefit related to non-utility generators ($44 million); and
A $20 million decrease due to unfavorable pricing at merchant generation facilities.
Other operations and maintenance decreased 15%, primarily reflecting:
A $56 million increase in gains from agreements to convey shale development rights underneath several natural gas storage fields;
A $30 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;
A $26 million decrease in transaction and transition costs related to the Dominion Energy Questar Combination; and
A $21 million decrease due to the absence of costs related to 2016 labor contract renegotiations as well as costs resulting from a union workforce temporary work stoppage; partially offset by
A $45 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017.
Depreciation, depletion and amortization increased 21%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($47 million) and various growth projects being placed into service ($40 million).
Interest and related charges increased 22%, primarily due to higher long-term debt interest expense resulting from debt issuances in the fourth quarter of 2016 and the first nine months of 2017($41 million) and debt acquired in the Dominion Energy Questar Combination ($11 million).
Income tax expense increased 18%, primarily due to an increased effective tax rate, principally due to lower anticipated renewable energy investment tax credits.
Noncontrolling interests decreased 18% primarily due to a decrease in earnings attributable to merchant solar partners ($22 million), partially offset by an increase in Dominion Energy Midstream earnings attributable to public unit holders ($15 million).
Year-To-Date 2017 vs. 2016
Net revenue increased 11%, primarily reflecting:
A $663 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017;
A $119 million electric capacity benefit due to the annual PJM capacity performance market effective June 2016 ($123 million) and a benefit related to non-utility generators ($86 million), partially offset by the annual PJM capacity performance market effective June 2017 ($90 million);
A $74 million increase due to additional generation output from merchant solar generating projects;
A $57 million increase in sales to electric utility retail customers due to the effect of changes in customer usage and other factors;
A $49 million increase from regulated natural gas transmission growth projects placed into service; and
A $36 million increase from rate adjustment clauses associated with electric utility operations; partially offset by
A $109 million decrease due to unfavorable pricing at merchant generation facilities;
A $104 million decrease from Cove Point import contracts; and
A decrease in sales to electric utility retail customers from a reduction in heating degree days during the heating season of 2017 ($52 million) and a decrease in cooling degree days during the cooling season of 2017 ($53 million).
Other operations and maintenance increased 2%, primarily reflecting:
A $162 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017; and
A $35 million increase in salaries, wages and benefits; partially offset by
An $88 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income; and
The absence of organizational design initiative costs ($64 million).
Depreciation, depletion and amortization increased 28%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($162 million) and various growth projects being placed into service ($120 million).
Other taxes increased 16%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($35 million) and increased property taxes related to growth projects placed into service ($31 million).
Other income increased 32%, primarily reflecting:
A $26 million increase in earnings from equity method investments;
A $19 million increase in AFUDC associated with rate-regulated projects;
An $11 million increase in interest income associated with the settlement of state income tax refund claims; and
An $11 million increase in net realized gains (including investment income) on nuclear decommissioning trust funds.
Interest and related charges increased 27%, primarily due to higher long-term debt interest expense resulting from debt issuances in 2016 and the first nine months of 2017 ($148 million) and debt acquired in the Dominion Energy Questar Combination ($39 million).
Income tax expense increased 22%, primarily due to higher pre-tax income and an increased effective tax rate, principally due to lower anticipated renewable energy investment tax credits.
Noncontrolling interests increased 82%, primarily due to an increase in Dominion Energy Midstream earnings attributable to public unitholders.
Segment Results of Operations
Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. In connection with its corporate rebranding in May 2017, Dominion Energy changed the names of its principal operating segments to Power Delivery, Power Generation and Gas Infrastructure from Dominion Virginia Power, Dominion Generation and Dominion Energy, respectively. Presented below is a summary of contributions by Dominion Energy’s operating segments to net income attributable to Dominion Energy:
|
| Net Income attributable to Dominion Energy |
|
| Diluted EPS |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| $ Change |
|
| 2017 |
|
| 2016 |
|
| $ Change |
| ||||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power Delivery |
| $ | 138 |
|
| $ | 139 |
|
| $ | (1 | ) |
| $ | 0.21 |
|
| $ | 0.22 |
|
| $ | (0.01 | ) |
Power Generation |
|
| 369 |
|
|
| 650 |
|
|
| (281 | ) |
|
| 0.57 |
|
|
| 1.04 |
|
|
| (0.47 | ) |
Gas Infrastructure |
|
| 187 |
|
|
| 135 |
|
|
| 52 |
|
|
| 0.29 |
|
|
| 0.21 |
|
|
| 0.08 |
|
Primary operating segments |
|
| 694 |
|
|
| 924 |
|
|
| (230 | ) |
|
| 1.07 |
|
|
| 1.47 |
|
|
| (0.40 | ) |
Corporate and Other |
|
| (29 | ) |
|
| (234 | ) |
|
| 205 |
|
|
| (0.04 | ) |
|
| (0.37 | ) |
|
| 0.33 |
|
Consolidated |
| $ | 665 |
|
| $ | 690 |
|
| $ | (25 | ) |
| $ | 1.03 |
|
| $ | 1.10 |
|
| $ | (0.07 | ) |
Year-To-Date |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power Delivery |
| $ | 390 |
|
| $ | 363 |
|
| $ | 27 |
|
| $ | 0.62 |
|
| $ | 0.59 |
|
| $ | 0.03 |
|
Power Generation |
|
| 870 |
|
|
| 1,066 |
|
|
| (196 | ) |
|
| 1.37 |
|
|
| 1.74 |
|
|
| (0.37 | ) |
Gas Infrastructure |
|
| 613 |
|
|
| 483 |
|
|
| 130 |
|
|
| 0.97 |
|
|
| 0.78 |
|
|
| 0.19 |
|
Primary operating segments |
|
| 1,873 |
|
|
| 1,912 |
|
|
| (39 | ) |
|
| 2.96 |
|
|
| 3.11 |
|
|
| (0.15 | ) |
Corporate and Other |
|
| (186 | ) |
|
| (246 | ) |
|
| 60 |
|
|
| (0.30 | ) |
|
| (0.40 | ) |
|
| 0.10 |
|
Consolidated |
| $ | 1,687 |
|
| $ | 1,666 |
|
| $ | 21 |
|
| $ | 2.66 |
|
| $ | 2.71 |
|
| $ | (0.05 | ) |
Power Delivery
Presented below are selected operating statistics related to Power Delivery’s operations:
|
| Third Quarter |
|
| Year-To-Date |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| % Change |
|
| 2017 |
|
| 2016 |
|
| % Change |
| ||||||
Electricity delivered (million MWh) |
|
| 23.0 |
|
|
| 24.1 |
|
|
| (5 | )% |
|
| 63.2 |
|
|
| 64.2 |
|
|
| (2 | )% |
Degree days (electric distribution service area): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cooling |
|
| 1,124 |
|
|
| 1,326 |
|
|
| (15 | ) |
|
| 1,698 |
|
|
| 1,755 |
|
|
| (3 | ) |
Heating |
|
| 2 |
|
|
| — |
|
|
| 100 |
|
|
| 1,825 |
|
|
| 2,247 |
|
|
| (19 | ) |
Average electric distribution customer accounts (thousands)(1) |
|
| 2,576 |
|
|
| 2,552 |
|
|
| 1 |
|
|
| 2,570 |
|
|
| 2,546 |
|
|
| 1 |
|
|
|
Presented below, on an after-tax basis, are the key factors impacting Power Delivery’s net income contribution:
|
| Third Quarter 2017 vs. 2016 Increase (Decrease) |
|
| Year-To-Date 2017 vs. 2016 Increase (Decrease) |
| ||||||||||
|
| Amount |
|
| EPS |
|
| Amount |
|
| EPS |
| ||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated electric sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weather |
| $ | (13 | ) |
| $ | (0.02 | ) |
| $ | (19 | ) |
| $ | (0.03 | ) |
Other |
|
| 1 |
|
|
| — |
|
|
| 12 |
|
|
| 0.02 |
|
FERC transmission equity return |
|
| 5 |
|
|
| 0.01 |
|
|
| 14 |
|
|
| 0.02 |
|
Storm damage and service restoration |
|
| 3 |
|
|
| — |
|
|
| 17 |
|
|
| 0.03 |
|
Other |
|
| 3 |
|
|
| — |
|
|
| 3 |
|
|
| — |
|
Share dilution |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.01 | ) |
Change in net income contribution |
| $ | (1 | ) |
| $ | (0.01 | ) |
| $ | 27 |
|
| $ | 0.03 |
|
Power Generation
Presented below are selected operating statistics related to Power Generation’s operations:
|
| Third Quarter |
|
| Year-To-Date |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| % Change |
|
| 2017 |
|
| 2016 |
|
| % Change |
| ||||||
Electricity supplied (million MWh): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility |
|
| 23.1 |
|
|
| 24.8 |
|
|
| (7 | )% |
|
| 64.7 |
|
|
| 67.1 |
|
|
| (4 | )% |
Merchant |
|
| 7.9 |
|
|
| 7.9 |
|
|
| — |
|
|
| 22.7 |
|
|
| 21.2 |
|
|
| 7 |
|
Degree days (electric utility service area): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cooling |
|
| 1,124 |
|
|
| 1,326 |
|
|
| (15 | ) |
|
| 1,698 |
|
|
| 1,755 |
|
|
| (3 | ) |
Heating |
|
| 2 |
|
|
| — |
|
| 100 |
|
|
| 1,825 |
|
|
| 2,247 |
|
|
| (19 | ) | |
Presented below, on an after-tax basis, are the key factors impacting Power Generation’s net income contribution:
|
| Third Quarter 2017 vs. 2016 Increase (Decrease) |
|
| Year-To-Date 2017 vs. 2016 Increase (Decrease) |
| ||||||||||
|
| Amount |
|
| EPS |
|
| Amount |
|
| EPS |
| ||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated electric sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weather |
| $ | (33 | ) |
| $ | (0.05 | ) |
| $ | (45 | ) |
| $ | (0.07 | ) |
Other |
|
| 6 |
|
|
| 0.01 |
|
|
| 27 |
|
|
| 0.04 |
|
Electric capacity |
|
| (16 | ) |
|
| (0.03 | ) |
|
| 70 |
|
|
| 0.11 |
|
Renewable energy investment tax credits(1) |
