UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2016
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from
to
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Commission File Number |
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Exact name of registrants as specified in their charters |
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I.R.S. Employer
Identification Number |
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001-36684 |
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DOMINION MIDSTREAM PARTNERS, LP |
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46-5135781 |
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DELAWARE
(State or other jurisdiction of incorporation or organization) |
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120 TREDEGAR STREET
RICHMOND, VIRGINIA (Address
of principal executive offices) |
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23219
(Zip Code) |
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(804) 819-2000
(Registrants telephone number) |
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Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class |
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Name of Each Exchange
on Which Registered |
Common Units Representing Limited Partner Interests |
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by
check mark whether the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes ☐ No ☒
Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the past 90 days. 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). Yes ☒ No ☐
Indicate by check mark if disclosure
of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒
Indicate by check mark
whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting
company in Rule 12b-2 of the Exchange Act.
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Large accelerated filer ☒ |
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Accelerated filer ☐ |
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Non-accelerated filer ☐ |
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Smaller reporting company ☐ |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the
Act). Yes ☐ No ☒
The aggregate market value of the
registrants common units held by non-affiliates was approximately $770 million based on the closing price of its common units as reported on the New York Stock Exchange as of the last day of its most recently completed second fiscal quarter.
At February 24, 2017, Dominion Midstream Partners, LP had 67,251,952 common units and 31,972,789 subordinated units outstanding.
Dominion Midstream Partners, LP
Unless the context otherwise requires, references in this Annual Report on Form 10-K to Cove Point, the
Predecessor, our predecessor, and we, our, us, our partnership or like terms when used in a historical context (periods prior to October 20, 2014), refer to Dominion Cove Point LNG,
LP as our predecessor for accounting purposes. When used in the present tense or prospectively (periods beginning October 20, 2014), Dominion Midstream, we, our, us or like terms refer to Dominion
Midstream Partners, LP; one of its wholly-owned subsidiaries, Cove Point GP Holding Company, LLC, Iroquois GP Holding Company, LLC, Dominion Carolina Gas Transmission, LLC (beginning April 1, 2015) or Questar Pipeline, LLC and its subsidiaries
(beginning December 1, 2016); or all of them taken as a whole.
GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Form 10-K are defined below:
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Abbreviation or Acronym |
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Definition |
2005 Agreement |
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An agreement effective March 1, 2005, which Cove Point entered into with the Sierra Club and the Maryland
Conservation Council, Inc. |
Additional Return Distributions |
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The additional cash distribution equal to 3.0% of Cove Points Modified Net Operating Income in excess
of $600 million distributed each year |
Adjusted EBITDA |
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EBITDA after adjustment for EBITDA attributable to predecessors and a noncontrolling interest in Cove Point
held by Dominion subsequent to the Offering, less income from equity method investees, plus distributions from equity method investees |
AFUDC |
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Allowance for funds used during construction |
AIP |
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Annual Incentive Plan |
AOCI |
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Accumulated other comprehensive income (loss) |
ARO |
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Asset retirement obligation |
Atlantic Coast Pipeline |
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Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion, Duke Energy Corporation,
Piedmont Natural Gas Company, Inc. and Southern Company Gas (formerly known as AGL Resources Inc.) |
Bcf |
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Billion cubic feet |
Bcfe |
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Billion cubic feet equivalent |
Blue Racer |
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Blue Racer Midstream, LLC, a joint venture between Dominion and Caiman |
BRP |
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Retirement Benefit Restoration Plan |
CAA |
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Clean Air Act |
Caiman |
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Caiman Energy II, LLC |
CAP |
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IRS Compliance Assurance Process |
CD&A |
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Compensation Discussion and Analysis |
CEO |
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Chief Executive Officer |
CFO |
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Chief Financial Officer |
CGN Committee |
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Compensation, Governance and Nominating Committee of Dominions Board of Directors |
Charleston Project |
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Project to provide 80,000 Dths/day of firm transportation service from an existing interconnect with Transco
in Spartanburg County, South Carolina to customers in Dillon, Marlboro, Sumter, Charleston, Lexington and Richland counties, South Carolina |
Clean Power Plan |
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Guidelines issued by the EPA in August 2015 for states to follow in developing plans to reduce CO2 emissions from existing fossil fuel-fired electric generating units, stayed by the U.S. Supreme Court in February 2016 pending resolution of court challenges by certain states |
Columbia to Eastover Project |
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Project to provide 15,800 Dths/day of firm transportation service from an existing interconnect with Southern
Natural Gas Company, LLC in Aiken County, South Carolina and provide for a receipt point change of 2,200 Dths/day under an existing contract from an existing interconnect with Transco in Cherokee County, South Carolina for a total 18,000 Dths/day,
to a new delivery point for the International Paper Company at its pulp and paper mill known as the Eastover Plant in Richland County, South Carolina |
CO2 |
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Carbon dioxide |
Cove Point |
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Dominion Cove Point LNG, LP |
Cove Point Facilities |
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Collectively, the Liquefaction Project, Cove Point LNG Facility and Cove Point Pipeline |
Cove Point Holdings |
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Cove Point GP Holding Company, LLC |
Cove Point LNG Facility |
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An LNG import/regasification and storage facility located on the Chesapeake Bay in Lusby, Maryland owned by
Cove Point |
Cove Point Pipeline |
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An approximately 136-mile natural gas pipeline owned by Cove Point that connects the Cove Point LNG Facility
to interstate natural gas pipelines |
CPCN |
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Certificate of Public Convenience and Necessity |
CRA |
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Compliance Resolution Agreement |
CWA |
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Clean Water Act |
DCG |
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Dominion Carolina Gas Transmission, LLC (successor by statutory conversion to and formerly known as Carolina
Gas Transmission Corporation) |
DCG Acquisition |
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The acquisition of DCG by Dominion Midstream from Dominion on April 1, 2015 |
DCG Predecessor |
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Dominion as the predecessor for accounting purposes for the period from Dominions acquisition of DCG
from SCANA on January 31, 2015 until the DCG Acquisition |
DCGS |
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Dominion Carolina Gas Services, Inc. |
DCPI |
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Dominion Cove Point, Inc. |
DOE |
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Department of Energy |
DOL |
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Department of Labor |
Dominion |
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The legal entity, Dominion Resources, Inc., one or more of its consolidated subsidiaries (other than Dominion
Midstream GP, LLC and its subsidiaries) or operating segments, or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries |
Dominion Gas |
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Dominion Gas Holdings, LLC |
Dominion Midstream |
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The legal entity, Dominion Midstream Partners, LP, one or more of its consolidated subsidiaries, Cove Point
Holdings, Iroquois GP Holding Company, LLC, DCG (beginning April 1, 2015) and Questar Pipeline (beginning December 1, 2016), or the entirety of Dominion Midstream Partners, LP and its consolidated subsidiaries |
Dominion Midstream LTIP |
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Dominion Midstream 2014 Long-Term Incentive Plan |
Dominion Payroll |
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Dominion Payroll Company, Inc. |
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Abbreviation or Acronym |
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Definition |
Dominion Questar |
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The legal entity, Dominion Questar Corporation (formerly known as Questar Corporation), one or more of its
consolidated subsidiaries or operating segments, or the entirety of Dominion Questar Corporation and its consolidated subsidiaries |
DOT |
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U.S. Department of Transportation |
DRS |
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Dominion Resources Services, Inc. |
Dth |
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Dekatherm |
DTI |
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Dominion Transmission, Inc. |
EA |
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Environmental assessment |
Eastern Market Access Project |
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Project to provide 294,000 Dths/day of firm transportation service to help meet demand for natural gas for
Washington Gas Light Company, a local gas utility serving customers in D.C., Virginia and Maryland, and Mattawoman Energy, LLC for its new electric power generation facility to be built in Maryland |
EBITDA |
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Earnings before interest and associated charges, income tax expense, depreciation and
amortization |
Edgemoor Project |
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Project to provide 45,000 Dths/day of firm transportation service from an existing interconnect with Transco
in Cherokee County, South Carolina to customers in Calhoun and Lexington counties, South Carolina |
EPA |
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Environmental Protection Agency |
EPACT |
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Energy Policy Act of 2005 |
ERISA |
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The Employee Retirement Income Security Act of 1974 |
ESRP |
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Executive Supplemental Retirement Plan |
Export Customers |
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ST Cove Point, LLC, a joint venture of Sumitomo Corporation and Tokyo Gas Co., Ltd., and GAIL Global (USA)
LNG, LLC |
FERC |
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Federal Energy Regulatory Commission |
FERC Order |
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FERC order issued on September 29, 2014 that granted authorization for Cove Point to construct, modify and
operate the Liquefaction Project, subject to conditions, and also granted authorization to enhance the Cove Point Pipeline |
FIPs |
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Failures in individual performance |
FTA |
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Free Trade Agreement |
FTA Authorization |
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Authorization from the DOE for the export of up to 1.0 Bcfe/day of natural gas to countries that have or will
enter into an FTA for trade in natural gas |
GAAP |
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U.S. generally accepted accounting principles |
GHGRP |
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Greenhouse Gas Reporting Program |
GHG |
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Greenhouse gas |
IDR |
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Incentive distribution right |
Import Shippers |
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The three LNG import shippers consisting of BP Energy Company, Shell NA LNG, Inc. and Statoil |
IRC |
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Internal Revenue Code |
Iroquois |
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Iroquois Gas Transmission System, L.P. |
IRS |
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Internal Revenue Service |
Keys Energy Project |
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Project to provide 107,000 Dths/day of firm transportation service from Cove Points interconnect with
Transco in Fairfax County, Virginia to Keys Energy Center, LLCs power generating facility in Prince Georges County, Maryland |
Liquefaction Project |
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A natural gas export/liquefaction facility currently under construction by Cove Point |
LNG |
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Liquefied natural gas |
Maryland Commission |
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Public Service Commission of Maryland |
MD&A |
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Managements Discussion and Analysis of Financial Condition and Results of Operations |
MLP |
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Master limited partnership, equivalent to publicly traded partnership |
Modified Net Operating Income |
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Cove Points Net Operating Income plus any interest expense included in the computation of Net Operating
Income |
Mtpa |
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Million metric tons per annum |
NEO |
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Named executive officers |
Net Operating Income |
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Cove Points gross revenues from operations minus its interest expense and operating expenses, but
excluding depreciation and amortization, as determined for U.S. federal income tax purposes |
NG |
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Collectively, North East Transmission Co., Inc. and National Grid IGTS Corp. |
NGA |
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Natural Gas Act of 1938, as amended |
NGPSA |
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Natural Gas Pipeline Safety Act of 1968, as amended |
NJNR |
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NJNR Pipeline Company |
Non-FTA Authorization |
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Authorization from the DOE 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 |
Non-Open Access Services |
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Non-open access, proprietary non-jurisdictional services with rates, terms and conditions that are determined
by arms length negotiations with customers |
NSPS |
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New Source Performance Standards |
NYSE |
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New York Stock Exchange |
Offering |
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The initial public offering of common units of Dominion Midstream |
Open Access Services |
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Open access jurisdictional services with cost-based rates and terms and conditions that are part of a tariff
approved by FERC |
organizational design initiative |
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In the first quarter of 2016, Dominion announced an organizational design initiative that reduced its total
workforce during 2016, the goal of which was to streamline its leadership structure and push decision making lower while also improving efficiency |
OSHA |
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Federal Occupational Safety and Health Act, as
amended |
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Abbreviation or Acronym |
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Definition |
PHMSA |
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Pipeline and Hazardous Materials Safety Administration |
ppb |
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Parts-per-billion |
predecessors |
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Collectively, the Predecessor, DCG Predecessor and Questar Pipeline Predecessor |
Preferred Equity Interest |
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A perpetual, non-convertible preferred equity interest in Cove Point entitled to the Preferred Return
Distributions and the Additional Return Distributions |
Preferred Return Distributions |
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The first $50.0 million of annual cash distributions made by Cove Point |
Private Placement Agreement |
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Series A Preferred Unit and Common Unit Purchase Agreement between Dominion Midstream and purchasers (certain
affiliates of Stonepeak Infrastructure Partners, Magnetar Financial LLC, First Reserve Advisors, L.L.C., Kayne Anderson Capital Advisors, L.P. and Tortoise Capital Advisors, LLC) dated October 27, 2016 |
PSD |
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Prevention of Significant Deterioration |
PSIA |
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Pipeline Safety Improvement Act of 2002 |
Questar Pipeline |
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Questar Pipeline, LLC (successor by statutory conversion to and formerly known as Questar Pipeline Company),
one or more of its consolidated subsidiaries, or the entirety of Questar Pipeline, LLC and its consolidated subsidiaries |
Questar Pipeline Acquisition |
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The acquisition of Questar Pipeline by Dominion Midstream from Dominion on December 1, 2016 |
Questar Pipeline Contribution Agreement |
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Contribution, Conveyance and Assumption Agreement between Dominion and Dominion Midstream dated October 28,
2016 |
Questar Pipeline Predecessor |
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Dominion as the predecessor for accounting purposes for the period from Dominions acquisition of
Questar Pipeline on September 16, 2016 until the Questar Pipeline Acquisition |
RGGI |
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Regional Greenhouse Gas Initiative |
ROFO Assets |
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Any of the common equity interests in Cove Point or the indirect ownership interests in Blue Racer or
Atlantic Coast Pipeline subject to the right of first offer agreement with Dominion entered into in connection with the Offering |
ROIC |
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Return on invested capital |
SCANA |
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SCANA Corporation |
SCE&G |
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South Carolina Electric & Gas Company |
SEC |
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Securities and Exchange Commission |
SEIF |
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Maryland Strategic Energy Investments Fund |
Series A Preferred Units |
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Series A convertible preferred units representing limited partner interests in Dominion Midstream, issued in
December 2016 |
St. Charles Transportation Project |
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Project to provide 132,000 Dths/day of firm transportation service from Cove Points interconnect with
Transco in Fairfax County, Virginia to Competitive Power Venture Maryland, LLCs power generating facility in Charles County, Maryland |
Statoil |
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Statoil Natural Gas, LLC |
Storage Customers |
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The four local distribution companies that receive firm peaking services from Cove Point, consisting of
Atlanta Gas Light Company; Public Service Company of North Carolina, Incorporated; Virginia Natural Gas, Inc. and Washington Gas Light Company |
Transco |
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Transcontinental Gas Pipe Line, LLC |
TSR |
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Total shareholder return |
VIE |
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Variable interest entity |
Virginia Power |
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Virginia Electric and Power Company |
VOC |
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Volatile organic compounds |
Wexpro |
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The legal entity, Wexpro Company, one or more of its consolidated subsidiaries, or the entirety of Wexpro
Company and its consolidated subsidiaries. |
White River Hub |
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White River Hub, LLC |
Zions |
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Zions Bancorporation |
Part I
Item 1. Business
OVERVIEW
Dominion Midstream is a
growth-oriented Delaware limited partnership formed on March 11, 2014 by Dominion to grow a portfolio of natural gas terminaling, processing, storage, transportation and related assets. A registration statement on Form S-1, as amended through the time of its effectiveness, was filed by Dominion Midstream with the SEC and was declared effective on October 10, 2014. Dominion Midstreams common units began trading on the
NYSE on October 15, 2014, under the ticker symbol DM. On October 20, 2014, Dominion Midstream completed the Offering of 20,125,000 common units representing limited partner interests. In connection with the Offering, Dominion
Midstream acquired the Preferred Equity Interest and the general partner interest in Cove Point from Dominion.
Cove Point owns and
operates the Cove Point LNG Facility and the Cove Point Pipeline. Cove Point is currently generating a significant portion of its revenue and earnings from annual reservation payments under certain regasification, storage and transportation
contracts.
On April 1, 2015, Dominion Midstream acquired from Dominion all of the issued and outstanding membership interests of
DCG, an open access, transportation-only interstate pipeline company in South Carolina and southeastern Georgia, for total consideration of $500.8 million. See Note 4 to the Consolidated Financial Statements for additional information regarding this
acquisition.
On September 29, 2015, Dominion Midstream acquired NGs 20.4% and NJNRs 5.53%
partnership interests in Iroquois and, in exchange, Dominion Midstream issued common units representing limited partner interests in Dominion Midstream to both NG and NJNR. The Iroquois investment, accounted for under the equity method, was recorded
at $216.5 million. See Note 4 to the Consolidated Financial Statements for additional information regarding this equity method investment.
On December 1, 2016, Dominion Midstream acquired from Dominion all of the issued and outstanding membership interests of Questar Pipeline,
which owns and operates interstate natural gas pipelines and storage facilities in the western U.S., for total consideration of $1.29 billion. See Note 4 to the Consolidated Financial Statements for additional information regarding this acquisition.
Dominion Midstream manages its daily operations through one operating segment, Dominion Energy, which consists of gas transportation,
LNG import and storage. In addition to the Dominion Energy operating segment, Dominion Midstream also reports a Corporate and Other segment, which primarily includes specific items attributable to its operating segment that are not included in
profit measures evaluated by executive management in assessing the operating segments performance or in allocating resources among the segments. See Note 23 to the Consolidated Financial Statements for further discussions of Dominion
Midstreams operating segment, which information is incorporated herein by reference.
ORGANIZATIONAL STRUCTURE
The following simplified diagram depicts Dominion Midstreams organizational and ownership structure at December 31, 2016.
ASSETS AND OPERATIONS
Dominion Midstreams ongoing principal sources of cash flow include distributions received from Cove Point from our Preferred Equity Interest, cash
generated from the operations of DCG and Questar Pipeline and distributions received from our noncontrolling partnership interest in Iroquois.
Preferred Equity
Interest
One of our primary cash flow generating assets is the Preferred Equity Interest which is entitled to Preferred Return Distributions so long
as Cove Point has sufficient cash and undistributed Net Operating Income (determined on a cumulative basis from the closing of the Offering) from which to make Preferred Return Distributions. Preferred Return Distributions will be made on a
quarterly basis and will not be cumulative. The Preferred Equity Interest is also entitled to the Additional Return Distributions and should benefit from the expected increased cash flows and income associated with the Liquefaction Project once it
is completed.
We expect that Cove Point will generate cash and cumulative Net Operating Income in excess of that required to make
Preferred Return Distributions through the expected completion of the Liquefaction Project in late 2017 and thereafter. We base our expectation on the existing long-term contracts with firm reservation charges for substantially all of the
regasification and storage capacity of the Cove Point LNG Facility and all of the transportation capacity of the Cove Point Pipeline and the expectation that the Liquefaction Project will commence operations in late 2017. While we expect Cove
Points cash flows and Net Operating Income from its existing import contracts and associated transportation contracts to decrease as those contracts expire in 2017 and 2023, we expect the cash flows and Net Operating Income from the
Liquefaction Project, once completed, to replace and substantially exceed Cove Points cash flows and Net Operating Income from its existing import contracts and associated transportation contracts. See description of the Liquefaction Project
under Assets and OperationsCove Point. Until the Liquefaction Project is completed, Cove Point is prohibited from making a distribution on its common equity interests unless it has a distribution reserve sufficient to pay two quarters
of Preferred Return Distributions (and two quarters of similar distributions with respect to any other preferred equity interest in Cove Point). Cove Point fully funded this distribution reserve in October 2016, but there can be no assurance that
funds will be sufficient for such purpose or that Cove Point will have sufficient cash and undistributed Net Operating Income to permit it to continue to make Preferred Return Distributions after the expiration of certain of its contracts in the
second quarter of 2017. We do not expect to cause Cove Point to make distributions on its common equity, or the Additional Return Distributions, prior to the Liquefaction Project commencing commercial service. No distribution reserve will be
established for the Additional Return Distributions.