|
| (242 | ) |
|
| (0.39 | ) |
|
| (187 | ) |
|
| (0.31 | ) |
Merchant generation margin |
|
| 6 |
|
|
| 0.01 |
|
|
| (9 | ) |
|
| (0.02 | ) |
Noncontrolling interests(2) |
|
| 14 |
|
|
| 0.02 |
|
|
| 1 |
|
|
| — |
|
Depreciation and amortization |
|
| (12 | ) |
|
| (0.02 | ) |
|
| (38 | ) |
|
| (0.06 | ) |
Other |
|
| (4 | ) |
|
| (0.01 | ) |
|
| (15 | ) |
|
| (0.02 | ) |
Share dilution |
|
| — |
|
|
| (0.01 | ) |
|
| — |
|
|
| (0.04 | ) |
Change in net income contribution |
| $ | (281 | ) |
| $ | (0.47 | ) |
| $ | (196 | ) |
| $ | (0.37 | ) |
|
|
|
|
Presented below are selected operating statistics related to Gas Infrastructure’s operations:
|
| Third Quarter |
|
| Year-To-Date |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| % Change |
|
| 2017 |
|
| 2016 |
|
| % Change |
| ||||||
Gas distribution throughput (bcf)(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
| 10 |
|
|
| 2 |
|
|
| 400 | % |
|
| 85 |
|
|
| 18 |
|
|
| 372 | % |
Transportation |
|
| 143 |
|
|
| 106 |
|
|
| 35 |
|
|
| 469 |
|
|
| 364 |
|
|
| 29 |
|
Heating degree days (gas distribution service area): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eastern region |
|
| 66 |
|
|
| 22 |
|
|
| 200 |
|
|
| 2,940 |
|
|
| 3,435 |
|
|
| (14 | ) |
Western region(1) |
|
| 131 |
|
|
| 39 |
|
|
| 236 |
|
|
| 3,024 |
|
|
| 39 |
|
|
| 7,654 |
|
Average gas distribution customer accounts (thousands)(1)(2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
| 1,234 |
|
|
| 472 |
|
|
| 161 |
|
|
| 1,234 |
|
|
| 329 |
|
|
| 275 |
|
Transportation |
|
| 1,082 |
|
|
| 1,069 |
|
|
| 1 |
|
|
| 1,089 |
|
|
| 1,072 |
|
|
| 2 |
|
Average retail energy marketing customer accounts (thousands)(2) |
|
| 1,463 |
|
|
| 1,377 |
|
|
| 6 |
|
|
| 1,447 |
|
|
| 1,368 |
|
|
| 6 |
|
|
|
|
|
Presented below, on an after-tax basis, are the key factors impacting Gas Infrastructure’s net income contribution:
|
| Third Quarter 2017 vs. 2016 Increase (Decrease) |
|
| Year-To-Date 2017 vs. 2016 Increase (Decrease) |
| ||||||||||
|
| Amount |
|
| EPS |
|
| Amount |
|
| EPS |
| ||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy Questar Combination |
| $ | 34 |
|
| $ | 0.05 |
|
| $ | 184 |
|
| $ | 0.30 |
|
Assignment of Marcellus acreage |
|
| 33 |
|
|
| 0.05 |
|
|
| 7 |
|
|
| 0.01 |
|
Cove Point import contracts |
|
| (27 | ) |
|
| (0.04 | ) |
|
| (63 | ) |
|
| (0.10 | ) |
Noncontrolling interests(1) |
|
| (9 | ) |
|
| (0.01 | ) |
|
| (28 | ) |
|
| (0.04 | ) |
Transportation and storage growth projects |
|
| 7 |
|
|
| 0.01 |
|
|
| 23 |
|
|
| 0.04 |
|
Other |
|
| 14 |
|
|
| 0.02 |
|
|
| 7 |
|
|
| 0.01 |
|
Share dilution |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.03 | ) |
Change in net income contribution |
| $ | 52 |
|
| $ | 0.08 |
|
| $ | 130 |
|
| $ | 0.19 |
|
|
|
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results:
|
| Third Quarter |
|
| Year-To-Date |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| $ Change |
|
| 2017 |
|
| 2016 |
|
| $ Change |
| ||||||
(millions, except EPS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Specific items attributable to operating segments |
| $ | — |
|
| $ | 4 |
|
| $ | (4 | ) |
| $ | (1 | ) |
| $ | (22 | ) |
| $ | 21 |
|
Specific items attributable to corporate operations |
|
| (7 | ) |
|
| (30 | ) |
|
| 23 |
|
|
| (16 | ) |
|
| (41 | ) |
|
| 25 |
|
Total specific items |
|
| (7 | ) |
|
| (26 | ) |
|
| 19 |
|
|
| (17 | ) |
|
| (63 | ) |
|
| 46 |
|
Other corporate operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Renewable energy investment tax credits |
|
| 52 |
|
|
| (143 | ) |
|
| 195 |
|
|
| 79 |
|
|
| (11 | ) |
|
| 90 |
|
Interest expense, net |
|
| (85 | ) |
|
| (63 | ) |
|
| (22 | ) |
|
| (258 | ) |
|
| (191 | ) |
|
| (67 | ) |
Other |
|
| 11 |
|
|
| (2 | ) |
|
| 13 |
|
|
| 10 |
|
|
| 19 |
|
|
| (9 | ) |
Total other corporate operations |
|
| (22 | ) |
|
| (208 | ) |
|
| 186 |
|
|
| (169 | ) |
|
| (183 | ) |
|
| 14 |
|
Total net expense |
| $ | (29 | ) |
| $ | (234 | ) |
| $ | 205 |
|
| $ | (186 | ) |
| $ | (246 | ) |
| $ | 60 |
|
EPS impact |
| $ | (0.04 | ) |
| $ | (0.37 | ) |
| $ | 0.33 |
|
| $ | (0.30 | ) |
| $ | (0.40 | ) |
| $ | 0.10 |
|
Corporate and Other includes specific items attributable to Dominion Energy'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.
Virginia Power
Results of Operations
Presented below is a summary of Virginia Power’s consolidated results:
|
| Third Quarter |
|
| Year-To-Date |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| $ Change |
|
| 2017 |
|
| 2016 |
|
| $ Change |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
| $ | 459 |
|
| $ | 503 |
|
| $ | (44 | ) |
| $ | 1,133 |
|
| $ | 1,046 |
|
| $ | 87 |
|
Overview
Third Quarter 2017 vs. 2016
Net income decreased 9%, primarily due to milder weather during 2017 and the annual PJM capacity performance market effective June 2017, partially offset by a benefit related to non-utility generators.
Year-To-Date 2017 vs. 2016
Net income increased 8%, primarily due to the PJM capacity performance market, a benefit related to non-utility generators, an increase in customer usage and other factors and the absence of organizational design initiative costs, partially offset by milder weather during 2017.Restructuring.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Power’sEastern Energy’s results of operations:
|
| Third Quarter |
|
| Year-To-Date |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| $ Change |
|
| 2017 |
|
| 2016 |
|
| $ Change |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 2,154 |
|
| $ | 2,211 |
|
| $ | (57 | ) |
| $ | 5,732 |
|
| $ | 5,877 |
|
| $ | (145 | ) |
Electric fuel and other energy-related purchases |
|
| 549 |
|
|
| 516 |
|
|
| 33 |
|
|
| 1,414 |
|
|
| 1,527 |
|
|
| (113 | ) |
Purchased (excess) electric capacity |
|
| 21 |
|
|
| (6 | ) |
|
| 27 |
|
|
| (8 | ) |
|
| 107 |
|
|
| (115 | ) |
Net revenue |
|
| 1,584 |
|
|
| 1,701 |
|
|
| (117 | ) |
|
| 4,326 |
|
|
| 4,243 |
|
|
| 83 |
|
Other operations and maintenance |
|
| 373 |
|
|
| 443 |
|
|
| (70 | ) |
|
| 1,126 |
|
|
| 1,279 |
|
|
| (153 | ) |
Depreciation and amortization |
|
| 288 |
|
|
| 270 |
|
|
| 18 |
|
|
| 854 |
|
|
| 765 |
|
|
| 89 |
|
Other taxes |
|
| 76 |
|
|
| 74 |
|
|
| 2 |
|
|
| 233 |
|
|
| 218 |
|
|
| 15 |
|
Other income |
|
| 13 |
|
|
| 13 |
|
|
| — |
|
|
| 57 |
|
|
| 47 |
|
|
| 10 |
|
Interest and related charges |
|
| 128 |
|
|
| 118 |
|
|
| 10 |
|
|
| 373 |
|
|
| 345 |
|
|
| 28 |
|
Income tax expense |
|
| 273 |
|
|
| 306 |
|
|
| (33 | ) |
|
| 664 |
|
|
| 637 |
|
|
| 27 |
|
An analysis of Virginia Power’s results of operations follows:
Third Quarter 2017 vs. 2016
Net revenue decreased 7%, primarily reflecting:
A $76 million decrease in sales to retail customers from a decrease in cooling degree days; and
A $24 million increase in electric capacity related expenses due to the annual PJM capacity performance market effective June 2017 ($68 million), partially offset by a benefit related to non-utility generators ($44 million).
Other operations and maintenance decreased 16%, primarily reflecting:
A $30 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;
An $11 million decrease due to the absence of 2016 union workforce contract renegotiations; and
A $9 million decrease in outside services due to the absence of certain utility projects.
Income tax expense decreased 11%, primarily due to lower pre-tax income.
Year-To-Date 2017 vs. 2016
Net revenue increased 2%, primarily reflecting:
A $119 million electric capacity benefit due to the annual PJM capacity performance market effective June 2016 ($123 million) and a benefit related to non-utility generators ($86 million), partially offset by the annual PJM capacity performance market effective June 2017 ($90 million);
An increase in sales to retail customers due to the effect of changes in customer usage and other factors ($57 million); and
An increase from rate adjustment clauses ($36 million); partially offset by
A decrease in sales to retail customers from a reduction in heating degree days during the heating season of 2017 ($52 million) and a decrease in cooling degree days during the cooling season of 2017 ($53 million).
Other operations and maintenance decreased 12%, primarily reflecting:
An $88 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;
The absence of organizational design initiative costs ($32 million); and
A $28 million decrease in storm damage and service restoration costs.
Depreciation and amortization increased 12%, primarily due to various growth projects being placed into service ($48 million) and revised depreciation rates ($32 million).
Other income increased 21%, primarily reflecting:
An $11 million increase in interest income associated with the settlement of state income tax refund claims; and
A $10 million increase from the assignment of Virginia Power’s electric transmission tower rental portfolio; partially offset by
A $16 million charge associated with a customer settlement.
Results of Operations
Presented below is a summary of Dominion Energy Gas' consolidated results:
|
| Third Quarter |
|
| Year-To-Date |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| $ Change |
|
| 2017 |
|
| 2016 |
|
| $ Change |
| ||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
| $ | 117 |
|
| $ | 83 |
|
| $ | 34 |
|
| $ | 302 |
|
| $ | 286 |
|
| $ | 16 |
|
Overview
Third Quarter 2017 vs. 2016
Net income increased 41%, primarily due to gains from agreements to convey shale development rights underneath several natural gas storage fields.