Cove Point
Cove Point is a Delaware limited partnership, of which Dominion Midstream owns the preferred equity interests and the general partner interest and Dominion
owns the common equity interests. Cove Points operations currently consist of LNG import and storage services at the Cove Point LNG Facility and the transportation of domestic natural gas and regasified LNG to
Mid-Atlantic markets via the Cove Point Pipeline. Following binding commitments from counterparties, Cove Point requested and received regulatory approval to operate the Cove Point LNG Facility
as a bi-directional facility, able to import LNG and regasify it as natural gas or to liquefy domestic natural gas and export it as LNG.
COVE POINTS IMPORT/STORAGE/REGASIFICATION
FACILITIES
The Cove Point LNG Facility includes an offshore pier, LNG storage tanks, regasification facilities and associated
equipment required to (i) receive imported LNG from tankers, (ii) store LNG in storage tanks, (iii) regasify LNG and (iv) deliver regasified LNG to the Cove Point Pipeline. The Cove Point LNG Facility has a contractual peak
regasification capacity of approximately 1.8 million Dths/day and an aggregate LNG storage capacity of 695,000 cubic meters of LNG, or approximately 14.6 Bcfe, all of which was fully contracted at December 31, 2016. In addition, the Cove Point
LNG Facility has an existing liquefier (unrelated to the Liquefaction Project) capable of liquefying approximately 15,000 Dths/day of natural gas. This liquefaction capacity is primarily used to liquefy natural gas received from domestic customers
that store LNG in our tanks for use during peak periods of natural gas demand. Cove Point offers both Open Access Services and Non-Open Access Services. Cove Points two-berth pier is located approximately 1.1 miles offshore in the Chesapeake
Bay. Cove Point operates the Cove Point LNG Facility on an integrated basis with no equipment exclusively used for the benefit of Open Access Services or Non-Open Access Services.
Cove Point currently provides services under (i) long-term agreements with the Import Shippers for an aggregate of 1.0 million
Dths/day of firm and off-peak regasification capacity, and (ii) long-term agreements for an aggregate 204,000 Dths/day of firm capacity with the Storage Customers who receive firm peaking services, whereby the Storage Customers deliver domestic
natural gas to the Cove Point LNG Facility to be liquefied and stored during the summer for withdrawal on a limited number of days at peak times during the winter. Cove Point also had, through December 31, 2016, an additional 800,000 Dths/day of
regasification capacity committed under a separate agreement with Statoil, one of the Import Shippers. The agreement provides for 277,650 Dths/day of such service until its expiration in the second quarter of 2017. In 2016, the Import Shippers
comprised approximately 57% of total consolidated operating revenues for Dominion Midstream. Cove Points customers are required to pay fixed monthly charges, regardless of whether they use the amount of capacity they have paid to reserve at
the Cove Point LNG Facility. Following the expiration of certain Cove Point regasification and transportation contracts with Statoil in the second quarter of 2017, the resulting available storage and transportation capacity will be utilized in
connection with the Liquefaction Project.
COVE POINTS PIPELINE
FACILITIES
The Cove Point Pipeline is a 36-inch diameter bi-directional underground, interstate natural gas pipeline that extends
approximately 88 miles from the Cove Point LNG Facility to interconnections with pipelines owned by Transco in Fairfax County, Virginia, and with Columbia Gas Transmission LLC and DTI, both in Loudoun County, Virginia. In 2009, the original pipeline
was expanded to include a 36-inch diameter loop that extends
approximately 48 miles, roughly 75% of which is parallel to the original pipeline. Cove Point has two compressor stations, with approximately 24,800 installed compressor horsepower, at its
interconnections with the three upstream interstate pipelines. The Loudoun Compressor Station is located at the western end of the Cove Point Pipeline where it interconnects with the pipeline systems of DTI and Columbia Gas Transmission LLC. The
Pleasant Valley Compressor Station is located roughly 13 miles to the southeast of the Loudoun Compressor Station, where the Cove Point Pipeline interconnects with Transcos pipeline system.
Cove Point offers open-access transportation services, including firm transportation, off-peak firm transportation and interruptible
transportation, with cost-based rates and terms and conditions that are subject to the jurisdiction of FERC. Firm transportation services are generally provided based on a reservation-based fee that is designed to recover Cove Points fixed
costs and earn a reasonable return. The firm transportation customers are required to pay fixed monthly fees, regardless of whether they use their reserved capacity for the Cove Point Pipeline. Cove Point also provides certain incrementally priced,
firm transportation services that are associated with expansion projects. The Export Customers will be responsible for procuring their own natural gas supplies and transporting such supplies to the Cove Point Pipeline, which serves as the primary
method of transportation of natural gas supplies to or from the Cove Point LNG Facilities.
In October 2015, Cove Point received FERC
authorization to construct the approximately $40 million Keys Energy Project. Construction on the project commenced in December 2015, and the project facilities are expected to be placed into service in March 2017.
In November 2016, Cove Point filed an application to request FERC authorization to construct the approximately $150 million Eastern
Market Access Project. Construction on the project is expected to begin in the fourth quarter of 2017, and the project facilities are expected to be placed into service in late 2018.
COVE POINTS EXPORT/LIQUEFACTION FACILITIES
Cove Point is in the process of constructing the Liquefaction Project, which will consist of one LNG train with a design nameplate outlet capacity of 5.25
Mtpa. It is expected to be placed in service in late 2017. Under normal operating conditions and after accounting for maintenance downtime and other losses, the firm contracted capacity for LNG loading onto ships will be approximately 4.6 Mtpa (0.66
Bcfe/day). Cove Point has authorization from the DOE to export up to 0.77 Bcfe/day (approximately 5.75 Mtpa) should the liquefaction facilities perform better than expected. Once completed, the Liquefaction Project will enable the Cove Point LNG
Facility to liquefy domestically produced natural gas and export it as LNG. The Liquefaction Project is being constructed on land already owned by Cove Point, which is within the developed area of the existing Cove Point LNG Facility, and will be
integrated with a number of the facilities that are currently operational. Domestic natural gas will be delivered to the Cove Point LNG Facility through the Cove Point Pipeline for liquefaction and will be exported as LNG. The total costs of
developing the Liquefaction Project are estimated to be approximately $4.0 billion, excluding financing costs. Through
December 31, 2016, Cove Point incurred $3.3 billion of development and construction costs associated with the Liquefaction Project. Dominion has indicated that it intends to provide the
funding necessary for the remaining construction costs for the Liquefaction Project, but it is under no obligation to do so.
Many of the
existing facilities at the Cove Point LNG Facility will be used to provide the liquefaction service. The Liquefaction Project will utilize existing storage tanks at the Cove Point LNG Facility to store LNG produced by the new liquefaction
facilities. The Liquefaction Project will utilize the existing off-shore two-berth pier and insulated LNG and gas piping from the pier to the on-shore Cove Point LNG Facility. Cove Point is constructing new facilities to liquefy the natural gas on
land it already owns (which encompasses more than 1,000 acres). No change will be made to the Cove Point LNG Facilitys current storage, import, or regasification capabilities and only minor modifications will be made to the Cove Point LNG
Facility itself, such as adding piping tie-ins and electrical/control connections to integrate the liquefaction facility with the existing LNG regasification facilities.
COVE POINTS EXPORT CUSTOMERS
Cove Point has executed service contracts for the Liquefaction Project with the Export Customers, each of which has contracted for 50% of the available
capacity. The Export Customers together will have firm access to 6.8 Bcfe of the existing storage capacity, with the balance of the existing storage capacity available for Cove Points existing Import Shippers and Storage Customers. The Export
Customers have each entered into a 20-year agreement for the liquefaction and export services, which they may annually elect to switch to import services, provided that the other Export Customer agrees to switch. In addition, each of the Export
Customers has entered into an accompanying 20-year service agreement for firm transportation on the Cove Point Pipeline.
Upon completion
of the Liquefaction Project, a substantial portion of Cove Points revenues will be dependent upon the payment of these two customers. Cove Points future results and liquidity are primarily dependent upon the payment of the Export
Customers under their respective contracts, and on their continued willingness and ability to perform their contractual obligations.
Cove
Point will provide terminal services for the Export Customers as a tolling service, and the Export Customers will be responsible for procuring their own natural gas supplies and transporting such supplies to or from the Cove Point LNG Facilities. To
deliver the feed gas for liquefaction to the Cove Point LNG Facility, each Export Customer entered into a firm transportation service agreement to utilize the Cove Point Pipeline, with a maximum firm transportation quantity of 430,000 Dths/day for
each Export Customer. This amount of firm transportation capacity will enable Export Customers to deliver to the Cove Point LNG Facility the feed gas, including fuel, required on days of peak liquefaction, utilizing both their firm liquefaction
rights and an expected level of authorized overrun service. In the event of an election of import/regasification service, each of the Export Customers will have a regasification capacity of 330,000 Dths/day.
DCG
DCG operates as
an open access, transportation-only interstate pipeline company in South Carolina and southeastern Georgia. At December 31, 2016, DCGs natural gas system consisted of nearly 1,500 miles of transmission pipeline of up to 24 inches in diameter
and five compressor stations with approximately 38,700 installed compressor horsepower. DCGs system transports gas to its customers from the transmission systems of Southern Natural Gas Company at Port Wentworth, Georgia and Aiken County,
South Carolina; Southern LNG, Inc. at Elba Island, near Savannah, Georgia; and Transco in Cherokee and Spartanburg counties in South Carolina. All of DCGs operations are regulated by FERC.
DCGs customers include SCE&G (which uses natural gas for electricity generation and for gas distribution to retail customers), SCANA
Energy Marketing, Inc. (which markets natural gas to industrial and sale for resale customers, primarily in the southeastern U.S.), municipalities, county gas authorities, federal and state agencies, marketers, power generators and
industrial customers primarily engaged in the manufacturing or processing of ceramics, paper, metal and textiles.
DCGs revenues are
primarily derived from reservation charges for firm services as provided for in its FERC-approved tariff. DCGs pipeline system is substantially fully subscribed with a contracted pipeline capacity of approximately 794,500 Dths/day.
Approximately 1% of the capacity has a 2017 expiration date, and 99% of this capacity is contracted through 2018 or beyond.
In 2014, DCG
executed three binding precedent agreements for the approximately $120 million Charleston Project. In February 2017, DCG received FERC authorization to construct and operate the project facilities, which are expected to be placed into service in the
fourth quarter of 2017. The Charleston Project is supported by long-term contracts with terms ranging from 10 to 30 years.
Questar Pipeline
Questar Pipeline owns and operates interstate natural gas pipelines and storage facilities in the western U.S. providing natural gas transportation and
underground storage services in Utah, Wyoming and Colorado. Questar Pipelines operations are primarily regulated by FERC. At December 31, 2016, Questar Pipeline owned and operated nearly 2,200 miles of natural gas transportation pipelines
across northeastern and central Utah, northwestern Colorado and southwestern Wyoming. Questar Pipelines system ranges in diameter from lines that are less than four inches to 36 inches. Questar Pipeline owns 18 transmission and storage
compressor stations with approximately 221,200 combined installed compressor horsepower. Questar Pipeline also owns gathering lines as well as processing facilities near Price, Utah, which provide for dew-point control to meet gas-quality
specifications of downstream pipelines. Additionally, Questar Pipeline owns and operates 50% of White River Hub, an 11-mile FERC-regulated natural gas transportation pipeline in western Colorado, which is accounted for under the equity method.
Questar Pipelines transportation customers include its affiliate, Questar Gas Company,
which provides the largest share of transportation revenues, as well as Enterprise Gas Processing, LLC, Rockies Express Pipeline LLC, Citadel Energy Marketing LLC, Wyoming Interstate Company, LLC, Pacificorp, Encana Marketing (USA) Inc. and other
unaffiliated end-users, marketers and producers in the Rocky Mountain region. The Questar Pipeline systems interconnect with several major, unaffiliated natural gas pipeline systems owned by Kern River Gas Transmission Company, Ruby Pipeline, LLC,
Rockies Express Pipeline, LLC, Northwest Pipeline, LLC, Wyoming Interstate Company, TransColorado Gas Transmission Company, LLC, and others.
Questar Pipelines transportation revenues are primarily derived from reservation charges for firm services as provided for in its
FERC-approved tariff. At December 31, 2016, Questar Pipelines pipeline system had contracted pipeline capacity of approximately 5,696,500 Dths/day. Approximately 17% of that capacity is committed to by Questar Pipelines affiliate,
Questar Gas Company. Of the total committed capacity, approximately 17% relates to contracts that expire in 2017, 77% relates to contracts that expire in 2018 or beyond, and the remaining 6% of contracts operate under evergreen contracts that
contain customary termination features. Questar Pipeline expects that the contract with Questar Gas Company and other contracts expiring in 2017 will be renewed under similar terms as the existing agreements.
Questar Pipeline owns four natural gas storage facilities totaling 55.8 Bcf of working gas storage capacity. The Clay Basin storage facility
in northeastern Utah has a certificated capacity of 120.2 Bcf, including 54.0 Bcf of working gas. In addition, Questar Pipeline owns three smaller storage aquifers in northeastern Utah and western Wyoming.
Questar Pipelines natural gas storage customers include its affiliate, Questar Gas Company, which provides the largest share of storage
revenues, as well as Puget Sound Energy Inc., Intermountain Gas Company and other unaffiliated customers.
Questar Pipelines natural
gas storage revenues are primarily derived from long-term contracts for storage capacity at the Clay Basin storage facility. Approximately 27% of the total storage working gas capacity is contracted with Questar Gas Company. Of the total contracted
working gas capacity, 14% of the volumes expire in 2017 while the remaining 86% are contracted through 2018 or beyond. The contracts that expire in 2017 are all expected to be renewed under similar terms as the existing agreements.
Iroquois
Iroquois is a Delaware limited partnership which owns and
operates a 416-mile FERC-regulated interstate natural gas pipeline providing service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, through interconnecting pipelines
and exchanges. Iroquois pipeline extends from the U.S.-Canadian border at Waddington, New York through the state of Connecticut to South Commack, Long Island, New York and continuing on from Northport, Long Island, New York through the Long
Island Sound to Hunts Point, Bronx, New York. At December 31, 2016, Dominion Midstream holds a 25.93% noncontrolling partnership interest in Iroquois, which is accounted for under the equity method.
RELATIONSHIP WITH DOMINION
We view our relationship with Dominion as a significant competitive strength. We believe this relationship will provide us with potential acquisition
opportunities from a broad portfolio of existing midstream assets that meet our strategic objectives, as well as access to personnel with extensive technical expertise and industry relationships. Dominion has granted us a right of first offer with
respect to any future sale of its common equity interests in Cove Point. We may also acquire newly issued common equity or additional preferred equity interests in Cove Point in the future, provided that any issuances of additional equity interests
in Cove Point would require both our and Dominions approval. Any additional equity interests that we acquire in Cove Point would allow us to participate in the significant growth in cash flows and income expected following the completion of
the Liquefaction Project. In connection with the Offering, Dominion also granted us a right of first offer with respect to any future sale of its indirect ownership interest in Blue Racer, which is a midstream company focused on the Utica Shale
formation, and its indirect ownership interest in Atlantic Coast Pipeline, which is focused on constructing a natural gas pipeline running from West Virginia through Virginia to North Carolina. In addition, acquisition opportunities, such as the DCG
Acquisition and the Questar Pipeline Acquisition, may arise from future midstream pipeline, terminaling, processing, transportation and storage assets acquired or constructed by Dominion.
Dominion, headquartered in Richmond, Virginia, is one of the nations largest producers and transporters of energy. Dominions
strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. At December 31, 2016, Dominion served over 6 million utility and retail energy customers and
operated one of the nations largest underground natural gas storage systems, with approximately 1 trillion cubic feet of storage capacity. Dominions portfolio of midstream pipeline, terminaling, processing, transportation and storage
assets includes its indirect ownership interests in Blue Racer and Atlantic Coast Pipeline, both of which are described in more detail below, and the assets and operations of Dominion Gas and Dominion Questar. Dominion Gas consists primarily of
(i) The East Ohio Gas Company d/b/a Dominion East Ohio, a regulated natural gas distribution company, (ii) DTI, an interstate natural gas transmission pipeline company, and (iii) Dominion Iroquois, Inc., which holds a 24.07%
noncontrolling partnership interest in Iroquois. Dominion Questar consists primarily of Questar Gas Company, a regulated natural gas distribution company, and Wexpro, a natural gas exploration and production company which supplies natural gas to
Questar Gas Company under a cost-of-service framework.
Blue Racer is a midstream energy company focused on the design, construction,
operation and acquisition of midstream assets. Blue Racer is investing in natural gas gathering and processing assets in Ohio and West Virginia, targeting primarily the Utica Shale formation, and is an equal partnership between Dominion and Caiman,
with Dominion contributing midstream assets, including both gathering and processing assets, and Caiman contributing private equity capital. Midstream services offered by Blue Racer include gathering, processing, fractionation, and natural gas
liquids transportation and marketing. Blue Racer is expected to develop additional new capacity designed to meet
producer needs as the development of the Utica Shale formation increases.
Atlantic
Coast Pipeline is a limited liability company owned at December 31, 2016 by Dominion (48%), Duke Energy Corporation (40%), Piedmont Natural Gas Company, Inc. (7%) and Southern Company Gas (formerly known as AGL Resources, Inc.) (5%). Effective
October 2016, Piedmont Natural Gas Company, Inc. became a wholly-owned subsidiary of Duke Energy Corporation. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through
Virginia to North Carolina to increase natural gas supplies in the region. Construction of the pipeline is subject to receiving all necessary regulatory and other approvals, including without limitation CPCNs from FERC and all required environmental
permits. Atlantic Coast Pipeline filed its FERC application in September 2015, and the facilities are expected to be in service in the fourth quarter of 2019. DTI will provide the services necessary to oversee the construction of, and to
subsequently operate and maintain, the facilities and projects undertaken by, and subject to the approval of, Atlantic Coast Pipeline. The pipeline is expected to serve as a new, independent route for transportation of shale and conventional
interstate gas supplies for markets in the mid-Atlantic region of the U.S.
At December 31, 2016, Dominion is our largest unitholder,
holding 18,504,628 common units (28% of all outstanding), 11,365,628 Series A Preferred Units (38% of all outstanding) and 31,972,789 subordinated units (100% of all outstanding). Dominion also owns our general partner and owns 100% of our IDRs. As
a result of its significant ownership interests in us, we believe Dominion will be motivated to support the successful execution of our business strategies and will provide us with acquisition opportunities, although it is under no obligation to do
so. Dominion views us as a significant part of its growth strategy, and we believe that Dominion will be incentivized to contribute or sell additional assets to us and to pursue acquisitions jointly with us in the future. However, Dominion will
regularly evaluate acquisitions and dispositions and may, subject to compliance with our right of first offer with respect to Cove Point, Blue Racer and Atlantic Coast Pipeline, elect to acquire or dispose of assets in the future without offering us
the opportunity to participate in those transactions. Moreover, Dominion will continue to be free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with future acquisition
opportunities.
See Note 20 to the Consolidated Financial Statements for a discussion of the significant contracts entered into with
Dominion.
COMPETITION
Substantially all of the
regasification and storage capacity of the Cove Point LNG Facility, and all of the transportation capacity of the Cove Point Pipeline is currently under contract, and the proposed Liquefaction Projects capacity is also fully contracted under
long-term fixed reservation fee agreements. However, in the future Cove Point may compete with other independent terminal operators as well as major oil and gas companies on the basis of terminal location, services provided and price. Competition
from terminal operators primarily comes from refiners and distribution companies with marketing and trading arms.
DCGs pipeline system generates a substantial portion of its revenue from long-term firm
contracts for transportation services and is therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, DCGs pipeline system faces competitive pressures from similar facilities that
serve the South Carolina and southeastern Georgia area in terms of location, rates, terms of service, and flexibility and reliability of service.
Questar Pipelines pipeline system generates a substantial portion of its revenue from long-term firm contracts for transportation and
storage services and is therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, Questar Pipelines pipeline system and storage facilities face competitive pressures from similar
facilities in the Rocky Mountain region in terms of location, rates, terms of service and availability and reliability of service.
REGULATION
Dominion Midstream is subject to regulation by various federal, state and local authorities, including the SEC, FERC, EPA, DOE, DOT and Maryland Commission.
FERC Regulation
The design, construction and operation of
interstate natural gas pipelines, LNG terminals (including the Liquefaction Project) and other facilities, the import and export of LNG, and the transportation of natural gas are all subject to various regulations, including the approval of FERC
under Section 3 (for LNG terminals) and Section 7 (for interstate transportation facilities) of the NGA, as well as the Natural Gas Policy Act of 1978, as amended, to construct and operate the facilities. For the Cove Point LNG Facility,
Cove Point is required to maintain authorization from FERC under Section 3 and Section 7 of the NGA. The design, construction and operation of the Cove Point LNG Facility and its proposed Liquefaction Project, and the import and export of
LNG, are highly regulated activities. FERCs approval under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, are required for the proposed Liquefaction Project.
DCG and Questar Pipeline are required to maintain authorization from FERC under Section 7 of the NGA.
Under the NGA, FERC is granted
authority to approve, and if necessary, set just and reasonable rates for the transportation, including storage, or sale of natural gas in interstate commerce. In addition, under the NGA, with respect to the jurisdictional services, we
are not permitted to unduly discriminate or grant undue preference as to our rates or the terms and conditions of service. FERC has the authority to grant certificates allowing construction and operation of facilities used in interstate gas
transportation and authorizing the provision of services. Under the NGA, FERCs jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for
ultimate consumption for domestic, commercial, industrial, or any other use, and to natural gas companies engaged in such transportation or sale. However, FERCs jurisdiction does not extend to the production or local distribution of natural
gas.
In general, FERCs authority to regulate interstate natural gas pipelines and the services
that they provide includes:
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In November 2016, pursuant to the terms of a previous settlement, Cove
Point filed a general rate case for its FERC-jurisdictional services, with 23 proposed rates to be effective January 1, 2017. Cove Point proposed an annual cost-of-service of approximately $140 million. In December 2016, FERC accepted a January 1,
2017 effective date for all proposed rates, with the exception of five, which were suspended to be effective June 1, 2017. This case is pending.
In connection with Dominions acquisition of DCG on January 31, 2015, Dominion agreed to a rate moratorium which precludes DCG from
filing a Section 4 NGA general rate case to establish base rates that would be effective prior to January 1, 2018.
LIQUEFACTION PROJECT
In
April 2013, Cove Point filed its application with FERC requesting authorization to construct, modify and operate the Liquefaction Project, as well as enhance the Cove Point Pipeline. In May 2014, FERC staff issued its EA for the Liquefaction
Project. In the EA, FERC staff addressed a variety of topics related to the proposed construction and development of the Liquefaction Project and its potential impact to the environment, including in the areas of geology, soils, groundwater, surface
waters, wetlands, vegetation, wildlife and aquatic resources, special status species, land use, recreation, socioeconomics, air quality and noise, reliability and safety, and cumulative impacts. In September 2014, Cove Point received the FERC Order
which authorized the construction and operation of the Liquefaction Project. In the FERC Order, FERC concluded that if constructed and operated in accordance with Cove Points application and supplements, and in compliance with the
environmental conditions set forth in the FERC Order, the Liquefaction Project would not constitute a major federal action significantly affecting the quality of the human environment. In October 2014, Cove Point commenced construction of the
Liquefaction Project.
Two parties separately filed petitions for review of the FERC Order in the U.S. Court of Appeals for the D.C.
Circuit, which petitions have been 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 partys petition for
review of the FERC Order authorizing the Liquefaction Project. The court also issued a decision remanding the other partys petition for review of the FERC Order to FERC for further explanation of how FERCs decision that a previous
transaction with an existing import shipper was not unduly discriminatory. Cove Point believes that on remand FERC will be able to justify its decision.
Energy Policy Act of 2005
The EPACT and FERCs policies promulgated thereunder contain numerous provisions relevant to the natural gas industry and to interstate pipelines.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties. Additionally, the EPACT amended Section 3 of the NGA to establish or clarify FERCs exclusive authority to
approve or deny an application for the siting, construction, expansion or operation of LNG terminals, although except as specifically provided in the EPACT, nothing in the EPACT is intended to affect otherwise applicable law related to any other
federal agencys authorities or responsibilities related to LNG terminals. The EPACT amended the NGA to, among other things, prohibit market manipulation. In accordance with the EPACT, FERC issued a final rule making it unlawful for any entity,
in connection with the purchase or sale of natural gas or transportation service subject to FERCs jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or
would operate as a fraud.
DOE Regulation
Prior to importing
or exporting LNG, Cove Point must receive approvals from the DOE. Cove Point previously received import authority in connection with the construction and operation of the Cove Point LNG Facility and more recently also received authority to export
the commodity.
In October 2011, the DOE granted FTA Authorization for the export of up to 1.0 Bcfe/day of natural gas to countries that
have or will enter into an FTA for trade in natural gas. In September 2013, the DOE also 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. The
FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively. In June 2016, a party filed a petition for review of the DOEs Non-FTA Authorization approval in the United States Court of Appeals for the D.C. Circuit. This
case is pending.
DOT Regulation
The Cove Point Pipeline, DCG
and Questar Pipeline are subject to regulation by the DOT, under the PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline
facilities. The NGPSA requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections.
The PSIA, which is administered by the DOT Office of Pipeline Safety, governs the areas of testing, education, training and communication. The
PSIA requires pipeline companies to perform extensive integrity tests on natural gas transportation pipelines that exist in high population density areas designated as high consequence areas. Pipeline companies are required to perform
the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its
protective coating.
Testing consists of hydrostatic testing, internal electronic testing or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a
qualification program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs for gas transportation pipelines, which requires pipeline operators to perform ongoing assessments of
pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline, as necessary; and implement
preventive and mitigation actions. The Cove Point Pipeline, DCG and Questar Pipeline are also subject to the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011, which regulates safety requirements in the design, construction,
operation and maintenance of interstate natural gas transmission facilities.
State Regulation
The Maryland Commission regulates electricity suppliers, fees for pilotage services to vessels, construction of generating stations and certain common
carriers engaged in the transportation for hire of persons in the state of Maryland. See Note 17 to the Consolidated Financial Statements for additional information.
Worker Health and Safety
Dominion Midstream is subject to a number
of federal and state laws and regulations, including OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. Dominion Midstream has an internal safety, health and security program designed to monitor and
enforce compliance with worker safety requirements and routinely reviews and considers improvements in its programs. Cove Point is also subject to the United States Coast Guards Maritime Security Standards for Facilities, which are designed to
regulate the security of certain maritime facilities. Dominion Midstream believes that it is in material compliance with all applicable laws and regulations related to worker health and safety. Notwithstanding these preventative measures, incidents
may occur, including those outside of Dominion Midstreams control.
ENVIRONMENTAL
REGULATION
General
Dominion Midstream is
committed to compliance with all applicable environmental laws, regulations and rules related to its operations. Dominion Midstreams operations are subject to stringent, comprehensive and evolving federal, regional, state and local laws and
regulations governing environmental protection. These laws and regulations may, among other things, require the acquisition of permits or other approvals to conduct regulated activities, restrict the amounts and types of substances that may be
released into the environment, limit operational capacity of the facilities, require the installation of environmental controls, limit or prohibit construction activities in sensitive areas such as wetlands or areas inhabited by endangered or
threatened species and impose substantial liabilities for pollution resulting from operations. The cost of complying with applicable environmental
laws, regulations and rules is expected to be material. Failure to comply with these laws and regulations may also result in the assessment of administrative, civil and criminal penalties, the
imposition of investigatory and remedial obligations and the issuance of orders enjoining some or all of Dominion Midstreams operations in affected areas.
Dominion Midstream has applied for or obtained the necessary environmental permits for the operation of its facilities. Many of these permits
are subject to reissuance and continuing review. Additional information related to Dominion Midstreams environmental compliance matters, including current and planned capital expenditures relating to environmental compliance, can be found in
Future Issues and Other Matters in Item 7. MD&A.
Air Emissions
The regulation of air emissions under the CAA and comparable state laws and regulations restrict the emission of air pollutants from many sources and also
impose various monitoring and reporting requirements. The CAA new source review regulations require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air
emissions, obtain and strictly comply with stringent air permit requirements or install and operate specific equipment or technologies to control emissions. Obtaining necessary air permits has the potential to delay the development of our projects.
The regulation of air emissions under the CAA requires that we obtain various construction and operating permits, including Title V air
permits, and incur capital expenditures for the installation of certain air pollution control devices at our facilities. We have taken and expect to continue to take certain measures to comply with various regulations specific to our operations,
such as National Emission Standards for Hazardous Air Pollutants, NSPS, new source review and federal and state regulatory measures imposed to meet national ambient air quality standards. We have incurred, and expect to continue to incur,
substantial capital expenditures to maintain compliance with these and other air emission regulations that have been promulgated or may be promulgated or revised in the future.
Global Climate Change
The national and international attention in
recent years on GHG emissions and their relationship to climate change has resulted in federal, regional and state legislative and regulatory action in this area. Dominion Midstream supports national climate change legislation that would provide a
consistent, economy-wide approach to addressing this issue and is currently taking action to protect the environment and address climate change while meeting the future needs of its customers. Dominion Midstreams CEO and its management are
responsible for compliance with the laws and regulations governing environmental matters, including climate change.
In response to
findings that emissions of GHGs present an endangerment to public health and the environment, the EPA adopted regulations under existing provisions of the CAA in April 2010, that require a reduction in emissions of GHGs from motor vehicles. These
rules took effect in January 2011 and established
GHG emissions as regulated pollutants under the CAA. 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 EPAs ability to require best available control technology 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 GHG sources obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional,
pollutants that are regulated by the new source review program, and to set a significant emissions rate at 75,000 tons per year of CO2 equivalent emissions under which a source would not be
required to apply best available control technology for its GHG emissions. Due to uncertainty regarding what additional actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the court ruling
under a new rulemaking, we cannot predict the impact to the financial statements at this time.
In January 2015, as part of its Climate
Action Plan, the EPA announced plans to reduce methane emissions from the oil and gas sector including natural gas processing and transmission sources. In July 2015, the EPA announced the next generation of its voluntary Natural Gas Star Program.
The 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. DCG joined the EPAs
voluntary Natural Gas Star Program in July 2016 and submitted an implementation plan in September 2016.
Maryland, along with eight other
Northeast states, has implemented regulations requiring reductions in CO2 emissions through the RGGI, a cap and trade program covering
CO2 emissions from electric generating units in the Northeast. The CPCN states that the Liquefaction Project must submit a Climate Action Plan to the Maryland Department of the Environment and
gain approval of the plan. Additionally, by not connecting to the larger grid, the Liquefaction Project generating station is exempt from purchasing RGGI carbon emission allowances. Furthermore, the CPCN requires Cove Point to make payments over
time totaling approximately $48 million to the SEIF and Maryland low income energy assistance programs.
GHG EMISSIONS
Dominion began tracking and reporting GHG emissions at the Cove Point LNG Facility in 2010 under the EPAs GHGRP and voluntarily tracked such emissions
prior to 2010. A comprehensive methane leak survey is conducted each year in accordance with the EPA rule to detect leaks and to quantify leaks from compressor units. Dominion Midstream does not yet have final 2016 emissions data.
Annual GHG emissions at the Cove Point LNG Facility have remained fairly constant from 2011 to 2015, ranging from 141,250 to 182,650 metric
tons of CO2 equivalent. Approximately 99% of these emissions are CO2 emissions from combustion sources, such as compressor engines and
heaters. Only 1% of the annual Cove Point GHG emissions comes from methane emissions. Compared to other fossil fuels, natural gas has a much lower carbon emission rate with
an ample regional supply, promoting energy and economic security. In 2015, annual GHG emissions from Dominion Midstreams facilities, including five compressor stations in South Carolina and
two compressor stations in Virginia were approximately 243,470 metric tons of CO2 equivalent emissions.
Water
The CWA is a comprehensive program requiring a broad range
of regulatory tools including a permit program with strong enforcement mechanisms to authorize and regulate discharges to surface waters. Cove Point must comply with applicable aspects of the CWA programs at its operating facilities. Cove Point has
applied for or obtained the necessary environmental permits for the operation of its facilities.
The CWA and analogous state laws impose
restrictions and strict controls regarding the discharge of effluent into surface waters. Pursuant to these laws, permits must be obtained to discharge into state waters or waters of the U.S. Any such discharge into regulated waters must be
performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal and state law require appropriate containment berms and similar structures
to help prevent the accidental release of petroleum into the environment. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of
activities.
From time to time, Dominion Midstreams projects and operations may potentially impact tidal and non-tidal wetlands. In
these instances, Dominion Midstream must obtain authorization from the appropriate federal, state and local agencies prior to impacting a subject wetland. The authorizing agency may impose significant direct or indirect mitigation costs to
compensate for regulated impacts to wetlands. The approval timeframe may also be extended and potentially affect project schedules resulting in a material adverse effect on Dominion Midstreams business and contracts.
Threatened and Endangered Species
The Endangered Species Act
establishes prohibitions on activities that can result in harm to specific species of plants and animals. In some cases those prohibitions could result in impacts to the viability of projects or requirements for capital expenditures to reduce a
facilitys impacts on a species.
EMPLOYEES
Dominion Midstream is managed
and operated by the Board of Directors and executive officers of Dominion Midstream GP, LLC, our general partner. We do not have any employees, nor does our general partner. All of the employees that conduct our business are employed by affiliates,
and our general partner secures the personnel necessary to conduct our operations through its services agreement with DRS. We reimburse our general partner and its affiliates for the associated costs of obtaining the personnel necessary for our
operations pursuant to our partnership agreement. At December 31, 2016, Cove Point had approximately 160 full-time employees and was supported by 15 full-time DRS employees.
WHERE YOU CAN FIND MORE INFORMATION
Dominion Midstream files its annual, quarterly and current reports and other information with the SEC. Its SEC filings are available to the public over the
Internet at the SECs website at http://www.sec.gov. You may also read and copy any document it files at the SECs public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further
information on the public reference room.
Dominion Midstream makes its SEC filings available, free of charge, including the annual report
on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, through our internet website, http://www.dommidstream.com, as soon as reasonably practicable after filing or furnishing the material to
the SEC. Information contained on our website is not incorporated by reference in this report.
Item 1A. Risk Factors
Dominion Midstreams business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual
results and are often beyond its control. A number of these factors have been identified below. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in
this report, see Forward-Looking Statements in Item 7. MD&A.
RISKS INHERENT
IN OUR ABILITY TO GENERATE STABLE AND GROWING CASH FLOWS
Our cash generating assets are the Preferred Equity Interest, our pipeline operations, and our equity method investment in Iroquois, the cash receipts from
which may not be sufficient following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our
unitholders. Our sources of cash are funds we receive from (i) Cove Point on the Preferred Equity Interest, which we expect will result in an annual payment to us of $50.0 million, (ii) our pipelines operations and
(iii) distributions received with respect to our interest in Iroquois, which we expect will generate sufficient cash to enable us to pay the minimum quarterly distributions on the common and subordinated units. These sources may not generate
sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our
unitholders. The amount of cash we can distribute on our common and subordinated units is almost entirely dependent upon Cove Points ability to generate Net Operating Income, our pipelines ability to generate cash from operations and
Iroquois ability to make distributions to its partners. Due to our relative lack of asset diversification, an adverse development at Cove Point, our pipelines or Iroquois would have a significantly greater impact on our financial condition and
results of operations than if we maintained a more diverse portfolio of assets. Cove Points ability to make payments
on the Preferred Equity Interest, our pipelines cash generated from operations and Iroquois ability to make distributions to its partners will depend on several factors beyond our
control, some of which are described below.
The Preferred Equity Interest is non-cumulative. Cove Point will make Preferred Return
Distributions on a quarterly basis provided it has sufficient cash and undistributed Net Operating Income (determined on a cumulative basis from the closing of the Offering) from which to make Preferred Return Distributions. Preferred Return
Distributions are non-cumulative. In the event Cove Point is unable to fully satisfy Preferred Return Distributions during any quarter, we will not have a right to recover any missed or deficient payments.
An inability to obtain needed capital or financing on satisfactory terms, or at all, could have an adverse effect on our operations and
ability to generate cash flow. We are dependent on our credit facility with Dominion for any borrowings necessary to meet our working capital and other financial needs. In certain circumstances, we are able to extend the credit facility at our
option. However, there can be no assurance that conditions for such extension will be met. A new credit facility with Dominion may bear a higher interest rate than the current credit facility, which could adversely affect our cash flow.
If Dominions funding resources were to become unavailable to Dominion, our access to funding would also be in jeopardy. In the future,
an inability to obtain additional financing from other sources on acceptable terms could negatively affect our financial condition, cash flows, anticipated financial results or impair our ability to generate additional cash flows. Our ability to
obtain bank financing or to access the capital markets for future debt or equity offerings may be limited by our financial condition at the time of any such financing or offering, the covenants contained in any other credit facility or other debt
agreements in place at the time, adverse market conditions or other contingencies and uncertainties that are beyond our control. Our failure to obtain the funds necessary to maintain, develop and increase our asset base could adversely impact our
growth and profitability.
If we do not make acquisitions on economically acceptable terms or fail to adequately integrate acquired
assets, our future growth and our ability to increase distributions to our unitholders will be limited. Our ability to grow depends on our ability to make accretive acquisitions either from Dominion or third parties, such as the Questar Pipeline
Acquisition and we may be unable to do so for any of the following reasons, without limitation:
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We are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them; |
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We are unable to obtain or maintain necessary governmental approvals; |
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We are unable to obtain financing for the acquisitions or future organic growth opportunities on acceptable terms, or at all; |
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We are unable to secure adequate customer commitments to use the future facilities; |
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We are outbid by competitors; or |
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Dominion may not offer us the opportunity to acquire assets or equity interests from it. |
Additionally, a failure to adequately integrate acquired assets into our processes and systems could impact operations and result in
compliance risks.
We may not be able to obtain financing or successfully negotiate future acquisition
opportunities offered by Dominion. If Dominion offers us the opportunity to purchase additional equity interests in Cove Point or interests in Blue Racer or Atlantic Coast Pipeline, or other assets or equity interests, we may not be able to
successfully negotiate a purchase and sale agreement and related agreements, we may not be able to obtain any required financing on acceptable terms or at all for such purchase and we may not be able to obtain any required governmental and third
party consents. The decision whether or not to accept such offer, and to negotiate the terms of such offer, will be made by our general partner consistent with its duties under our partnership agreement. Our general partner may decline the
opportunity to accept such offer for a variety of reasons, including a determination that the acquisition of the assets at the proposed purchase price would result in a risk that the conversion of subordinated units would not occur.