Year-To-Date 2017 vs. 2016
Net income increased 6%, primarily due to gas transportation and storage activities from growth projects placed into service.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion Energy Gas' results of operations:
|
| Third Quarter |
|
| Year-To-Date |
|
| Third Quarter |
|
| Year-To-Date |
| ||||||||||||||||||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| $ Change |
|
| 2017 |
|
| 2016 |
|
| $ Change |
|
| 2020 |
|
| 2019 |
|
| $ Change |
|
| 2020 |
|
| 2019 |
|
| $ Change |
| ||||||||||||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
| $ | 401 |
|
| $ | 382 |
|
| $ | 19 |
|
| $ | 1,313 |
|
| $ | 1,181 |
|
| $ | 132 |
|
| $ | 531 |
|
| $ | 502 |
|
| $ | 29 |
|
| $ | 1,597 |
|
| $ | 1,598 |
|
| $ | (1 | ) |
Purchased gas |
|
| 19 |
|
|
| 21 |
|
|
| (2 | ) |
|
| 100 |
|
|
| 71 |
|
|
| 29 |
|
|
| 14 |
|
|
| 3 |
|
|
| 11 |
|
|
| 22 |
|
|
| 12 |
|
|
| 10 |
|
Other energy-related purchases |
|
| 4 |
|
|
| 4 |
|
|
| — |
|
|
| 11 |
|
|
| 8 |
|
|
| 3 |
|
|
| — |
|
|
| 1 |
|
|
| (1 | ) |
|
| 1 |
|
|
| 2 |
|
|
| (1 | ) |
Net revenue |
|
| 378 |
|
|
| 357 |
|
|
| 21 |
|
|
| 1,202 |
|
|
| 1,102 |
|
|
| 100 |
|
|
| 517 |
|
|
| 498 |
|
|
| 19 |
|
|
| 1,574 |
|
|
| 1,584 |
|
|
| (10 | ) |
Other operations and maintenance |
|
| 73 |
|
|
| 133 |
|
|
| (60 | ) |
|
| 377 |
|
|
| 331 |
|
|
| 46 |
|
|
| 136 |
|
|
| 166 |
|
|
| (30 | ) |
|
| 451 |
|
|
| 552 |
|
|
| (101 | ) |
Depreciation and amortization |
|
| 57 |
|
|
| 55 |
|
|
| 2 |
|
|
| 167 |
|
|
| 150 |
|
|
| 17 |
|
|
| 95 |
|
|
| 92 |
|
|
| 3 |
|
|
| 282 |
|
|
| 274 |
|
|
| 8 |
|
Other taxes |
|
| 42 |
|
|
| 36 |
|
|
| 6 |
|
|
| 139 |
|
|
| 127 |
|
|
| 12 |
|
|
| 40 |
|
|
| 40 |
|
|
| — |
|
|
| 117 |
|
|
| 118 |
|
|
| (1 | ) |
Earnings from equity method investee |
|
| 4 |
|
|
| 5 |
|
|
| (1 | ) |
|
| 15 |
|
|
| 14 |
|
|
| 1 |
| ||||||||||||||||||||||||
Impairment of assets and other charges (benefits) |
|
| (19 | ) |
|
| — |
|
|
| (19 | ) |
|
| 463 |
|
|
| 13 |
|
|
| 450 |
| ||||||||||||||||||||||||
Gains on sales of assets |
|
| — |
|
|
| (2 | ) |
|
| 2 |
|
|
| — |
|
|
| (2 | ) |
|
| 2 |
| ||||||||||||||||||||||||
Earnings from equity method investees |
|
| 7 |
|
|
| 8 |
|
|
| (1 | ) |
|
| 30 |
|
|
| 30 |
|
|
| — |
| ||||||||||||||||||||||||
Other income |
|
| 6 |
|
|
| 2 |
|
|
| 4 |
|
|
| 16 |
|
|
| 8 |
|
|
| 8 |
|
|
| 22 |
|
|
| 46 |
|
|
| (24 | ) |
|
| 117 |
|
|
| 131 |
|
|
| (14 | ) |
Interest and related charges |
|
| 25 |
|
|
| 23 |
|
|
| 2 |
|
|
| 72 |
|
|
| 68 |
|
|
| 4 |
|
|
| 186 |
|
|
| 88 |
|
|
| 98 |
|
|
| 294 |
|
|
| 261 |
|
|
| 33 |
|
Income tax expense |
|
| 74 |
|
|
| 34 |
|
|
| 40 |
|
|
| 176 |
|
|
| 162 |
|
|
| 14 |
| ||||||||||||||||||||||||
Income tax expense (benefit) |
|
| (10 | ) |
|
| 38 |
|
|
| (48 | ) |
|
| (40 | ) |
|
| 104 |
|
|
| (144 | ) | ||||||||||||||||||||||||
Net income from discontinued operations |
|
| — |
|
|
| 45 |
|
|
| (45 | ) |
|
| — |
|
|
| 125 |
|
|
| (125 | ) | ||||||||||||||||||||||||
Noncontrolling interests |
|
| 32 |
|
|
| 24 |
|
|
| 8 |
|
|
| 97 |
|
|
| 90 |
|
|
| 7 |
| ||||||||||||||||||||||||
An analysis of Dominion Energy Gas'Eastern Energy’s results of operations follows:
Third Quarter 20172020 vs. 20162019
Net revenue increased 6%4%, primarily reflecting:
• | The absence of credits associated with the start-up phase of the Liquefaction Facility ($23 million); and |
• | A $14 million decrease in net fuel costs primarily due to an increase in regulated gas sales; partially offset by |
• | A $17 million decrease in services performed for Atlantic Coast Pipeline; and |
• | A $6 million decrease in services provided to affiliates. |
A $13
Other operations and maintenance decreased 18%, due to a $17 million increase from regulated natural gas transmission growth projects placed into service;
A $6 million increase in PIR program revenues; and
A $6 million increasedecrease in services performed for Atlantic Coast Pipeline.
Other operations and maintenance decreased 45%, primarily reflecting:
The increase in gains from agreements to convey shale development rights underneath several natural gas storage fields ($56 million); and
The absence ofPipeline, a union workforce temporary work stoppage ($8 million); partially offset by
A $5 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income.
Other taxes increased 17% primarily due to an increase in property taxes related to growth projects placed into service.