The acquisitions we may make could adversely affect our business and cash flows. The acquisitions we may make involve potential risks,
including:
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An inability to integrate successfully the businesses that we acquire with our existing operations; |
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A decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the acquisition; |
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A substantial increase in our indebtedness and working capital requirements; |
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The assumption of unknown liabilities; |
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Limitations on rights to indemnity from the seller; |
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Mistaken assumptions about the cash generated, or to be generated, by the business acquired or the overall costs of equity or debt; |
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Incorrect assumptions about capital investments and required operating and maintenance expenditures; |
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The diversion of managements attention from other business concerns; and |
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Unforeseen difficulties encountered in operating new business segments or in new geographic areas. |
In connection with acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the
opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our future funds and other resources.
Our level of indebtedness may increase and reduce our financial flexibility and ability to pay distributions. At December 31,
2016, we had the following outstanding indebtedness: $63.2 million under our $300.0 million credit facility with Dominion, $300.0 million under a term loan agreement and $435.0 million of senior and medium-term notes acquired in connection
with the Questar Pipeline Acquisition. We may borrow under our $300.0 million credit facility with Dominion to pursue acquisitions and future organic growth opportunities, or to otherwise meet our financial needs. Although the credit facility
does not contain any financial tests and covenants that we must satisfy as a condition to making distributions, we are required to pay any amounts then due and payable under such agreement prior to making any distributions to our unitholders,
notwithstanding our stated cash distribution policy. Also, while such credit facility only contains limited representations, warranties and ongoing covenants consistent with other credit facilities
made available by Dominion to certain of its other affiliates, we are required to obtain Dominions consent prior to creating any mortgage, security interest, lien or other encumbrance
outside the ordinary course of business on any of our property, assets or revenues during the term of such agreement. Failure to obtain any such consent from Dominion in the future could have an adverse impact on our ability to implement our
business strategies, generate revenues and pay distributions to our unitholders.
In connection with the Questar Pipeline Acquisition, we
borrowed $300.0 million under a term loan agreement that matures in December 2019. Interest on the borrowed amount accrues at a variable rate determined based on our ratio of total debt to cash flow, and interest payments are due on a quarterly
basis. Upon maturity of the term loan agreement, any amounts then due and payable will need to be paid before we are permitted to make distributions to our unitholders. The term loan agreement contains customary representations, warranties and
covenants consistent with other debt arrangements made available to similarly situated borrowers. See Note 15 to the Consolidated Financial Statements for additional information.
In the future, we may incur additional significant indebtedness pursuant to other term loans, credit facilities or similar arrangements in
order to make future acquisitions or to develop our assets. As amounts under any indebtedness we incur become due and payable, we expect that the instruments pursuant to which such indebtedness is incurred will require that we repay such amounts
prior to making any distributions to our unitholders. We also expect that such instruments may contain financial tests and covenants that are not present in our credit facility with Dominion that we would need to satisfy as a condition to making
distributions. Should we be unable to satisfy any such restrictions, we will be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy.
Our level of indebtedness could affect our ability to generate stable and growing cash flows in several ways, including the following:
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A significant portion of our cash flows could be used to service our indebtedness; |
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The covenants contained in the agreements governing our future indebtedness may limit our ability to borrow additional funds, dispose of assets, pay distributions and make certain investments; |
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Our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; |
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A high level of debt would increase our vulnerability to general adverse economic and industry conditions; |
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A high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore may be able to take advantage of opportunities that our indebtedness would prevent us
from pursuing; and |
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A high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, debt-service requirements, acquisitions, general partnership or other purposes.
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In addition, borrowings under our credit facility with Dominion and the term loan agreement bear interest at variable
rates. Additionally, credit facilities we or our subsidiaries may enter into
in the future may bear interest at variable rates. If the interest rates on future credit facilities are tied to market interest rates and market interest rates increase, such variable-rate debt
will create higher debt-service requirements, which could adversely affect our cash flow.
In addition to our debt-service obligations,
our future operations may require substantial investments on a continuing basis. Our ability to make scheduled debt payments, to refinance our obligations with respect to our indebtedness and to fund capital and non-capital expenditures necessary to
maintain the condition of our operating assets, properties and systems software, as well as to provide capacity for the growth of our business, depends on our financial and operating performance. General economic conditions and financial, business
and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity
financing may not be available to pay or refinance such debt.
Cost and expense reimbursements owed to our general partner and its
affiliates will reduce the amount of distributable cash flow to our unitholders. Our general partner will not receive a management fee or other compensation for its management of our partnership, but we are obligated to reimburse our general
partner and its affiliates for all expenses incurred and payments made on our behalf. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform various general, administrative and support services for
us or on our behalf, and corporate overhead costs and expenses allocated to us by Dominion. Our partnership agreement provides that our general partner will determine the costs and expenses that are allocable to us and does not set a limit on the
amount of expenses for which our general partner and its affiliates may be reimbursed. The payment of fees to our general partner and its affiliates and the reimbursement of expenses could adversely affect our ability to pay cash distributions to
our unitholders.
RISKS INHERENT IN OUR INVESTMENT IN COVE
POINT
Cove Points revenue is generated by contracts with a limited number of customers, and Cove Points ability to
generate cash required to make payments on the Preferred Equity Interest is substantially dependent upon the performance of these customers under their contracts. Cove Point provides service to approximately 30 customers, including the Storage
Customers, marketers or end users and the Import Shippers. The three largest customers comprised approximately 90%, 90% and 93% of the total transportation and storage revenues for the years ended December 31, 2016, 2015 and 2014, respectively.
Cove Points largest customer represented approximately 70%, 70% and 72% of such amounts in 2016, 2015 and 2014, respectively. Because Cove Point has a small number of customers, its contracts subject it to counterparty risk. The ability of
each of Cove Points customers to perform its obligations to Cove Point will depend on a number of factors that are beyond our control. Cove Points future results and liquidity are substantially dependent upon the performance of these
customers under their contracts, and on such customers continued willingness and ability to perform their
contractual obligations. Cove Point is also exposed to the credit risk of any guarantor of these customers obligations under their respective agreements in the event that Cove Point must
seek recourse under a guaranty. Any such credit support may not be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under an agreement resulting in a judgment in Cove Points
favor where the counterparty has limited assets in the U.S. to satisfy such judgment, Cove Point may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process. Upon the expiration of Cove
Points import contracts, we expect these contracts will not be renewed.
Cove Points contracts may become subject to
termination or force majeure provisions under certain circumstances that, if triggered for any reason, could have an adverse effect on Cove Point and its ability to make payments on the Preferred Equity Interest. In the event any of Cove
Points customers become entitled to terminate their further contractual obligations to Cove Point and exercise such right, such termination could have a material adverse effect on Cove Points business, financial condition, operating
results, cash flow, liquidity and prospects, which could have an adverse impact on Cove Points ability to pay the Preferred Return Distributions.
Cove Point is not currently receiving any revenues under its export contracts, and the export contracts may be terminated by Export
Customers if certain conditions precedent are not met or for other reasons. Cove Points agreements with the Export Customers, while executed, will not begin generating revenues for Cove Point prior to the completion of the Liquefaction
Project. In addition, the Export Customers may become entitled to terminate, or be relieved from, their contractual obligations to Cove Point under certain circumstances, including: (i) failure of certain conditions precedent to be met or
waived by specified dates; (ii) the occurrence and continuance of certain events of force majeure (including the loss of Non-FTA Authorization); (iii) delays in the commencement of commercial operations of the Liquefaction Project beyond
specified time periods; and (iv) failure by Cove Point to satisfy its contractual obligations after any applicable cure periods. If such agreements were terminated, there can be no assurance that Cove Point will be able to replace such
agreements on comparable terms. Our ability to effect such a replacement is dependent upon, among other things, the global market for LNG. The termination of, and failure to replace, the export contracts could have an adverse impact on Cove
Points ability to pay the Preferred Return Distributions following the expiration of certain of its contracts with Statoil described below if Cove Point was unable to generate sufficient annual cash flows from other sources.
Cove Points existing revenue streams will be insufficient to pay the full amount of Preferred Return Distributions commencing
May 1, 2017. Through December 31, 2016, Cove Point had 800,000 Dths/day of regasification and firm transportation capacity under contract with Statoil pursuant to an import contract. Cove Point currently has 277,650 Dths/day of such
capacity under contract with Statoil. Statoils obligations under the import contract expire on May 1, 2017 in order to provide capacity to be utilized in connection with the Liquefaction Project. Following the expiration of this contract
with Statoil, unless the Liquefaction Project is completed, Cove Point is not expected to generate annual cash flows sufficient to pay Preferred Return Distributions in full. In October 2016, we
caused Cove Point to set aside a distribution reserve sufficient to pay two quarters of Preferred Return Distributions (and two quarters of similar distributions with respect to any other
preferred equity interests in Cove Point). However, there can be no assurance that funds will be available or sufficient for such purpose or that Cove Point will have sufficient cash and undistributed Net Operating Income to permit it to continue to
make Preferred Return Distributions after the expiration of the Statoil contracts.
Cove Point may be unable to complete the Liquefaction
Project for a variety of reasons, some of which are outside of its control, and some of which are described below. In the event Cove Point is unable to complete the Liquefaction Project or if the export contracts are terminated and not replaced and,
in either case, Cove Point does not have sufficient cash and Net Operating Income from other sources following the expiration of its import contract with Statoil referenced above, Cove Point will not be able to pay the Preferred Return Distributions
and distributions with respect to any future preferred equity interests acquired by us. The inability of Cove Point to make Preferred Return Distributions could have a significant impact on our ability to pay distributions to our unitholders.
Similarly, the inability of Cove Point to generate revenues sufficient to support the payment of distributions on additional preferred equity interests that may otherwise be made available to us could adversely impact our overall business plan and
ability to generate stable and growing cash flows.
Various factors could negatively affect the timing or overall development of the
Liquefaction Project, which could adversely affect Cove Points ability to make payments on the Preferred Equity Interest after May 1, 2017. Completion of the Liquefaction Project could be delayed by factors such as:
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The ability to obtain or maintain necessary permits, licenses and approvals from agencies and third parties that are required to construct or operate the Liquefaction Project; |
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Force majeure events, weather conditions, shortages of materials or delays in the delivery of materials, and as construction progresses, Cove Point may decide or be forced to submit change orders to its contractors that
could result in longer construction periods; |
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The ability to attract sufficient skilled and unskilled labor and the existence of any labor disputes, and Cove Points ability to maintain good relationships with its contractors in order to construct the
Liquefaction Project within the expected parameters and the ability of those contractors to perform their obligations; and |
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Dominions ability and willingness to provide funding for the development of the Liquefaction Project and, if necessary, Cove Points ability to obtain additional funding for the development of the
Liquefaction Project. |
Any delay in completion of the Liquefaction Project may prevent Cove Point from commencing
liquefaction operations when anticipated, which could cause a delay in the receipt of revenues therefrom, require Cove Point to pay damages to its customers, or in event of significant delays beyond certain time periods, permit either or both of
Cove Points Export Customers to terminate their contractual obligations to Cove Point. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on Cove Points operating results and its
ability to make payments on the Preferred Equity Interest. In addition, the successful completion of the
Lique-
faction Project is subject to the risk of cost overruns, which may make it difficult to finance the completion of the Liquefaction Project.
Cove Point is dependent on its contractors for the successful completion of the Liquefaction Project and may be unable to complete the
Liquefaction Project on time. There is limited recent industry experience in the U.S. regarding the construction or operation of large-scale liquefaction facilities. The construction of the Liquefaction Project is confined within a limited
geographic area and could be subject to delays, cost overruns, labor disputes and other factors that could adversely affect Cove Points financial performance or impair its ability to execute the business plan for the Liquefaction Project as
scheduled. Timely and cost-effective completion of the Liquefaction Project in compliance with agreed-upon specifications is highly dependent upon the performance of Cove Points contractors pursuant to their agreements. Further, faulty
construction that does not conform to Cove Points design and quality standards may also have a similar adverse effect. For example, improper equipment installation may lead to a shortened life of Cove Points equipment, increased
operations and maintenance costs or a reduced availability or production capacity of the affected facility. The ability of Cove Points contractors to perform successfully under their agreements is dependent on a number of factors, including
force majeure events and the contractors ability to:
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Design, engineer and receive critical components and equipment necessary for the Liquefaction Project to operate in accordance with specifications and address any start-up and operational issues that may arise in
connection with the commencement of commercial operations; |
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Attract, develop and retain skilled personnel and engage and retain third party subcontractors, and address any labor issues that may arise; |
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Post required construction bonds and comply with the terms thereof, and maintain their own financial condition, including adequate working capital; and |
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Respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control and manage the construction process generally,
including coordinating with other contractors and regulatory agencies and dealing with inclement weather conditions. |
Although some agreements with Cove Points contractors may provide for liquidated damages, if the contractor fails to perform in the
manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operations of the Liquefaction Project and any liquidated damages that Cove Point receives may not be
sufficient to cover the damages that it suffers as a result of any such delay or impairment. Furthermore, Cove Point may have disagreements with its contractors about different elements of the construction process, which could lead to the assertion
of rights and remedies under the related contracts resulting in a contractors unwillingness to perform further work on the Liquefaction Project. Cove Point may also face difficulties in commissioning a newly constructed facility. Any
significant project delays in the construction of the Liquefaction Project could have a material adverse effect on Cove Points ability to make payments on the Preferred Equity Interest.
Cove Point is dependent on Dominion to fund the costs necessary to construct infrastructure
projects, including the Liquefaction Project. If Dominion is unwilling or unable to supply the funding necessary to complete infrastructure projects, Cove Point may be required to seek additional financing in the future and may not be able to secure
such financing on acceptable terms. Cove Point began construction on the Liquefaction Project, which is estimated to cost approximately $4.0 billion, excluding financing costs. Cove Point also is currently constructing the Keys Energy
Project, which is expected to cost approximately $40 million and be placed into service in March 2017. Additionally, in November 2016, Cove Point filed an application to request FERC authorization to construct the approximately $150 million Eastern
Market Access Project. Construction on this project is expected to begin in the fourth quarter of 2017, and the project facilities are expected to be placed into service in late 2018.
To date, Dominion has funded development and construction costs associated with these expansion projects. Dominion has indicated that it
intends to provide the funding necessary for the remaining construction costs and other capital expenditures of Cove Point, but it has no contractual obligation to do so and has not secured all of the funding necessary to cover these costs, as it
intends to finance these costs as they are incurred using its consolidated operating cash flows in addition to proceeds from capital markets transactions. Cove Points existing revenue streams and cash reserves will be insufficient for it to
complete these infrastructure projects. If Dominion is unwilling to provide funding for the remaining construction costs and other capital expenditures, or is unable to obtain such funding in the amounts required or on terms acceptable to Dominion,
Cove Point would have to obtain additional funding from lenders, in the capital markets or through other third parties. Any such additional funding may not be available in the amounts required or on terms acceptable to Cove Point and Dominion
Midstream. The failure to obtain any necessary additional funding could cause these expansion projects to be delayed or not be completed.
If Cove Point does obtain bank financing or access the capital markets, incurring additional debt may significantly increase interest expense
and financial leverage, which could compromise Cove Points ability to fund future development and acquisition activities and restrict Cove Points ability to make payments on the Preferred Equity Interest, which would in turn limit our
ability to make distributions to our unitholders.
Dominion has also entered into guarantee arrangements on behalf of Cove Point to
facilitate the Liquefaction Project, including guarantees supporting the terminal services and transportation agreements as well as the engineering, procurement and construction contract for the Liquefaction Project. Two of the guarantees have no
stated limit, one guarantee has a $150 million limit, and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million. If Cove Point was required to replace these guarantees with other credit support, the cost could
be significant.
Some of the approvals for the construction of the Liquefaction Project may be subject to further conditions, review
and/or revocation. Cove Point has received the required approvals to commence construction of the Liquefaction Project from the DOE, FERC and the Maryland Commission, which are subject to compliance with the applicable permit conditions.
However, all DOE export licenses are subject to review and possible withdrawal should the DOE conclude that such export authorization
is no longer in the public interest. The issuance of the FERC Order approving the Liquefaction Project was upheld by the D.C. Circuit. Cove Point does not know whether any existing or potential
interventions or other actions by third parties will interfere with Cove Points ability to maintain such approvals, but loss of any material approval could have a material adverse effect on the construction or operation of the facility. In
addition, the Liquefaction Project has been the subject of litigation in the past and could be the subject of litigation in the future. Failure to comply with regulatory approval conditions or an adverse ruling in any future litigation could
adversely affect Cove Points operations, financial condition, and ability to make payments on the Preferred Equity Interest.
To
maintain the cryogenic readiness of the Cove Point LNG Facility, Cove Point may need to purchase and process LNG. Cove Point needs to maintain the cryogenic readiness of the Cove Point LNG Facility when the terminal facilities are not being used
by existing customers. Each year, one or two LNG cargos are procured and are billed to Cove Points Import Shippers pursuant to a cost recovery mechanism set forth in Cove Points FERC gas tariff. This cost recovery mechanism expired by
its terms on December 31, 2016. Cove Point included such mechanism in its rate case filed in November 2016, but until such rate case is approved, there can be no assurance that a similar recovery mechanism will be available. Following the
completion of the Liquefaction Project, the Cove Point LNG Facility will be a bi-directional facility, reducing the risk that it will not be used for either import or export, and the addition of liquefaction facilities, which can be used to liquefy
any boil-off gas, is expected to reduce any need for Cove Point to procure LNG for cooling purposes. However, Cove Point may need to maintain or obtain funds necessary to procure LNG to maintain the cryogenic readiness of the Cove Point LNG Facility
in the future, which could adversely impact its ability to make payments on the Preferred Equity Interest.
RISKS INHERENT
IN OUR BUSINESS GENERALLY
We are dependent on contractors and regulators for the
successful completion of infrastructure projects and may be unable to complete infrastructure projects within initially anticipated timing. Infrastructure projects have been announced and additional projects may be considered in the future. We
compete for projects with companies of varying size and financial capabilities, including some that may have advantages competing for natural gas supplies. Commencing construction on announced and future projects may require approvals from
applicable state and federal agencies. Projects may not be able to be completed on time as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties,
difficulties with partners or potential partners, a decline in the credit strength of counterparties or vendors, or other factors beyond our control. Even if facility construction, pipeline, expansion and other infrastructure projects are completed,
the total costs of the projects may be higher than anticipated and the performance of our business following completion of the projects may not meet expectations. Start-up and operational issues can arise in connection with the commencement of
commercial operations at our facilities. Such issues may include
failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, we may not be able to timely and effectively
integrate the projects into our operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be
prudently incurred. Any of these or other factors could adversely affect our ability to realize the anticipated benefits from the infrastructure projects.
We may not be able to maintain, renew or replace our existing portfolio of customer contracts successfully, or on favorable terms and since
these contracts are with a limited number of customers, we are subject to customer concentration risk. Upon contract expiration, customers may not elect to re-contract with us as a result of a variety of factors, including the amount of
competition in the industry, changes in the price of natural gas and supply areas, their level of satisfaction with our services, the extent to which we are able to successfully execute our business plans and the effect of the regulatory framework
on customer demand. The failure to replace any such customer contracts on similar terms could result in a loss of revenue for us. Further, we are subject to customer concentration risk in that several customers represent the majority of our
contracted capacity. Producers with direct commodity price exposure face liquidity constraints, which could present a credit risk to Dominion Midstream.