Income tax expense increased by $40 million due to higher pre-tax income ($28 million) and the absence of a 2016 settlement with a tax authority ($12 million).
Year-To-Date 2017 vs. 2016
Net revenue increased 9%, primarily reflecting:
A $38 million increase from regulated natural gas transmission growth projects placed into service;
A $22 million increase in services performed for Atlantic Coast Pipeline;
An $18 million increase in PIR program revenues; and
A $17 million increase in rate recovery for low income assistance programs associated with regulated natural gas distribution operations.
Other operations and maintenance increased 14%, primarily reflecting:
A $21 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;
A $17 million increase in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income;
A $15 million increase due to a charge to write-off the balance of a regulatory asset no longer considered probable of recovery; and
An $11 million increasedecrease in salaries, wages and benefits and generala $5 million decrease in services provided by affiliates.
Impairment of assets and administrative expenses;other charges (benefits) decreased $19 million, due to a $29 million benefit from the revision of the previously established ARO, partially offset by
A $16 a $10 million increase in gains from agreementscharge, both of which were related to convey shale development rights underneath several natural gas storage fields;
The absence of organizational design initiative costs ($10 million); and
The absencethe probable abandonment of a union workforce temporary work stoppage ($8 million).
significant portion of the Supply Header Project.
Other income increased by $8 million primarily due to an increase in AFUDC associated with rate-regulated projects ($12 million), partially offset by the absence of a gain on the 2016 sale of a portion of Dominion Energy Gas’ interest in Iroquois ($5 million).
Liquidity and Capital Resources
Dominion Energy 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 September 30, 2017, Dominion Energy had $2.4 billion of unused capacity under its credit facilities. See Note 14 to the Consolidated Financial Statements for more information.
A summary of Dominion Energy’s cash flows is presented below:
|
| 2017 |
|
| 2016 |
| ||
(millions) |
|
|
|
|
|
|
|
|
Cash and cash equivalents at January 1 |
| $ | 261 |
|
| $ | 607 |
|
Cash flows provided by (used in): |
|
|
|
|
|
|
|
|
Operating activities |
|
| 3,664 |
|
|
| 3,386 |
|
Investing activities |
|
| (4,873 | ) |
|
| (9,029 | ) |
Financing activities |
|
| 1,175 |
|
|
| 5,287 |
|
Net decrease in cash and cash equivalents |
|
| (34 | ) |
|
| (356 | ) |
Cash and cash equivalents at September 30 |
| $ | 227 |
|
| $ | 251 |
|
Net cash provided by Dominion Energy’s operating activities increased $278 million, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017, an electric utility capacity benefit, derivative activities and proceeds from the assignment of the electric transmission tower rental portfolio, partially offset by lower deferred fuel cost recoveries in the Virginia jurisdiction, milder weather in Dominion Energy’s electric utility service territory, higher interest expense, lower revenue from Cove Point’s import contracts and Dominion Energy’s contribution to Dominion Energy Questar’s pension plan.
Dominion Energy 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 Energy'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 Energy’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 Energy’s credit exposure as of September 30, 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.
|
| Gross Credit Exposure |
|
| Credit Collateral |
|
| Net Credit Exposure |
| |||
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Investment grade(1) |
| $ | 26 |
|
| $ | — |
|
| $ | 26 |
|
Non-investment grade(2) |
|
| 3 |
|
|
| — |
|
|
| 3 |
|
No external ratings: |
|
|
|
|
|
|
|
|
|
|
|
|
Internally rated—investment grade(3) |
|
| 8 |
|
|
| — |
|
|
| 8 |
|
Internally rated—non-investment grade(4) |
|
| 33 |
|
|
| — |
|
|
| 33 |
|
Total |
| $ | 70 |
|
| $ | — |
|
| $ | 70 |
|
|
|
|
|
|
|
|
|
Investing Cash Flows
Net cash used in Dominion Energy’s investing activities decreased $4.2 billion,52%, primarily due to the absence of the acquisition ofinterest income from Cove Point’s promissory notes receivable from Dominion Energy Questar and decreases in plant construction and other property additions,($28 million), partially offset by an increase in acquisitions of solar development projects and increased investment in Atlantic Coast Pipeline.
Financing Cash Flows and Liquidity
interest income from affiliated notes receivable from Dominion Energy relies on capital markets as significant sources($9 million).
Interest and related charges increased $98 million,primarily due to:
• | A charge for cash flow hedges of debt-related items that are probable of not occurring as a result of the GT&S Transaction ($141 million); and |
33
• | Interest expense on Eastern Energy’s November 2019 senior note issuance ($8 million); partially offset by |
• | The absence of interest expense from Cove Point’s term loan borrowings ($32 million); and |
• | The absence of interest expense from intercompany borrowings as a result of the Dominion Energy Gas Restructuring ($12 million). |
Income tax expense (benefit) decreased $48 million, primarily due to an adjustment to finalize the effects of funding for capital requirements not satisfied by cash provided by its operations. As discussed furtherthe changes in Credit Ratings and Debt Covenantstax status 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 registrationconnection with the SEC for certain issuances.
Dominion Energy currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communicationsGas Restructuring ($24 million) 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 Energy to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.lower pre-tax income ($24 million).