Our business is exposed to customer credit risk, and we may not be able to fully protect ourselves against such risk. Our business is
subject to the risks of nonpayment and nonperformance by our customers. We have in the past and expect to continue to undertake capital expenditures based on commitments from customers upon which we expect to realize a return. Nonperformance by our
customers of those commitments or termination of those commitments resulting from our inability to timely meet our obligations could result in substantial losses to us. In addition, some of our customers, counterparties and suppliers may be highly
leveraged and subject to their own operating and regulatory risks and, even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. Volatility in commodity prices might have
an impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us. We manage our exposure to credit risk through credit analysis and monitoring procedures, and sometimes collateral, such
as letters of credit, prepayments, liens on customer assets and guarantees. However, these procedures and policies cannot fully eliminate customer credit risk, and to the extent our policies and procedures prove to be inadequate, it could negatively
affect our financial condition and results of operations.
Our results of operations, as well as construction of the Liquefaction
Project and our infrastructure projects, may be affected by changes in the weather. Fluctuations in weather can affect demand for our services. For example, milder than normal weather can reduce demand for gas transmission services. In addition,
severe weather, including hurricanes, winter storms, earthquakes, floods and other natural disasters can disrupt operation of our facilities and cause service outages, construction delays and property damage that require incurring additional
expenses. Furthermore, our operations, especially Cove Point, could be adversely affected and our physical plant placed at greater risk of
damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather
events, abnormal levels of precipitation or a change in sea level or sea temperatures.
Our operations and construction activities are
subject to operational hazards, equipment failures, supply chain disruptions and personnel issues, which could create significant liabilities and losses, and negatively affect Cove Points ability to make payments on the Preferred Equity
Interest and our ability to make distributions. Operation of our facilities and the construction of the Liquefaction Project and infrastructure projects involves risk, including the risk of potential breakdown or failure of equipment or
processes due to aging infrastructure, regulatory compliance deficiencies, pipeline integrity, including potential seam deficiencies, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of
terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below
expected levels. Because our transmission facilities, pipelines and other facilities are interconnected with those of third parties, the operation of our facilities and pipelines could be adversely affected by unexpected or uncontrollable
events occurring on the systems of such third parties. Our business is dependent upon sophisticated information technology systems and network infrastructure, the failure of which could prevent us from accomplishing critical business functions.
Operation of our facilities below expected capacity levels could result in lost revenues and increased expenses, including higher
maintenance costs. Unplanned outages of our facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are inherent risks of our business. Unplanned outages typically increase operation
and maintenance expenses and may reduce our revenues as a result of selling fewer services or incurring increased rate credits to customers. If we are unable to perform our contractual obligations, penalties or liability for damages could result.
In addition, there are many risks associated with our operations and the transportation, storage and processing of natural gas and LNG,
including fires, explosions, uncontrolled releases of natural gas or other substances, the collision of third party equipment with pipelines and other environmental incidents. Such incidents could result in the loss of human life or injuries among
employees, customers or the public in general, environmental pollution, damage or destruction of facilities or the property of third parties; business interruptions and associated public or employee safety impacts; loss of revenues, increased
liabilities, heightened regulatory scrutiny, and reputational risk. Further, the location of pipelines and storage facilities, or transmission facilities near populated areas, including residential areas, commercial business centers and industrial
risks, could increase the level of damages resulting from these risks. We maintain property and casualty insurance that may cover certain damage and claims caused by such incidents, but other damage and claims arising from such incidents may not be
covered or may exceed the amount of any insurance available, in which case such risks or losses could create significant liabilities that negatively affect Cove
Points ability to make payments on the Preferred Equity Interest or our ability to make distributions.
We are subject to complex governmental regulation, including pipeline safety and integrity regulations, that could adversely affect our
results of operations and subject us to monetary penalties. Our operations are subject to extensive federal, state and local regulation, including the NGPSA, and require numerous permits, approvals and certificates from various
governmental agencies. Such laws and regulations govern the terms and conditions of the services we offer, our relationships with affiliates, protection of our critical infrastructure assets and pipeline safety, among other matters. Our businesses
are subject to regulatory regimes which could result in substantial monetary penalties if we are found not to be in compliance.
Federal
and state agencies frequently impose conditions on our activities. These restrictions have become more stringent over time and can limit or prevent the construction of new transmission or distribution pipelines and related facilities. For example,
we are subject to regulation by the DOT under PHMSA, which has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. PHMSA non-compliance presents a risk
due to significant legislative mandates and pending rulemaking. The most recent reauthorization of PHMSA included new provisions on historical records research, maximum-allowed operating pressure validation, use of automated or remote-controlled
valves on new or replaced lines, increased civil penalties, and evaluation of expanding integrity management beyond high-consequence areas. PHMSA has not yet issued new rulemaking on most of these items. New laws or regulations, the revision or
reinterpretation of existing laws or regulations, changes in enforcement practices of regulators, or penalties imposed for non-compliance with existing laws or regulations may result in substantial additional expense.
Our operations are also subject to a number of environmental laws and regulations that impose significant compliance costs on us, and
existing and future environmental and similar laws and regulations could result in increased compliance costs or additional operating restrictions. Our operations and the Liquefaction Project and infrastructure projects are subject to extensive
federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, handling and disposal of hazardous materials and other wastes, and protection of natural resources and human health and safety. Many of
these laws and regulations, such as the CAA, the CWA, the Oil Pollution Act of 1990, and the Resource Conservation and Recovery Act, as amended, and analogous state laws and regulations require us to commit significant capital toward permitting,
emission fees, environmental monitoring, installation and operation of pollution control equipment and the purchase of emission allowances and/or offsets in connection with the construction and operations of facilities. Violation of these laws and
regulations could lead to substantial liabilities, fines and penalties or to capital expenditures related to pollution control equipment that could have a material adverse effect on our business, contracts, financial condition, operating results,
cash flow, liquidity and prospects. Additionally, federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the
environment.
Revised, reinterpreted or additional laws and regulations that result in increased compliance
costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are unable to estimate our compliance costs with certainty due to our inability to predict the requirements and timing of implementation of
any future environmental rules or regulations. Other factors that affect our ability to predict future environmental expenditures with certainty include the difficulty in estimating any future clean-up costs and quantifying liabilities under
environmental laws that impose joint and several liability on all responsible parties. However, such expenditures, if material, could result in the impairment of assets or otherwise adversely affect the results of our operations, financial
performance or liquidity and the ability of Cove Point to make payments on the Preferred Equity Interest or our ability to make distributions.
Any additional federal and/or state requirements imposed on energy companies mandating limitations on GHG emissions or requiring efficiency
improvements, may adversely impact our business. There are potential impacts on our natural gas businesses as federal or state GHG legislation or regulations may require GHG emission reductions from the natural gas sector and could affect demand
for natural gas. Several regions of the U.S. have moved forward with GHG emission regulations, such as in the Northeast. There are numerous other regulatory approaches currently in effect or being considered to address GHGs, including possible
future regulation by the EPA, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, or U.S. treaty commitments. Additional regulation of air emissions, including GHGs, under the CAA may be
imposed on the natural gas sector, including rules to limit methane gas emissions. For example, the EPA adopted regulations in May 2016 to regulate upstream methane emissions from oil and gas production. Compliance with GHG emission reduction
requirements may require the retrofitting or replacement of equipment or could otherwise increase the cost to operate and maintain our facilities. Additionally, GHG requirements could result in increased demand for energy conservation and renewable
products, which in turn could affect demand for natural gas.
Potential changes in accounting practices may adversely
affect our financial results. We cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or our operations specifically. New accounting standards
could be issued that could change the way we record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect earnings or could increase liabilities.
War, intentional acts and other significant events could adversely affect our operations or the construction of the Liquefaction Project
and infrastructure projects. We cannot predict the impact that world hostility may have on the energy industry in general or on our business in particular, including the construction of the Liquefaction Project and infrastructure projects. Any
retaliatory military strikes or sustained military campaign may affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets. In addition, our infrastructure facilities could be
direct targets of, or indirect casualties of, an act of terror. Furthermore, the
phys-
ical compromise of our facilities could adversely affect our ability to manage our facilities effectively. Instability in financial markets as a result of terrorism, war, intentional acts,
pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy and increase the cost of insurance coverage, which could negatively impact our results of operations, financial condition and Cove
Points ability to make payments on the Preferred Equity Interest or our ability to make distributions.
We are dependent upon our
affiliates and their key personnel and employees, and we may not find a suitable replacement if the services agreements with DRS and other affiliates are terminated or such key personnel are no longer available to us, which would materially and
adversely affect us. We are managed and operated by the Board of Directors and executive officers of Dominion Midstream GP, LLC, our general partner. We do not have any employees, nor does our general partner. All of the employees
that conduct our business are employed by affiliates, and our general partner secures the personnel necessary to conduct our operations through its services agreement with DRS. Our executive officers and the employees that conduct our business
may have conflicts in allocating their time and services among us and our affiliates. Although our Board of Directors has control over our executive officers, we have no authority over the individual employees. Accordingly, we are reliant
upon, and our success depends upon, our affiliates personnel and services. The failure of any of our affiliates key personnel to service our business with the requisite time and dedication, the departure of such personnel from our
affiliates or the failure of our affiliates to attract and retain key personnel would each materially and adversely affect our ability to conduct our business. Furthermore, if any of the services agreements with DRS or other affiliates are
terminated and suitable replacements for such entities are not secured in a timely manner or at all, we would likely be unable to conduct our business, which would materially and adversely affect us.
Hostile cyber intrusions could severely impair our operations, lead to the disclosure of confidential information, damage our reputation
and otherwise have an adverse effect on our business. We own assets deemed by FERC as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run our facilities are not
completely isolated from external networks. Parties that wish to disrupt the U.S. gas transmission system or our operations could view our computer systems, software or networks as attractive targets for a cyber-attack. For example, malware has been
designed to target software that runs the nations critical infrastructure such as gas pipelines. In addition, our businesses require that we and our vendors collect and maintain sensitive customer data, as well as confidential employee and
unitholder information, which is subject to electronic theft or loss.
A successful cyber attack on the systems that control our gas
transmission assets or the Cove Point Facilities could severely disrupt business operations, preventing us from serving customers or collecting revenues. The breach of certain business systems could affect our ability to correctly record, process
and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and
damage to our reputation. In addition, the misappropriation, corruption or loss of
personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses, such as credit monitoring. We maintain property and
casualty insurance that may cover certain damage caused by potential cybersecurity incidents; however, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a
significant cyber incident could materially and adversely affect our business, financial condition, results of operations and Cove Points ability to make payments on the Preferred Equity Interest or our ability to make distributions.
Certain of our operations are subject to FERCs rate-making policies, which could limit our ability to recover the full cost of
operating our assets, including earning a reasonable return, and have an adverse effect on Cove Points ability to make payments on the Preferred Equity Interest or our ability to make distributions. We are subject to extensive
regulations relating to the jurisdictional rates we can charge for our natural gas regasification, storage and transportation services. FERC establishes both the maximum and minimum rates we can charge for jurisdictional services. The basic elements
of rate-making that FERC considers are the costs of providing service, the volumes of gas being transported and handled, the rate design, the allocation of costs between services, the capital structure and the rate-of-return that a regulated entity
is permitted to earn. The profitability of our business is dependent on our ability, through the rates that we are permitted to charge, to recover costs and earn a reasonable rate of return on our capital investment. FERC or our customers can
challenge our existing jurisdictional rates, which we may be required to change should FERC find those rates to be unjust and unreasonable. Such a challenge could adversely affect our ability to maintain current revenue levels.
In November 2016, Cove Point filed a rate case with new jurisdictional rates effective January 1, 2017. This case is pending. DCG is
subject to a rate moratorium which precludes DCG from filing a Section 4 NGA rate case to establish base rates that would be effective prior to January 1, 2018.
Upon filing a rate case, or when or if Cove Point, DCG, Questar Pipeline or Iroquois has to defend its rates in a proceeding commenced by a
customer or FERC, it will be required, among other things, to support its rates, by showing that they reflect recovery of its costs plus a reasonable return on its investment, in accordance with cost of service ratemaking. In January 2016, FERC
initiated an investigation, pursuant to Section 5 of the NGA, to determine whether the rates currently charged by Iroquois are just and reasonable. Iroquois filed a settlement reducing its rates that was accepted by FERC in October 2016.
In addition, as part of our obligations to support rates, we are required to establish the inclusion of an income tax allowance in our cost of
service as just and reasonable. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a MLP.
FERCs current policy permits pipelines and storage companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines and storage companies owned by partnerships or limited
liability companies, the current tax allowance policy reflects the actual or potential income tax liability on the FERC jurisdictional income
attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. FERC issued the Notice
of Inquiry in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would
not double recover its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. We cannot predict whether FERC will successfully justify its
conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax allowances or return on equity calculations for pipeline companies organized as part of a MLP.
However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as a part of a MLP or decreases the return on equity for such pipelines could result in an adverse impact on our revenues associated with
the transportation and storage services we provide pursuant to cost-based rates. Some entities have authority to charge market-based rates and therefore this tax allowance issue does not affect the rates that they charge their customers.
An adverse determination by FERC with respect to our open access rates could have a material adverse effect on our revenues, earnings and cash
flows and Cove Points ability to make payments on the Preferred Equity Interest or our ability to make distributions.
If the
corporate tax rate is reduced from current levels, FERC may initiate rate filings for any or all of our jurisdictional pipeline entities. A lower statutory tax rate may result in a reduction in rates that our pipeline entities are allowed to charge
customers and a corresponding reduction in our revenues and cash flows. As a pass-through entity, we are not subject to entity-level taxation, and thus would not experience a corresponding reduction in our cash expenses.
RISKS INHERENT IN AN INVESTMENT IN US
Dominion owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner
and its affiliates, including Dominion, have conflicts of interest with us and limited duties, and they may favor their own interests to our detriment and that of our unitholders. Dominion owns and controls our general partner and appoints all
of the directors of our general partner. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage
our general partner in a manner beneficial to Dominion. Therefore, conflicts of interest may arise between Dominion or any of its affiliates, including our general partner, on the one hand, and us or any of our unitholders, on the other hand. In
resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:
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Our general partner is allowed to take into account the interests of parties other than us, such as Dominion, in exercising certain rights under our partnership agreement;
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Neither our partnership agreement nor any other agreement requires Dominion to pursue a business strategy that favors us; |
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Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partners liabilities and restricts
the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty; |
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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; |
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Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash
that is distributed to our unitholders; |
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Our general partner determines the amount and timing of any cash expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital
expenditure, which does not reduce operating surplus. This determination can affect the amount of cash from operating surplus that is distributed to our unitholders, which, in turn, may affect the ability of the subordinated units to convert;
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Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make
incentive distributions or to accelerate the expiration of the subordination period; |
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Our partnership agreement permits us to distribute up to $45.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute
capital surplus. This cash may be used to fund distributions on our subordinated units or the IDRs; |
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Our general partner determines which costs incurred by it and its affiliates are reimbursable by us; |
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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our
behalf; |
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Our general partner intends to limit its liability regarding our contractual and other obligations; |
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Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the outstanding common units; |
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Our general partner controls the enforcement of obligations that it and its affiliates owe to us; |
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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and |
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Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partners IDRs without the approval of the Conflicts
Committee or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.
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In addition, we may compete directly with Dominion and entities in which it has an interest for
acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us.
The Board of Directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our
partnership agreement does not require us to pay any distributions at all on our common and subordinated units. The Board of Directors of our general partner adopted a cash distribution policy pursuant to which we intend to make quarterly
distributions on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the Board of
Directors of our general partner may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters.
In addition, our partnership agreement does not require us to pay any distributions at all on our common and subordinated units. Accordingly,
investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of
distributions to our common and subordinated unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the Board of Directors of our general partner, whose interests may differ
from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of Dominion to the detriment of our common unitholders.
Our general partner intends to limit its liability regarding our obligations. Our general partner intends to limit its liability under
contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur
indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partners duties,
even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or
indemnification payments would reduce the amount of cash otherwise available for distribution to our common and subordinated unitholders.
We expect to distribute a significant portion of our distributable cash flow to our partners, which could limit our ability to grow and
make acquisitions. We plan to distribute most of our distributable cash flow, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional
units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level.
There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to
finance our growth strategy would result in increased interest expense, which, in turn, may impact the cash that we have available to distribute to our common and subordinated unitholders.
Our partnership agreement replaces our general partners fiduciary duties to holders of our units. Our partnership
agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of
decisions in its individual capacity, as opposed to in its capacity as our general partner, and otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it
desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual
capacity include:
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How to allocate business opportunities among us and its affiliates; |
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Whether to exercise its limited call right; |
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How to exercise its voting rights with respect to the units it owns; |
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Whether to exercise its registration rights; |
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Whether to elect to reset target distribution levels; and |
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Whether to consent to any merger or consolidation of Dominion Midstream or amendment to the partnership agreement. |
By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the
provisions discussed above.
Our partnership agreement restricts the remedies available to holders of our units for actions taken by
our general partner that might otherwise constitute breaches of fiduciary duty. Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise
constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
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Whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner generally is required to make such determination, or take or
decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; |
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Our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable
judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its officers or directors engaged in bad faith, meaning that they believed that the decision
was adverse to the interest of Dominion Midstream or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and
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Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:
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Approved by the Conflicts Committee, although our general partner is not obligated to seek such approval; or |
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Approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates, and the Series A Preferred Units voting together as a single class.
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In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where
our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or
the Conflicts Committee then it will be presumed that, in making its decision, taking any action or failing to act, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or Dominion
Midstream, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our Series A
Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units. Our Series A Preferred Units rank senior to all of our other classes or series of equity securities
with respect to distribution rights. These preferences may adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.
In addition, distributions on the Series A Preferred Units accrue and are cumulative. Our obligation to pay distributions on our Series A
Preferred Units or on the common units issued following the conversion of such Series A Preferred Units, may impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities,
acquisitions and other general partnership purposes. Our obligations to the holders of Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our
financial condition.
Dominion and other affiliates of our general partner may compete with us. Our partnership agreement provides
that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory, and
administrative services to its affiliates or to other persons. However, affiliates of our general partner, including Dominion, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition
with us. In addition, Dominion may compete with us for investment opportunities and may own an interest in entities that compete with us.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our
general partner or any of its affiliates, including its executive officers and directors and Dominion. Any such person or
entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to
us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such
opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable
treatment of us and our unitholders.
The holder or holders of our IDRs may elect to cause us to issue common units to it in connection
with a resetting of the target distribution levels related to the IDRs, without the approval of the Conflicts Committee or the holders of our common units. This could result in lower distributions to holders of our common units. The holder or
holders of a majority of our IDRs (initially our general partner) have the right, at any time when there are no subordinated units outstanding, and we have made cash distributions in excess of the highest then-applicable target distribution for each
of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election by our general
partner, the minimum quarterly distribution will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the reset
minimum quarterly distribution), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. If our general partner elects to reset the target
distribution levels, it will be entitled to receive a number of common units equal to the number of common units that would have entitled the holder to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the
distribution on the IDRs for the quarter prior to the reset election.
We anticipate that our general partner would exercise this reset
right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per unit without such conversion. However, our general partner may transfer the IDRs at any time. It is possible
that our general partner or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the IDRs expect that we will experience declines in our
aggregate cash distributions in the foreseeable future. In such situations, the holders of the IDRs may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the IDRs and may therefore desire to be
issued our common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash
distributions that they would have otherwise received had we not issued new common units to the holders of the IDRs in connection with resetting the target distribution levels.
Unitholders have limited voting rights and are not entitled to elect our general partner or
its directors, which could reduce the price at which our common units will trade. Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence
managements decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its Board of Directors. The Board of Directors of our general partner, including the
independent directors, is chosen entirely by Dominion, as a result of it owning our general partner, and not by our unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or
conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a
takeover premium in the trading price.
Even if holders of our common units are dissatisfied, they cannot initially remove our
general partner without its consent. If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders are unable to remove our general partner without its
consent because our general partner and its affiliates own sufficient units to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common and subordinated units and Series A Preferred Units voting together as a single
class is required to remove our general partner. At December 31, 2016, Dominion owned an aggregate of 47.7% of our limited partner interest. In addition, any vote to remove our general partner during the subordination period must provide for
the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide Dominion the ability to prevent the removal of our general partner.
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
A change of control may result in default under our term loan agreement. Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not
restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. The new owner of our general partner would then be in a position to replace the Board of Directors and executive
officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the Board of Directors and executive officers of our general partner. This effectively permits a change of control without the
vote or consent of the unitholders. In addition, a change of control would constitute an event of default under our term loan agreement. During the continuance of an event of default under our term loan agreement, the administrative agent may
declare all amounts payable by us immediately due and payable. In addition, holders of our Series A Preferred Units are entitled to certain conversion and redemption rights upon a change in control.
The IDRs may be transferred to a third party without unitholder consent. Our general partner may transfer the IDRs to a third
party at any time without the consent of our unitholders. If our general partner transfers the IDRs to a third party, our
gen-
eral partner would not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time. For example, a transfer of IDRs by our general partner
could reduce the likelihood of Dominion accepting offers made by us relating to assets owned by Dominion, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or
price. If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to
acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date
three days before notice of exercise of the limited call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is
first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon
a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our
partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its limited call right.
If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently
deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended. At December 31, 2016, Dominion owned an aggregate of 50.9% of our common and subordinated units.
Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem
the units of certain unitholders. Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status or the nationality, citizenship or other related status of
our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose tax status has or is reasonably likely to have a material adverse effect on the maximum
applicable rates chargeable to our customers, (ii) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property or (iii) who fails to comply with the procedures
established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.
We may issue additional units without unitholder approval, which would dilute existing
unitholder ownership interests. Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units or other
equity interests of equal or senior rank will have the following effects:
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Our existing unitholders proportionate ownership interest in us will decrease; |
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The amount of distributable cash flow on each unit may decrease; |
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Because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
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The ratio of taxable income to distributions may increase; |
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The relative voting strength of each previously outstanding unit may be diminished; and |
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The market price of the common units may decline. |
There are no limitations in our
partnership agreement on our ability to issue units ranking senior to the common units or equal to our Series A Preferred Units. In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership
interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank to our common units may (i) reduce or eliminate the amount of distributable cash flow to our
common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) further subordinate the claims of the common unitholders to our assets in the event of our liquidation.
The market price of our common units could be adversely affected by sales of substantial amounts of our common units or Series A Preferred
Units in the public or private markets, including sales by Dominion or other large holders. At December 31, 2016, Dominion held 18,504,628 common units, 11,365,628 Series A Preferred Units and 31,972,789 subordinated units. All of
the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period.
Our Series A Preferred Units are convertible into common units on a one-for-one basis, subject to certain limitations and adjustments
and subject to certain minimum conversion amounts, (i) in whole or in part at the option of the holders of the Series A Preferred Units any time after December 1, 2018 or prior to a liquidation of Dominion Midstream or (ii) in whole or in part at
our option any time after December 1, 2019 under certain circumstances. In addition, the holders of our Series A Preferred Units are entitled to certain conversion and redemption rights upon a change of control. In certain circumstances and subject
to certain limitations, we may be permitted to issue common units in lieu of cash to satisfy redemption prices with respect to the Series A Preferred Units. The number of units issued for such payments will be determined based on the value of our
common units and the specified premium set forth in our partnership agreement for conversion or redemption of the Series A Preferred Units in certain circumstances, and could be substantial, especially during periods of significant declines in
market prices of our common units. If a substantial portion of our subordinated units or Series A Preferred Units are converted into
common units or if we issued a substantial number of common units in lieu of cash to satisfy redemption prices with respect to the Series A Preferred Units, common unitholders could
experience significant dilution.
Sales by Dominion or other large holders of a substantial number of our common units in
the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have
agreed to provide registration rights to Dominion and the purchasers of our common units and Series A Preferred Units under the Private Placement Agreement. Under our partnership agreement, our general partner and its affiliates have registration
rights relating to the offer and sale of any units that they hold. In addition, under the Private Placement Agreement, the purchasers and their assignees have registration rights with respect to (i) the common units purchased
thereunder and (ii) the common units issuable upon conversion of the Series A Preferred Units they hold. Alternatively, we may be required to undertake a future public or private offering of common units and use the net proceeds from such
offering to redeem an equal number of common units held by Dominion.
Our partnership agreement restricts the voting rights of
unitholders owning 20% or more of our units. Our partnership agreement restricts unitholders voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our
general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors of our general partner, cannot vote on any matter.
Unitholders may have liability to repay distributions. Under certain circumstances, unitholders may have to repay amounts
wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, as amended, we may not make a distribution to our unitholders if the distribution would cause our
liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners that received the distribution and knew at the time of
the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to Dominion
Midstream are not counted for purposes of determining whether a distribution is permitted.
The NYSE does not require a
publicly traded partnership like us to comply with certain of its corporate governance requirements. The common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of
independent directors on our general partners Board of Directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to stockholders of
certain corporations that are subject to all of the NYSEs corporate governance requirements.
We incur incremental general
and administrative costs as a result of being a publicly traded partnership. We have limited history operating as a publicly traded partnership. As a publicly traded partnership, we incur significant legal, accounting and other expenses that we
did not incur prior to the Offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules
implemented by the SEC and the NYSE, requires publicly traded entities to adopt various corporate governance practices that further increase our costs. The amount of our expenses or reserves for
expenses, including the costs of being a publicly traded partnership reduces the amount of cash we have for distribution to our unitholders. As a result, the amount of cash we have available for distribution to our unitholders is affected by the
costs associated with being a public company. We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. These rules and regulations increase certain of our legal and financial compliance costs and make
activities more time-consuming and costly. For example, as a result of becoming a publicly traded company, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and
disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we incur additional costs associated with our SEC reporting requirements.
TAX RISKS TO UNITHOLDERS
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes and not being subject to a material amount of entity-level
taxation. If the IRS were to treat us as a corporation for federal income tax purposes, or if we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially
reduced. The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal
income tax purposes unless we satisfy a qualifying income requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from
the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as
an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable
income at the corporate tax rate and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our
unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the
anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to
taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local, or foreign income tax purposes, the minimum quarterly distribution amount and the target
distribution amounts may be adjusted to reflect the impact of that law or interpretation on us. At the state level, several states have been evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income, franchise or other forms of taxation. Currently, we own assets and conduct business in states that impose margin or franchise taxes. In the future, we may expand our operations.
Imposition of a similar tax on us in other jurisdictions to which we expand could substantially reduce our cash available for distribution to our unitholders.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial
or administrative changes, or differing interpretations, possibly applied on a retroactive basis. The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified
by administrative, legislative, or judicial action, changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect
publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal
income tax purposes.
Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult
or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any such changes or other proposals will ultimately be enacted. Any
similar future legislative changes could negatively impact the value of an investment in our units.
In addition, in January 2017, final
regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the IRC were published in the Federal Register. We do not believe these final regulations affect our ability to be treated as a partnership
for U.S. federal income tax purposes.
If the IRS were to contest the U.S. federal income tax positions we take, the market for our
common units could be adversely impacted, and the cost of any IRS contest would reduce our cash available for distribution to our unitholders. We have not requested a ruling from the IRS with respect to our treatment as a partnership for
U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsels
conclusions or the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Additionally, the
costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
If the IRS makes audit adjustments to our income tax returns for taxable years beginning after December 31, 2017, it (and some states)
may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years
beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and
interest) resulting from such audit adjustment directly from us. Under our limited partnership agreement, our general partner is permitted to make elections under the new rules to either pay the taxes (including any applicable penalties and
interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into
account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or
all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and
interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us. Our
unitholders are required to pay U.S. federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. For example, if we sell assets and use the
proceeds to repay existing debt or fund capital expenditures, our unitholders may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities
to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in cancellation of indebtedness income being allocated to our unitholders as taxable income without any increase in
our cash available for distribution. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected. If our unitholders sell their common
units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of our unitholders allocable share of our net taxable income decrease the
tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to our unitholders if they sell such units at a price greater than their tax basis in those
units, even if the price received is less than the original cost. In addition, because the amount realized includes a unitholders share of our nonrecourse liabilities, if our unitholders sell their common units, they may incur a tax liability
in excess of the amount of cash received from the sale.
A substantial portion of the amount realized from the sale of units, whether or
not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. Thus, our unitholders may recognize both ordinary income and capital loss from the sale of units if the amount realized on a
sale is less than their adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals,
up to $3,000 of ordinary income per year. In the taxable period in which our unitholders sell their units, they may recognize ordinary income from our allocations of income and gain prior to the
sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Tax-exempt
entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them. Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement
accounts, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including individual retirement accounts and other retirement plans, will
be unrelated business taxable income and will be taxable to them. Allocations and distributions to non-U.S. persons are subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S.
person will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Any tax-exempt entity or non- U.S. person, should consult their tax advisor before investing in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS
may challenge this treatment, which could adversely affect the value of the common units. Because we cannot match transferors and transferees of our common units, and for other reasons, we have adopted depreciation and amortization positions
that may not conform to all aspects of the provisions of the IRC of 1986, as amended, or existing and proposed Treasury regulations thereunder. Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to those
positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our
common units or result in audit adjustments to our unitholders tax returns.
We prorate our items of income, gain, loss and
deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the Allocation Date), instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders. We generally allocate certain deductions for depreciation of capital
additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss, or deduction based upon the ownership on the Allocation Date. The U.S.
Department of the Treasury has adopted final Treasury Regulations allowing a similar monthly simplifying convention but, the regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration
method, we could be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
A
unitholder whose common units are the subject of a securities loan (e.g., a loan to a short seller to cover a short sale of units) may be considered to have disposed of those common units. If so, the unitholder would no longer be treated
for tax purposes as a partner with respect to those common units during the period of the loan and could recognize gain or loss from
the disposition. Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of
a securities loan may be considered to have disposed of the loaned common units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller
and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash
distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a
tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
We may adopt certain valuation methodologies in determining a unitholders allocations of income, gain, loss and deduction.
The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units. In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely
determine the fair market value of our assets. Although we may, from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common
units as a means to measure the fair market value of our assets. The IRS may challenge our valuation methods and the resulting allocations of income, gain, loss and deduction. A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the timing and amount of gain from our unitholders sale of common units and could have a negative impact on the value of the common units
or result in audit adjustments to our unitholders tax returns without the benefit of additional deductions.
The sale or exchange
of 50% or more of our capital and profits interests during any twelve-month period will result in the constructive termination of our partnership for U.S. federal income tax purposes. For purposes of determining whether the 50% threshold
has been met, multiple sales of the same interest will be counted only once. On December 31, 2016, Dominion owned 50.9% of our common and subordinated interests and 37.5% of our convertible preferred interests. Therefore, a transfer by Dominion
of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a constructive termination of our partnership for U.S. federal income tax purposes.
Our constructive termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in
us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our
taxable income. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the
unitholders taxable year that includes our termination. Our constructive termination would not affect our classification as a partnership for U.S. federal income tax purposes, but it would
result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were
unable to determine that a termination occurred. The IRS has announced a relief procedure whereby, if a publicly traded partnership that has constructively terminated requests and the IRS grants special relief, among other things, the partnership
may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.
Our unitholders will likely be subject to state and local taxes and return filing requirements in jurisdictions where they do not
live as a result of investing in our common units. In addition to U.S. federal income taxes, unitholders are subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible
taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if unitholders do not live in any of those jurisdictions. Unitholders will likely be required to file foreign, state and
local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business
in multiple states, most of which currently impose a personal income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign
jurisdictions that impose income or similar taxes on nonresident individuals. It is each unitholders responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local
tax consequences of investment in our common units.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
At December 31, 2016, Dominion Midstreams assets consisted primarily of its preferred equity interest in Cove Point, the physical properties owned
by DCG and Questar Pipeline and its noncontrolling partnership interest in Iroquois. These physical properties are described in Item 1. Business, which description is incorporated herein by reference.
Item 3. Legal Proceedings
From
time to time Dominion Midstream may be 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 Dominion Midstream, as applicable, 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 Dominion Midstream may be
involved in various legal proceedings.
See Notes 12 and 18 to the Consolidated Financial Statements and Future Issues and Other
Matters in Item 7. MD&A, which information is incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which Dominion Midstream is a party or by which its interests may be
affected.
Item 4. Mine Safety Disclosures
Not applicable.
Part II
Item 5. Market for
the Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
SECURITIES
On October 15, 2014, Dominion Midstreams common units began trading on the NYSE under the ticker symbol DM. On October 20, 2014,
Dominion Midstream closed the Offering of 20,125,000 common units to the public at a price of $21.00 per common unit, which included a 2,625,000 common unit over-allotment option that was exercised in full by the underwriters.
At January 31, 2017, there were approximately 10 holders of record of our common units. There is no established public trading market for our
subordinated units, all of which are held by Dominion. Cash distributions were paid quarterly in 2016. Quarterly information concerning unit price and distributions is disclosed in Note 24 and Note 5, respectively, to the Consolidated Financial
Statements, which information is incorporated herein by reference.
The following table presents certain information with respect to
Dominion Midstreams purchase of its own common units during the fourth quarter of 2016:
DOMINION MIDSTREAM
PURCHASES OF COMMON UNITS
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Period |
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Total Number of Units Purchased |
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Average Price Paid per Unit |
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Total Number of Units Purchased as part of Publicly Announced Plans or Programs |
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Approximate Dollar Value of Units that May Yet Be Purchased under the Plans or
Programs |
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10/1/2016-10/31/2016 |
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$ |
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11/1/2016-11/30/2016 |
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12/1/2016-12/31/2016(1) |
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6,656,839 |
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25.1 |
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Total |
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6,656,839 |
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$ |
25.1 |
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(1) |
In December 2016, as part of the Questar Pipeline Acquisition, Dominion Midstream repurchased 6,656,839 of its common units from Dominion. |
DISTRIBUTIONS OF AVAILABLE CASH
Our partnership agreement provides that our general partner will make a determination as to whether to make a distribution, but our partnership agreement does
not require us to pay distributions at any time or in any amount. Instead, the Board of Directors of our general partner adopted a cash distribution policy effective as of the Offering which set forth our general partners intention with
respect to the distributions to be made to unitholders. We cannot pay any distributions on any junior securities, including any of the common units, subordinated units or IDRs, prior to paying the quarterly distribution payable to the Series A
Preferred Units, including any previously accrued and unpaid distributions.
Definition of Available Cash
Any distributions we make will be characterized as made from operating surplus or capital surplus. Distributions from operating
surplus are made differently than cash distributions that we would make from capital surplus. Operating surplus distributions will be made to our unitholders and, if we make quarterly distributions above the first target distribution level described
below, to the holder of our IDRs. We do not anticipate that we will make any distributions from capital surplus. In such an event, however, any capital surplus distribution would be made pro rata to all unitholders, but the IDRs would generally not
participate in any capital surplus distributions with respect to those rights. Any distribution from capital surplus would result in a reduction of the minimum quarterly distribution and target distribution levels and, if we reduce the minimum
quarterly distribution to zero and eliminate any unpaid arrearages, thereafter capital surplus would be distributed as if it were operating surplus and the IDRs would thereafter be entitled to participate in such distributions. In determining
operating surplus and capital surplus, we will only
take into account our proportionate share of our consolidated subsidiaries that are not wholly-owned, such as Cove Point.
We define operating surplus as:
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$45.0 million (as described below); plus |
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All of our cash receipts after the closing of the Offering, excluding cash from interim capital transactions (as defined below), provided that cash receipts from the termination of any hedge contract prior to its
stipulated settlement or termination date will be included in equal quarterly installments over the remaining scheduled life of such hedge contract had it not been terminated; plus |
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Cash distributions paid in respect of equity issued (including incremental distributions on IDRs), other than equity issued in the Offering, to finance all or a portion of expansion capital expenditures in respect of
the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date of any acquisition, construction, development or expansion commences
commercial service and the date that it is disposed of or abandoned; plus |
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Cash distributions paid in respect of equity issued (including incremental distributions on IDRs) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued,
to finance the expansion capital expenditures referred to above, in each case, in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to
occur of the date of any acquisition, construction, development or expansion that commences commercial service and the date that it is disposed of or abandoned; less |
|
|
All of our operating expenditures (as defined below) after the closing of the Offering; less
|
|
|
The amount of cash reserves established by our general partner to provide funds for future operating expenditures; less |
|
|
All working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve month period with the proceeds of additional working capital borrowings; less |
|
|
Any cash loss realized on disposition of an investment capital expenditure. |
Disbursements
made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall
be deemed to have been made, received, established, increased or reduced, for purposes of determining operating surplus, within such period if our general partner so determines. Cash received from Cove Point or from our interest in any entity for
which we account using the equity method will not be included to the extent it exceeds our proportionate share of such entitys operating surplus (calculated as if the definition of operating surplus applied to such entity from the date of our
acquisition of such an interest without any basket similar to that described in the first bullet above). Operating surplus does not reflect cash generated by our operations. For example, it includes a basket of $45.0 million that will enable us, if
we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the
effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus
up to the amount of any such cash that we receive from non-operating sources.
The proceeds of working capital borrowings increase
operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month
period following the borrowing, it will be deducted from operating surplus at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating
expenditures because operating surplus will have been previously reduced by the deduction.
We define operating expenditures in our
partnership agreement to generally mean all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under hedge contracts (provided that (1) with respect
to amounts paid in connection with the initial purchase of a hedge contract, such amounts will be amortized over the life of the applicable hedge contract and (2) payments made in connection with the termination of any hedge contract prior to
the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such hedge contract), officer compensation, repayment of working capital
borrowings, interest on indebtedness and capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:
|
|
Repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of
|
|
|
the definition of operating surplus above when such repayment actually occurs; |
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Payments (including prepayments and prepayment penalties and the purchase price of indebtedness that is repurchased and cancelled) of principal of and premium on indebtedness, other than working capital borrowings;
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|
Expansion capital expenditures; |
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|
Investment capital expenditures; |
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|
Payment of transaction expenses relating to interim capital transactions; |
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|
Distributions to our partners (including distributions in respect of our IDRs); |
|
|
Repurchases of equity interests except to fund obligations under employee benefit plans; or |
|
|
Any other expenditures or payments using the proceeds of the Offering. |
Intent to Distribute the Minimum Quarterly
Distribution
Pursuant to our cash distribution policy, within 60 days after the end of each quarter, we intend to distribute to the holders of common
and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.1750 per unit, or $0.70 per unit on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and
expenses, including payments to our general partner and its affiliates. The Board of Directors of our general partner may change the foregoing distribution policy at any time and from time to time, and even if our cash distribution policy is not
modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner. Our partnership agreement does not contain a requirement for us to pay distributions to our
unitholders, and there is no guarantee that we will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, our partnership agreement does contain provisions intended to motivate our general partner to make
steady, increasing and sustainable distributions over time. We cannot pay any distributions on any junior securities, including any of the common units, subordinated units and the IDRs, prior to paying the quarterly distribution payable to holders
of the Series A Preferred Units, including any previously accrued and unpaid distributions. Please see Note 15 and Note 20 to the Consolidated Financial Statements for a discussion of the provisions included in our term loan agreement and
credit facility with Dominion, respectively, that may restrict our ability to make distributions.