Year-To-Date 2020 vs. 2019
Net cash provided by Dominion Energy's financing activities revenue decreased $4.1 billion,$10 million, primarily reflecting:
• | A $37 million decrease in services performed for Atlantic Coast Pipeline; and |
• | A $14 million decrease in services provided to affiliates; partially offset by |
• | The absence of credits associated with the start-up phase of the Liquefaction Facility ($23 million); and |
• | A $15 million decrease in net fuel costs primarily due to an increase in regulated gas sales. |
Other operations and maintenance decreased 18%, primarily reflecting:
• | A $39 million decrease due to the absence of a charge related to a voluntary retirement program; |
• | A $37 million decrease in services performed for Atlantic Coast Pipeline; and |
• | A $20 million decrease in services provided by affiliates. |
Impairment of assets and other charges (benefits) increased $450 million, due to:
• | A $492 million charge associated with the probable abandonment of a significant portion of the Supply Header Project as well as a $46 million ARO; partially offset by |
• | The absence of a $13 million charge related to the abandonment of the Sweden Valley project. |
Other income decreased 11%, primarily due to the absence of debt and common stock issuances utilized to finance theinterest income from Cove Point’s promissory notes receivable from Dominion Energy Questar Combination.
See Notes 3($82 million), partially offset by interest income from affiliated notes receivable from East Ohio ($33 million) and 14 to the Consolidated Financial Statements in this report for further information regarding Dominion Energy'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 Energy as well($32 million).
Interest and related charges increased 13%,primarily due to:
• | A charge for cash flow hedges of debt-related items that are probable of not occurring as a result of the GT&S Transaction ($141 million); and |
• | Interest expense on Eastern Energy’s November 2019 senior note issuance ($23 million); partially offset by |
• | The absence of interest expense from Cove Point’s term loan borrowings ($100 million); and |
• | The absence of interest expense from intercompany borrowings as a result of the Dominion Energy Gas Restructuring ($33 million). |
Income tax expense (benefit) decreased $144 million, primarily due to lower pre-tax income ($120 million) and an adjustment to finalize the impacteffects of credit ratings on the accessibility and costs of using these markets. As of September 30, 2017, there have been no changes in Dominion Energy'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 Energy's debt. As of September 30, 2017, there have been no material changes to debt covenants, nor any events of default under Dominion Energy's debt covenants. Pursuant to a waiver received in April 2016 andtax status in connection with the closing of the Dominion Energy Questar Combination, the 65% maximum debt to total capital ratio in Dominion Energy’s credit agreements was, with respect to Dominion Energy only, temporarily increased to 70% through the fiscal quarter ended June 30, 2017. Effective July 2017, the maximum debt to total capital ratio in Dominion Energy’s credit agreements was reset to 65%.
Future Cash Payments for Contractual Obligations and Planned Capital Expenditures
As of September 30, 2017, there have been no material changes outside the ordinary course of business to Dominion Energy'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 September 30, 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 Energy’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 and Future Issues and Other Matters in MD&A in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017.
Environmental Matters
Dominion Energy is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. See Note 22 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 2016, and Note 15 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017, and in this report for additional information on various environmental matters.
Air
In August 2015, the EPA issued final carbon standards for existing fossil fuel power plants. Known as the Clean Power Plan, the rule uses a set of measures for reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units and expanding renewable resources. The new rule requires states to impose standards of performance limits for existing fossil fuel-fired electric generating units or equivalent statewide intensity-based or mass-based CO2 binding goals or limits. States are required to submit final plans identifying how they will comply with the rule by September 2018. The EPA also issued a proposed federal 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. In June 2017, the Governor of Virginia issued a directive for development of state carbon regulations with a December 2017 deadline for submittal of draft rules to the Virginia State Air Pollution Control Board for approval to notice for public comment. In October 2017, the EPA issued a proposed rule to repeal the Clean Power Plan on the basis that the rule promulgated in 2015 exceeds the EPA’s authority under the CAA. The proposal does not include a replacement rule. The proposal also does not impact the EPA’s regulation of GHG emissions from stationary sources under the CAA permitting programs or the GHG performance standards for new sources, which remain in place. Given these developments and associated federal and state regulatory and legal uncertainties, Dominion Energy cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.
State Actions
In August 2017, the Ozone Transport Commission released a draft model rule for control of NOx emissions from natural gas pipeline compressor fuel-fire prime movers. States within the ozone transport region, including states in which Dominion Energy has natural gas operations, are expected to develop reasonably achievable control technology rules for existing sources based on the Ozone Transport Commission model rule. States outside of the Ozone Transport Commission may also consider the model rules in setting new reasonably achievable control technology standards. Several states in which Dominion Energy operates, including Pennsylvania, New York and Maryland, are moving ahead with state-specific climate change regulations, including methane. Dominion Energy cannot currently estimate the potential financial statements impacts on results of operations, financial condition and/or cash flows related to these matters.
Significant Power Delivery Project
In September 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in Augusta County, Virginia approximately 18 miles of the existing 500 kV transmission line between the Dooms substation and the Valley substation, along with associated substation work, for a total estimated cost of approximately $65 million. This case is pending.
Significant Gas Infrastructure Projects
Eastern Market Access
In November 2016, Cove Point filed an application to request FERC authorization to construct the approximately $150 million Eastern Market Access Project. Construction on the project is expected to begin in the first quarter of 2018, and the project facilities are expected to be placed into service in late 2018.
In October 2017, Atlantic Coast Pipeline received the FERC order authorizing the construction and operation of an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. The project remains subject to other pending federal and state approvals.
Other Matters
While management currently has no plans which may affect the carrying value of Millstone, based on potential future economic and other factors, including, but not limited to, market power prices, results of capacity auctions, legislative and regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free emissions, and the impact of final rules from the EPA and the efforts of states to implement those final rules; there is risk that Millstone may be evaluated for an early retirement date. Should management make any decision on a potential early retirement date, the precise date and the resulting financial statement impacts, which could be material to Dominion Energy, may be affected by a number of factors, including any potential regulatory or legislative solutions, results of any transmission system reliability study assessments, and decommissioning requirements, among other factors.