General Partner Interest
Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner
owns the IDRs and may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.
Incentive Distribution Rights
IDRs represent the right to receive
increasing percentages (15.0%, 25.0% and 50.0%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the IDRs, but may
transfer these rights separately from its general partner interest.
If for any quarter:
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|
We have distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and |
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|
We have distributed cash from operating surplus to the common unitholders in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution; |
then we will make additional distributions from operating surplus for that quarter among the unitholders and the holders of the IDRs in the following manner:
|
|
First, to all unitholders, pro rata, until each unitholder receives a total of $0.2013 per unit for that quarter (the first target distribution); |
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|
Second, 85.0% to all common unitholders and subordinated unitholders, pro rata, and 15.0% to the holders of our IDRs, until each unitholder receives a total of $0.2188 per unit for that quarter (the second target
distribution); |
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|
Third, 75.0% to all common unitholders and subordinated unitholders, pro rata, and 25.0% to the holders of our IDRs, until each unitholder receives a total of $0.2625 per unit for that quarter (the third target
distribution); and |
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|
Thereafter, 50.0% to all common unitholders and subordinated unitholders, pro rata, and 50.0% to the holders of our IDRs. |
Percentage Allocations of Distributions from Operating Surplus
The
following table illustrates the percentage allocations of distributions from operating surplus between the unitholders and the holders of our IDRs based on the specified target distribution levels. The amounts set forth under the column heading
Marginal Percentage Interest in Distributions are the percentage interests of the holders of our IDRs and the unitholders in any distributions from operating surplus we distribute up to and including the corresponding amount in the
column Total Quarterly Distribution Per Unit. The percentage interests shown for our unitholders and the holders of our IDRs for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than
the minimum quarterly distribution. The percentage interests set forth below assume there are no arrearages on common units.
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|
|
|
|
|
|
|
|
|
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|
|
Marginal Percentage Interest in Distributions |
|
|
|
Total Quarterly Distribution Per Unit |
|
Unitholders |
|
|
IDR Holders |
|
Minimum Quarterly Distribution |
|
$0.1750 |
|
|
100.0% |
|
|
|
% |
|
First Target Distribution |
|
above $0.1750 up to $0.2013 |
|
|
100.0% |
|
|
|
% |
|
Second Target Distribution |
|
above $0.2013 up to $0.2188 |
|
|
85.0% |
|
|
|
15.0% |
|
Third Target Distribution |
|
above $0.2188 up to $0.2625 |
|
|
75.0% |
|
|
|
25.0% |
|
Thereafter |
|
above $0.2625 |
|
|
50.0% |
|
|
|
50.0% |
|
SUBORDINATION PERIOD
GENERAL
Our partnership agreement
provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions from operating surplus each quarter in an amount equal to $0.1750 per common unit, which amount is defined in our
partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions from operating surplus may be made on the
subordinated units, all of which are owned by Dominion. These units are deemed subordinated because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distribution
from operating surplus for any quarter until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters.
Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the
minimum quarterly distribution on the common units.
DETERMINATION OF SUBORDINATION PERIOD
The subordination period began upon the closing date of the Offering and ends when we satisfy one of the three tests set forth in our partnership
agreement as described below.
The first test would be satisfied as of the first business day after the distribution to unitholders in
respect of any quarter, beginning with the quarter ending June 30, 2018, if each of the following has occurred:
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|
For each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the aggregate minimum quarterly distribution on
the outstanding common and subordinated units for each four-quarter period; |
|
|
For the same three consecutive, non-overlapping four quarter periods, the adjusted operating surplus (as described below) equaled or exceeded the aggregate minimum quarterly distribution on the outstanding
common and subordinated units on a fully diluted weighted average basis for each four-quarter period; and |
|
|
There are no arrearages in payment of the minimum quarterly distribution on the common units. |
The second test would be satisfied if each of the following has occurred:
|
|
The Liquefaction Project commences commercial service, meaning Cove Point has obtained all approvals necessary to construct and operate the Liquefaction Project, completed and commissioned the Liquefaction Project and
is able to provide the services it has agreed to provide under the export contracts; |
|
|
For each of the two consecutive, non-overlapping four-quarter periods ending on December 31, 2016, aggregate distributions from operating surplus equaled or exceeded the aggregate minimum quarterly distribution on
the outstanding common and subordinated units for each four-quarter period; |
|
|
For the same two consecutive, non-overlapping four-quarter periods, the adjusted operating surplus (as described below) equaled or exceeded the aggregate minimum quarterly distribution on the outstanding
common and subordinated units on a fully diluted weighted average basis for each four-quarter period; |
|
|
For each completed quarter commencing after December 31, 2016, aggregate distributions from operating surplus equaled or exceeded the aggregate minimum quarterly distribution on the outstanding common and
subordinated units in each such quarter; and |
|
|
There are no arrearages in payment of the minimum quarterly distribution on the common units. |
The third test would be satisfied as of the first business day after the distribution to unitholders in respect of any quarter, beginning with
the quarter ending June 30, 2018, if each of the following has occurred:
|
|
For one four-quarter period immediately preceding that date, aggregate distributions from operating surplus exceeded 150.0% of the aggregate minimum quarterly distribution on the outstanding common units and
subordinated units for such four-quarter period; |
|
|
For the same four-quarter period, the adjusted operating surplus (as described below) equaled or exceeded 150.0% of the aggregate minimum quarterly distribution on the outstanding common and subordinated
units during each quarter on a fully diluted weighted average basis, plus the related distribution on the IDRs; and |
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|
There are no arrearages in payment of the minimum quarterly distributions on the common units. |
For the period after closing of the Offering through December 31, 2014, our partnership agreement prorated the minimum quarterly
distribution based on the actual length of the period, and used such prorated distribution for all purposes, including in determining whether there are any arrearages in payment of the minimum quarterly distribution on the common units.
When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis and will then participate pro
rata with the other common units in distributions, and all common units will thereafter no longer be entitled to arrearages.
Item 6. Selected Financial Data
For the periods prior to the closing of the Offering on October 20, 2014, the following selected financial data were derived from the financial
statements and accounting records of Cove Point as our predecessor. For the periods subsequent to the closing of the Offering, the Consolidated Financial Statements represent the consolidated results of operations, financial position and cash flows
of Dominion Midstream.
The following table should be read in conjunction with the Consolidated Financial Statements included in
Item 8. Financial Statements and Supplementary Data. See also Factors Impacting Comparability of Our Financial Results included in Item 7. MD&A.
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|
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|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014(1) |
|
|
2013 (Predecessor) |
|
|
2012 (Predecessor) |
|
(millions, except per unit amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
441.3 |
|
|
$ |
369.6 |
|
|
$ |
313.3 |
|
|
$ |
343.5 |
|
|
$ |
293.0 |
|
Net income including noncontrolling interest and predecessors |
|
|
229.7 |
|
|
|
196.5 |
|
|
|
106.9 |
|
|
|
109.4 |
|
|
|
97.2 |
|
Net income including noncontrolling interest |
|
|
224.2 |
|
|
|
194.2 |
|
|
|
26.3 |
|
|
|
|
|
|
|
|
|
Net income attributable to partners |
|
|
106.4 |
|
|
|
72.5 |
|
|
|
9.5 |
|
|
|
|
|
|
|
|
|
Net income per limited partner unit (basic and diluted): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units |
|
|
1.30 |
|
|
|
1.08 |
|
|
|
0.15 |
|
|
|
|
|
|
|
|
|
Subordinated units |
|
|
1.17 |
|
|
|
1.00 |
|
|
|
0.15 |
|
|
|
|
|
|
|
|
|
Cash distribution declared per common and subordinated unit |
|
|
0.9680 |
|
|
|
0.7760 |
|
|
|
0.1389 |
|
|
|
|
|
|
|
|
|
Total assets |
|
|
7,186.9 |
|
|
|
4,125.2 |
|
|
|
2,258.4 |
|
|
|
1,498.2 |
|
|
|
1,213.5 |
|
Long-term debt |
|
|
729.9 |
|
|
|
300.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
The selected income statement and cash flow data for the year ended December 31, 2014, consists of the consolidated results of Dominion Midstream for the period from October 20, 2014 through
December 31, 2014, and the results of our Predecessor for the period from January 1, 2014, through October 19, 2014. |
Item 7. Managements Discussion and Analysis of Financial Condition and
Results of Operations
MD&A discusses Dominion Midstreams results of operations and general financial condition. MD&A should be read in conjunction with Item 1.
Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data.
CONTENTS OF
MD&A
MD&A consists of the following information:
|
|
Forward-Looking Statements |
|
|
Initial Public Offering |
|
|
How We Evaluate Our Operations |
|
|
Factors Impacting Comparability of Our Financial Results |
|
|
Analysis of Consolidated Operations |
|
|
Segment Results of Operations |
|
|
Liquidity and Capital Resources |
|
|
Future Issues and Other Matters |
FORWARD-LOOKING
STATEMENTS
This report contains statements concerning expectations, plans, objectives, future financial performance and other
statements that are not historical facts. 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.
We make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially
from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any
forward-looking statement. These factors include but are not limited to:
|
|
Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; |
|
|
Extreme weather events and other natural disasters, including, but not limited to, hurricanes, severe storms, earthquakes and flooding that can cause outages and property damage to facilities; |
|
|
Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations; |
|
|
Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting
requirements and the regulation of additional substances; |
|
|
The cost of environmental compliance, including those costs related to climate change; |
|
|
Changes in implementation and enforcement practices of regulators relating to environmental and safety standards and litigation exposure for remedial activities; |
|
|
Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals; |
|
|
Fluctuations in energy-related commodity prices and the effect these could have on our earnings, liquidity position and the underlying value of our assets;
|
|
|
Counterparty credit and performance risk; |
|
|
Employee workforce factors; |
|
|
Risks of operating businesses in regulated industries that are subject to changing regulatory structures; |
|
|
The ability to negotiate, obtain necessary approvals and consummate acquisitions from Dominion and third parties and the impacts of such acquisitions; |
|
|
Receipt of approvals for, and timing of, closing dates for acquisitions; |
|
|
The timing and execution of our growth strategy; |
|
|
Risks associated with entities in which we share ownership and control with third parties, including risks that result from our lack of sole decision making authority, or reliance on the financial condition of third
parties, disputes that may arise between us and third party participants, difficulties in exiting these arrangements, requirements to contribute additional capital, the timing and amount of which may not be within our control, and rules for
accounting for these entities including those requiring their consolidation or deconsolidation in our financial statements; |
|
|
Political and economic conditions, including inflation and deflation; |
|
|
Domestic terrorism and other threats to our physical and intangible assets, as well as threats to cybersecurity; |
|
|
The timing and receipt of regulatory approvals necessary for planned construction or any future expansion projects, including the overall development of the Liquefaction Project, and compliance with conditions
associated with such regulatory approvals; |
|
|
Changes in demand for our services, including industrial, commercial and residential growth or decline in our service areas, changes in supplies of natural gas delivered to our pipeline 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 and the availability of energy efficient devices; |
|
|
Additional competition in industries in which we operate; |
|
|
Changes to regulated gas transportation and storage rates collected by us; |
|
|
Changes in operating, maintenance and construction costs; |
|
|
Adverse outcomes in litigation matters or regulatory proceedings; |
|
|
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;
|
|
|
The inability to complete planned construction, conversion or expansion projects, including the Liquefaction Project, at all, or within the terms and time frames initially anticipated; |
|
|
Contractual arrangements to be entered into with or performed by our customers substantially in the future, including any revenues anticipated thereunder and any possibility of termination and inability to replace such
contractual arrangements; |
|
|
Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms; |
|
|
Fluctuations in interest rates and increases in our level of indebtedness; |
|
|
Changes in availability and cost of capital; |
|
|
Changes in financial or regulatory accounting principles or policies imposed by governing bodies; and |
|
|
Conflicts of interest with Dominion and its affiliates. |
Additionally, other risks that could
cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.
Forward-looking statements are based
on beliefs and assumptions using information available at the time the statements are made. We caution the reader not to place undue reliance on forward-looking statements because the assumptions, beliefs, expectations and projections about future
events may, and often do, differ materially from actual results. We undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.
PARTNERSHIP OVERVIEW
We
are a growth-oriented Delaware limited partnership formed on March 11, 2014 by Dominion to initially own the Preferred Equity Interest and the general partner interest in Cove Point, which owns LNG import, storage, regasification and
transportation assets. We expect that our relationship with Dominion, which has substantial additional midstream assets, should provide us the opportunity over time to grow a portfolio of natural gas terminaling, processing, storage, transportation
and related assets. The Preferred Equity Interest is a perpetual, non-convertible preferred equity interest entitled to Preferred Return Distributions so long as Cove Point has sufficient cash and undistributed Net Operating Income (determined on a
cumulative basis from the closing of the Offering) from which to make Preferred Return Distributions. Preferred Return Distributions will be made on a quarterly basis and will not be cumulative. Until the Liquefaction Project is completed, Cove
Point is prohibited from making a distribution on its common equity interests until it has a distribution reserve sufficient to pay two quarters of Preferred Return Distributions. The distribution reserve was fully funded in October 2016. The
Preferred Equity Interest is also entitled to receive Additional Return Distributions, and should benefit from the expected increased cash flow and income associated with the Liquefaction Project upon completion. We expect the Preferred Equity
Interest to have limited exposure to the capital expenditure requirements associated with the future expansion of the Cove Point Facilities, as Dominion, although it is under no obligation to do so, has indicated that it intends to provide such
funding. Our results of operations and financial condition will be dependent on the performance of Cove Point, and we believe that the discussion and analysis of Cove Points financial condition and operations is important to our unitholders.
On April 1, 2015, Dominion Midstream acquired from Dominion all issued and outstanding membership interests in DCG. DCG owns and
operates nearly 1,500 miles of FERC-regulated open access, transportation-only interstate natural gas pipeline in South Carolina and southeastern Georgia.
On September 29, 2015, Dominion Midstream acquired a 25.93% noncontrolling partnership interest in Iroquois. Iroquois, a Delaware limited
partnership, owns and operates a 416-mile FERC-regulated interstate natural gas transmission pipeline that extends from the Canada-U.S. border through the states of New York and Connecticut.
On December 1, 2016, Dominion Midstream acquired from Dominion all of the issued and outstanding membership interests of Questar Pipeline.
Questar Pipeline owns and operates nearly
2,200 miles of interstate natural gas pipelines and 18 transmission and storage compressor stations in the western U.S. providing natural gas transportation and underground storage services in
Utah, Wyoming and Colorado.
Business Strategy
Dominion
Midstreams primary business objective is to generate stable and growing cash flows, which will enable it to maintain and increase cash distributions per unit over time. We intend to accomplish this objective by executing the following
strategies:
|
|
Pursue accretive acquisitions from Dominion. We intend to seek opportunities to expand our initial asset base primarily through accretive acquisitions from Dominion. In connection with the Offering, Dominion
granted us a right of first offer with respect to any future sale of its common equity interests in Cove Point, and we may also acquire newly issued common or additional preferred equity interests in Cove Point. Furthermore, Dominion granted us a
right of first offer with respect to any future sale of its indirect ownership interest in Blue Racer, which is a midstream company focused on the Utica Shale formation, and its indirect ownership interest in Atlantic Coast Pipeline, which is a
limited liability company focused on constructing a natural gas pipeline running from West Virginia through Virginia to North Carolina. Dominion is under no obligation to sell these interests, nor are we obligated to purchase such interests. We
believe Dominion will offer us opportunities to acquire other midstream assets that it may acquire or develop in the future or that it currently owns. We believe that Dominions economic relationship with us incentivizes it to offer us
acquisition opportunities, although it is under no obligation to do so nor are we obligated to make any such acquisitions. |
|
|
Pursue third party acquisitions and organic growth opportunities. We also intend to grow our business by pursuing strategic acquisitions from third parties and, as we acquire additional assets, future organic
growth opportunities at those acquired assets. Our third-party growth strategy will include assets both within the existing geographic footprint of Dominions natural gas-related businesses and potentially in new areas. |
|
|
Focus on long-term stable cash flows. We intend to pursue future growth opportunities, whether through our relationship with Dominion, third-party acquisitions or organic growth opportunities, that provide
long-term, stable cash flows. |
|
|
Capitalize on Dominions midstream experience in the Utica and Marcellus Shale formations. We intend to capitalize on Dominions midstream experience in the Utica and Marcellus Shale formations.
Dominions experience in these shale formations, as well as its extensive footprint, could potentially provide significant growth opportunities. |
INITIAL PUBLIC
OFFERING
On October 15, 2014, Dominion Midstreams common units began trading on the NYSE under the ticker symbol
DM. On October 20, 2014, Dominion Midstream closed the Offering of 20,125,000 common units to the public at a price of $21.00 per common unit, which included a 2,625,000 common unit over-allotment option that was exercised in full
by the underwriters.
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
In exchange for Dominions contribution of the general partner interest in Cove Point and
a portion of the Preferred Equity Interest to us, which we contributed to Cove Point Holdings, Dominion received:
|
|
11,847,789 common units and 31,972,789 subordinated units, representing an aggregate 68.5% limited partner interest; |
|
|
A non-economic general partner interest; and |
|
|
A cash distribution of $51.5 million as described in the partnership agreement. |
Dominion
Midstream received net proceeds of $392.4 million from the Offering, after deducting underwriting discounts, structuring fees and offering expenses of $30.2 million. Dominion Midstream utilized $340.9 million of net proceeds to make, through Cove
Point Holdings, a contribution to Cove Point in exchange for the remaining portion of the Preferred Equity Interest.
See Note 20 to the
Consolidated Financial Statements for a discussion of the significant contracts entered into in connection with the closing of the Offering.
BASIS OF
PRESENTATION
The contribution by Dominion to Dominion Midstream of the general partner interest in Cove Point and a portion of the
Preferred Equity Interest is considered to be a reorganization of entities under common control. As a result, Dominion Midstreams basis is equal to Dominions cost basis in the general partner interest in Cove Point and a portion of the
Preferred Equity Interest. As discussed in Note 14 to the Consolidated Financial Statements, Dominion Midstream is the primary beneficiary of, and therefore consolidates, Cove Point. As such, Dominion Midstreams investment in the Preferred
Equity Interest and Cove Points preferred equity interest are eliminated in consolidation. Dominions retained common equity interest in Cove Point is reflected as noncontrolling interest.
For the period prior to the closing of the Offering on October 20, 2014, the financial statements included in this Annual Report on Form 10-K
were derived from the financial statements and accounting records of Cove Point, as our predecessor for accounting purposes. The financial statements were prepared using Dominions historical basis in the assets and liabilities of Cove Point
and include all revenues, costs, assets and liabilities attributed to Cove Point. For the period subsequent to the closing of the Offering, the Consolidated Financial Statements represent the consolidated results of operations, financial position
and cash flows of Dominion Midstream.