Legal Matters
See Notes 13 and 22 to the Consolidated Financial Statements and Item 3. Legal Proceedings in the Companies' Annual Report on Form 10-K for the year ended December 31, 2016, Notes 12 and 15 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017, and Item 1. Legal Proceedings in this report for additional information on various legal matters.
Regulatory Matters
See Note 13 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 2016, Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017, and in this report for additional information on various regulatory matters.Restructuring ($24 million).
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 risksFor quantitative 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 Energy's and Virginia Power's electric operations and Dominion Energy's and Dominion Energy 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 fromqualitative disclosures about 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, Dominionaffecting Eastern Energy, and Virginia Power hold commodity-based derivative instruments held for non-trading purposes associated with purchases and salessee Item 7A of electricity, natural gas and other energy-related products and Dominion Energy 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 basedEastern Energy’s Annual Report 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 $28 million and $27 million of Dominion Energy's commodity-based derivative instruments as of September 30, 2017 and December 31, 2016, respectively.
A hypothetical 10% decrease in commodity prices would have resulted in a decrease in the fair value of $48 million and $62 million of Virginia Power's commodity-based derivative instruments as of September 30, 2017 and December 31, 2016, respectively.
A hypothetical 10% increase in commodity prices would have resulted in a decrease in fair value of $4 million of Dominion Energy Gas' commodity-based derivative instruments as of both September 30, 2017 and December 31, 2016.
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 September 30, 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 September 30, 2017, Dominion Energy and Virginia Power had $3.5 billion and $1.5 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 $55 million and $42 million, respectively, in the fair value of Dominion Energy's and Virginia Power's interest rate derivatives at September 30, 2017. As of December 31, 2016, Dominion Energy 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 Energy's and Virginia Power's interest rate derivatives at December 31, 2016.
Dominion Energy Gas holds foreign currency swaps for the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of September 30, 2017 and December 31, 2016, Dominion Energy and Dominion Energy Gas had $280 million (€250 million) in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a $3 million and $5 million decrease in the fair value of Dominion Energy Gas' foreign currency swaps at September 30, 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 Energy 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 Energy's and Virginia Power's Consolidated Balance Sheets at fair value.
Dominion Energy recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $137 million and $113 million for the nine months ended September 30, 2017 and 2016, respectively, and $144 millionForm 10-K for the year ended December 31, 2016. Net realized gains2019. Eastern Energy’s exposure to market risk and losses include gains and losses fromits management of such risk has not changed materially since December 31, 2019. Refer to Note 8 to the saleConsolidated Financial Statements in this report for disclosure of investmentsEastern Energy’s derivative positions as well as any other-than-temporary declines in fair value. Dominion Energy recorded in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $271 million and $146 million for the nine months ended September 30, 2017 and 2016, respectively, and $183 million for the year ended December 31, 2016.2020.
Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $59 million and $51 million for the nine months ended September 30, 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 $127 million and $77 million for the nine months ended September 30, 2017 and 2016, respectively, and $93 million for the year ended December 31, 2016.
Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power and Dominion Energy 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 DominionEastern Energy, Virginia Power,including its President (principal executive officer) and Dominion Energy Gas, including Dominion Energy’s, Virginia Power’s, and Dominion Energy Gas' CEO and CFO (principal financial officer), evaluated the effectiveness of each of their respective Company’sthe disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, each of DominionEastern Energy’s Virginia Power’s,President (principal executive officer) and Dominion Energy Gas' CEO and CFO (principal financial officer) have concluded that each of their respective Company’sthe disclosure controls and procedures are effective.
There were no changes in Dominion Energy’s, Virginia Power’s, or Dominion Energy 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’Eastern Energy’s internal control over financial reporting.
From time to time, the Companies areEastern Energy is 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 CompaniesEastern Energy and theirits subsidiaries are involved in various legal proceedings.
See the following for discussions on various legal, environmental and other regulatory proceedings to which the Companies areEastern Energy is a party, which information is incorporated herein by reference:
Notes 13 and 22 to the Consolidated Financial Statements 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.
Notes 12 and 15 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarter ended March 31, 2017.
Notes 12 and 15 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarter ended June 30, 2017.
Notes 12 and 15 to the Consolidated Financial Statements in this report.
• | Notes 13 and 23 to the Consolidated Financial Statements in Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2019. |
• | Notes 13 and 17 to the Consolidated Financial Statements in Eastern Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. |
• | Notes 13 and 17 to the Consolidated Financial Statements in Eastern Energy’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020. |
• | Notes 11 and 14 to the Consolidated Financial Statements in this report. |
The Companies'Eastern Energy’s 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’Eastern Energy’s control. A number of these risk factors have been identified in the Companies'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016,2019 and updated in Eastern Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, 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'Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2016.2019 and Eastern Energy’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. 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
Dominion Energy35
ISSUER PURCHASES OF EQUITY SECURITIES
Period |
| Total Number of Shares (or Units) Purchased(1) |
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| Average Price Paid per Share (or Unit)(2) |
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| Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs |
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| Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(3) | |||
7/1/17-7/31/17 |
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| $ | — |
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| 19,629,059 shares/ $1.18 billion |
8/1/17-8/31/17 |
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| 217 |
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| 77.30 |
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| — |
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| 19,629,059 shares/ $1.18 billion |
9/1/17-9/30/17 |
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| 5,932 |
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| 79.50 |
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| — |
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| 19,629,059 shares/ $1.18 billion |
Total |
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| 6,149 |
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| $ | 79.42 |
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| — |
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| 19,629,059 shares/ $1.18 billion |
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32.2 | Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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104 | Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101. |
36
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.
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