The DCG Acquisition is considered to be a reorganization of entities under common control. As a
result, Dominion Midstreams basis in DCG is equal to Dominions cost basis in the assets and liabilities of DCG. On April 1, 2015, DCG became a wholly-owned subsidiary of Dominion Midstream and is therefore consolidated by Dominion
Midstream. The accompanying financial statements and related notes include the historical results and financial position of DCG beginning January 31, 2015, the inception date of common control.
The Questar Pipeline Acquisition is considered to be a reorganization of entities under common control. As a result, Dominion Midstreams
basis in Questar Pipeline is equal to
Dominions cost basis in the assets and liabilities of Questar Pipeline. On December 1, 2016, Questar Pipeline became a wholly-owned subsidiary of Dominion Midstream and is therefore
consolidated by Dominion Midstream. The accompanying financial statements and related notes have been retrospectively adjusted to include the historical results and financial position of Questar Pipeline beginning September 16, 2016, the inception
date of common control.
The financial statements for all years presented include costs for certain general, administrative and corporate
expenses assigned by DRS, DCGS (Dominion Payroll prior to January 1, 2016) or QPC Services Company to Dominion Midstream and Cove Point on the basis of direct and allocated methods in accordance with Dominion Midstreams services agreements
with DRS, DCGS (Dominion Payroll prior to January 1, 2016) and QPC Services Company and Cove Points services agreement with DRS. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the
proportional level of effort devoted by DRS, DCGS (Dominion Payroll prior to January 1, 2016) or QPC Services Company resources that is attributable to the entities, determined by reference to number of employees, salaries and wages and other
similar measures for the relevant DRS, DCGS (Dominion Payroll prior to January 1, 2016) or QPC Services Company service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are
reasonable. Nevertheless, the Consolidated Financial Statements prior to the Offering may not include all of the actual expenses that would have been incurred had we been a stand-alone publicly traded partnership during the periods presented, and
may not reflect our actual results of operations, financial position and cash flows had we been a stand-alone publicly traded partnership during the periods prior to the Offering.
HOW WE EVALUATE OUR OPERATIONS
Dominion Midstream management uses a variety of financial metrics to analyze our performance. These metrics are significant factors in assessing our operating
results and include: (1) EBITDA; (2) Adjusted EBITDA; and (3) distributable cash flow.
EBITDA, Adjusted EBITDA and Distributable Cash Flow
EBITDA represents net income including noncontrolling interest and predecessors before interest and related charges, income tax and depreciation and
amortization. Adjusted EBITDA represents EBITDA after adjustment for the EBITDA attributable to predecessors and a noncontrolling interest in Cove Point held by Dominion subsequent to the Offering, less income from equity method investees, plus
distributions from equity method investees. Subsequent to the Questar Pipeline Acquisition, we define distributable cash flow as Adjusted EBITDA less distributions to preferred unitholders, maintenance capital expenditures and interest expense and
adjusted for known timing differences between cash and income.
EBITDA, Adjusted EBITDA and distributable cash flow are non-GAAP
supplemental financial measures used by our management and by external users of our financial statements, such as investors and securities analysts, to assess:
|
|
The financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
|
|
|
The ability of our assets to generate cash sufficient to pay interest on our indebtedness, if any, and to make distributions; and |
|
|
Our operating performance and ROIC as compared to those of other publicly traded companies that own energy infrastructure assets, without regard to their financing methods and capital structure. |
The GAAP measure most directly comparable to EBITDA and Adjusted EBITDA is net income, and the GAAP measure most directly comparable to
distributable cash flow is net cash provided by operating activities. EBITDA, Adjusted EBITDA and distributable cash flow should not be considered alternatives to net income, operating income, cash flow from operating activities or any other measure
of financial performance or liquidity presented in accordance with GAAP. EBITDA, Adjusted EBITDA and distributable cash flow exclude some, but not all, items that affect net income and operating income, and these measures may vary among other
companies. Therefore, EBITDA, Adjusted EBITDA and distributable cash flow as presented may not be comparable to similarly titled measures of other companies.
FACTORS IMPACTING
COMPARABILITY OF OUR FINANCIAL RESULTS
Our historical results of
operations and cash flows for the periods presented may not be comparable, either from period to period, or going forward, principally for the following reasons:
Questar Pipeline Acquisition
In October 2016, Dominion Midstream,
following approval by the Conflicts Committee of Dominion Midstream GP, LLC, its general partner, entered into the Questar Pipeline Contribution Agreement to acquire Questar Pipeline from Dominion. Upon closing of the agreement in December 2016,
Dominion Midstream became the owner of all of the issued and outstanding membership interests of Questar Pipeline in exchange for consideration consisting of 6,656,839 common units, 11,365,628 Series A Preferred Units and cash of $822.7 million,
$300.0 million of which was treated as a debt-financed distribution, for a total value of $1.29 billion. In addition, Questar Pipelines debt of $435.0 million remained outstanding. In connection with the financing of the Questar Pipeline
Acquisition, Dominion Midstream issued 15,525,000 common units to the public in November 2016. Additionally, in December 2016, Dominion Midstream issued 5,990,634 common units and 18,942,714 Series A Preferred Units through a private placement and
borrowed $300.0 million under a three-year term loan agreement. See Note 4 to the Consolidated Financial Statements for additional information regarding the Questar Pipeline Acquisition.
As a result of the transaction, Dominion Midstream owns 100% of the membership interests in Questar Pipeline and therefore consolidates
Questar Pipeline in its financial statements. Because the contribution of Questar Pipeline by Dominion to Dominion Midstream is considered to be a reorganization of entities under common control, Questar Pipelines assets and liabilities were
recorded in Dominion Midstreams Consolidated Financial Statements at Dominions historical cost. Common control began on September 16, 2016, concurrent with Dominions acquisition of Dominion Questar.
Iroquois Rate Settlement
In October 2016, FERC issued an order approving a settlement reached between the parties in the Section 5 rate case initiated on Iroquois tariff
rates. The settlement resulted in a reduction of Iroquois rates to be phased in from September 2016 through September 2018. As a result, Dominion Midstreams equity method earnings from Iroquois are expected to decrease ratably
during the phase-in period and ultimately by approximately 20% for 2019, excluding the effects of any growth projects. Dominion Midstreams distributions received from Iroquois are expected to remain consistent with historical levels.
Acquisition of Interest in Iroquois
On August 14, 2015,
Dominion Midstream entered into Contribution Agreements with NG and NJNR. On September 29, 2015, pursuant to the Contribution Agreements, Dominion Midstream acquired a 25.93% noncontrolling partnership interest in Iroquois, consisting of
NGs 20.4% and NJNRs 5.53% partnership interests in Iroquois and, in exchange, Dominion Midstream issued common units representing limited partnership interests in Dominion Midstream to both NG (6,783,373 common units) and NJNR (1,838,932
common units). The number of units was based on the volume-weighted average trading price of Dominion Midstreams common units for the five trading days prior to August 14, 2015, or $33.23 per unit. The Iroquois investment, accounted for
under the equity method, was recorded at $216.5 million based on the value of Dominion Midstreams common units at closing, including $0.5 million of external transaction costs.
DCG Acquisition
On April 1, 2015, Dominion Midstream entered into
a Purchase, Sale and Contribution Agreement with Dominion pursuant to which Dominion Midstream acquired from Dominion all of the issued and outstanding membership interests of DCG in exchange for total consideration of $500.8 million, as adjusted
for working capital. The sale of DCG from Dominion to Dominion Midstream is considered to be a reorganization of entities under common control. As a result, Dominion Midstreams basis is equal to Dominions cost basis in the assets and
liabilities of DCG. Subsequent to the transaction, Dominion Midstream owns 100% of the membership interests in DCG and therefore consolidates DCG.
Import
Contracts
Cove Point has historically operated as an LNG import facility, under various long-term import contracts. Since 2010, Dominion has
renegotiated certain existing LNG import contracts in a manner that will result in a significant reduction in pipeline and storage capacity utilization and associated anticipated revenues during the period from 2017 through 2028. Such
amendments created the opportunity for Dominion to explore the Liquefaction Project, which, assuming it becomes operational, will extend the economic life of Cove Point. In total, these renegotiations reduced Cove Points expected annual
revenues from the import-related contracts by approximately $150 million from 2017 through 2028, partially offset by approximately $50 million of additional revenues in the years 2013 through 2017.
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
Liquefaction Project
Following the completion and initial startup phase of the Liquefaction Project, we expect that Cove Point will be able to pay the Preferred Return
Distributions using a small percentage of its total available cash flows, as we expect Cove Points total annual revenues, including reservation charges on the Cove Point Pipeline, to increase substantially notwithstanding the expiration or
termination of any existing contracts with its Import Shippers or Storage Customers.
Income Taxes
Federal and state income taxes are reflected on the historical financial statements of Cove Point. Dominion Midstream, as a pass-through entity, generally is
not subject to income taxes and does not record any provision for income taxes in its Consolidated Financial Statements. Income taxes will not be included in future periods, except to the extent Dominion Midstream acquires interests in business
activities that are conducted in states that impose income taxes on partnerships or if it were to acquire a controlling interest in an entity that is subject to income taxes. However, when Dominion Midstream acquires a controlling interest in a
business from Dominion that had previously been subject to income taxes, the income taxes incurred by the business would be included in Dominion Midstreams Consolidated Financial Statements for any period in which Dominion owned the
controlling interest.
General and Administrative Expenses
Subsequent to the Offering, we have incurred incremental general and administrative expenses as a result of operating as a publicly traded partnership, such
as expenses associated with annual and quarterly reporting; tax return and Schedules K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees;
investor relations expenses; registrar and transfer agent fees; director and officer insurance expenses; and director compensation expenses. Additionally, our financial results reflect our obligation to reimburse our general partner and its
affiliates for all direct and indirect expenses incurred and payments made on our behalf. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform various general, administrative and support services
for us or on our behalf, and corporate overhead costs and expenses allocated to us by Dominion. Our partnership agreement provides that our general partner will determine the costs and expenses that are allocable to us.
ACCOUNTING MATTERS
Critical
Accounting Policies and Estimates
Dominion Midstream has identified the following accounting policies, including certain inherent estimates, that as
a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or
using different assumptions. Dominion Midstream has discussed the development, selection and disclosure of each of these policies with the Audit Committee of its Board of Directors.
ACCOUNTING FOR REGULATED OPERATIONS
Dominion Midstream is required to reflect the effect of FERC rate regulation in its Consolidated Financial Statements. For regulated businesses subject to
FERC cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that FERC will permit the recovery of current
costs through future rates charged to customers, these costs that would otherwise be expensed by nonregulated companies, are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that FERC will require
customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by FERC.
Dominion Midstream evaluates whether or not recovery of its regulatory assets through future rates is probable and makes various assumptions
in its analyses. The expectations of future recovery are generally based on orders issued by FERC or historical experience, as well as discussions with FERC and legal counsel. If recovery of a regulatory asset is determined to be less than probable,
it will be written off in the period such assessment is made. See Note 11 to the Consolidated Financial Statements for additional information.
USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING
At December 31, 2016, Dominion Midstream reported $819.2 million of goodwill on its Balance Sheet.
In April of each year, Dominion Midstream tests its goodwill for potential impairment, and performs additional tests more frequently if an
event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2016, 2015 and 2014 annual tests and any interim tests did not result in the recognition of
any goodwill impairment.
In general, Dominion Midstream estimates the fair value of its reporting units by using a combination of
discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. Fair value estimates are dependent on subjective factors such
as Dominion Midstreams estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point
in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion Midstreams estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion Midstream has
consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash
flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair value would have still been greater than the
carrying value of the reporting unit tested, indicating that no impairment was present.
See Note 10 to the Consolidated Financial Statements for additional information.
USE OF ESTIMATES IN LONG-LIVED ASSET
IMPAIRMENT TESTING
Impairment testing for an individual or group of long-lived assets or for intangible assets with
definite lives is required when circumstances indicate those assets may be impaired. When an assets carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent
that the assets fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected
assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations
about possible variations in their amounts or timing, expectations about operating the long-lived assets and the selection of an appropriate discount rate. When determining whether an asset or asset group has been impaired, management groups assets
at the lowest level that has identifiable cash flows. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary
significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset, including future production and sales levels, expected fluctuations of prices
of commodities sold and consumed and expected proceeds from dispositions.
New Accounting Standards
See Note 3 to the Consolidated Financial Statements for a discussion of new accounting standards.
RESULTS OF OPERATIONS
Presented below are selected amounts related to Dominion Midstreams results of operations:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
$ Change |
|
|
2015 |
|
|
$ Change |
|
|
2014 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
441.3 |
|
|
$ |
71.7 |
|
|
$ |
369.6 |
|
|
$ |
56.3 |
|
|
$ |
313.3 |
|
Purchased gas |
|
|
41.7 |
|
|
|
(12.9 |
) |
|
|
54.6 |
|
|
|
(5.0 |
) |
|
|
59.6 |
|
Net revenue |
|
|
399.6 |
|
|
|
84.6 |
|
|
|
315.0 |
|
|
|
61.3 |
|
|
|
253.7 |
|
Other operations and maintenance |
|
|
95.3 |
|
|
|
38.6 |
|
|
|
56.7 |
|
|
|
21.8 |
|
|
|
34.9 |
|
Depreciation and amortization |
|
|
56.6 |
|
|
|
16.2 |
|
|
|
40.4 |
|
|
|
2.7 |
|
|
|
37.7 |
|
Other taxes |
|
|
30.6 |
|
|
|
4.3 |
|
|
|
26.3 |
|
|
|
3.9 |
|
|
|
22.4 |
|
Earnings from equity method investees |
|
|
23.0 |
|
|
|
16.4 |
|
|
|
6.6 |
|
|
|
6.6 |
|
|
|
|
|
Other income |
|
|
3.2 |
|
|
|
2.2 |
|
|
|
1.0 |
|
|
|
1.0 |
|
|
|
|
|
Interest and related charges |
|
|
7.3 |
|
|
|
6.7 |
|
|
|
0.6 |
|
|
|
0.6 |
|
|
|
|
|
Income tax expense |
|
|
6.3 |
|
|
|
4.2 |
|
|
|
2.1 |
|
|
|
(49.7 |
) |
|
|
51.8 |
|
Net income including noncontrolling interest and
predecessors |
|
$ |
229.7 |
|
|
$ |
33.2 |
|
|
$ |
196.5 |
|
|
$ |
89.6 |
|
|
$ |
106.9 |
|
Less: Predecessor income prior to initial public offering on October 20, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(80.6 |
) |
|
|
80.6 |
|
Less: Net income attributable to DCG Predecessor |
|
|
|
|
|
|
(2.3 |
) |
|
|
2.3 |
|
|
|
2.3 |
|
|
|
|
|
Less: Net income attributable to Questar Pipeline
Predecessor |
|
|
5.5 |
|
|
|
5.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income including noncontrolling interest |
|
|
224.2 |
|
|
|
30.0 |
|
|
|
194.2 |
|
|
|
167.9 |
|
|
|
26.3 |
|
Less: Net income attributable to noncontrolling interest |
|
|
117.8 |
|
|
|
(3.9 |
) |
|
|
121.7 |
|
|
|
104.9 |
|
|
|
16.8 |
|
Net income attributable to partners |
|
$ |
106.4 |
|
|
$ |
33.9 |
|
|
$ |
72.5 |
|
|
$ |
63.0 |
|
|
$ |
9.5 |
|
EBITDA |
|
$ |
299.9 |
|
|
$ |
60.3 |
|
|
$ |
239.6 |
|
|
$ |
43.2 |
|
|
$ |
196.4 |
|
Adjusted
EBITDA(1) |
|
$ |
125.8 |
|
|
$ |
50.2 |
|
|
$ |
75.6 |
|
|
$ |
66.1 |
|
|
$ |
9.5 |
|
Distributable cash flow(1) |
|
$ |
105.9 |
|
|
$ |
34.3 |
|
|
$ |
71.6 |
|
|
$ |
62.0 |
|
|
$ |
9.6 |
|
(1) |
For 2014, represents amounts for the period from October 20, 2014 to December 31, 2014.
|
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
The following table presents a reconciliation of EBITDA and Adjusted EBITDA to the most directly comparable GAAP financial measure for each year.
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|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Adjustments to reconcile net income including noncontrolling interest and predecessors to EBITDA and
Adjusted EBITDA: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income including noncontrolling interest and predecessors: |
|
$ |
229.7 |
|
|
$ |
196.5 |
|
|
$ |
106.9 |
|
Add: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
56.6 |
|
|
|
40.4 |
|
|
|
37.7 |
|
Interest and related charges |
|
|
7.3 |
|
|
|
0.6 |
|
|
|
|
|
Income tax expense |
|
|
6.3 |
|
|
|
2.1 |
|
|
|
51.8 |
|
EBITDA |
|
$ |
299.9 |
|
|
$ |
239.6 |
|
|
$ |
196.4 |
|
Distributions from equity method investees |
|
|
25.1 |
|
|
|
2.6 |
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from equity method investees |
|
|
23.0 |
|
|
|
6.6 |
|
|
|
|
|
EBITDA attributable to Predecessor prior to initial public offering |
|
|
|
|
|
|
|
|
|
|
157.5 |
|
EBITDA attributable to DCG Predecessor |
|
|
|
|
|
|
5.7 |
|
|
|
|
|
EBITDA attributable to Questar Pipeline Predecessor |
|
|
28.0 |
|
|
|
|
|
|
|
|
|
EBITDA attributable to noncontrolling interest |
|
|
148.2 |
|
|
|
154.3 |
|
|
|
29.4 |
|
Adjusted
EBITDA(1) |
|
$ |
125.8 |
|
|
$ |
75.6 |
|
|
$ |
9.5 |
|
(1) |
For 2014, represents amounts for the period from October 20, 2014 to December 31, 2014. |
The
following table presents a reconciliation of distributable cash flow to the most directly comparable GAAP financial measure for each year.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Adjustments to reconcile net cash provided by operating activities to distributable cash
flow: |
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
288.6 |
|
|
$ |
243.5 |
|
|
$ |
156.1 |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
Cash attributable to Predecessor prior to initial public offering |
|
|
|
|
|
|
|
|
|
|
119.5 |
|
Cash attributable to noncontrolling interest(1) |
|
|
150.5 |
|
|
|
154.4 |
|
|
|
31.1 |
|
Cash attributable to DCG Predecessor(2) |
|
|
|
|
|
|
10.4 |
|
|
|
|
|
Cash attributable to Questar Pipeline
Predecessor(3) |
|
|
19.7 |
|
|
|
|
|
|
|
|
|
Other changes in working capital and noncash adjustments |
|
|
7.4 |
|
|
|
(3.1 |
) |
|
|
4.0 |
|
Adjusted EBITDA |
|
|
125.8 |
|
|
|
75.6 |
|
|
|
9.5 |
|
Adjustments to cash(4): |
|
|
|
|
|
|
|
|
|
|
|
|
Less: Distributions to preferred unitholders(5) |
|
|
(3.2 |
) |
|
|
|
|
|
|
|
|
Plus: Deferred revenue(6) |
|
|
5.0 |
|
|
|
8.0 |
|
|
|
|
|
Less: Amortization of regulatory liability(7) |
|
|
(2.8 |
) |
|
|
(2.1 |
) |
|
|
|
|
Less: Maintenance capital expenditures(8) |
|
|
(16.0 |
) |
|
|
(9.4 |
) |
|
|
|
|
Plus: Acquisition costs funded by Dominion |
|
|
1.6 |
|
|
|
0.7 |
|
|
|
|
|
Less: Interest expense and AFUDC equity |
|
|
(4.8 |
) |
|
|
(1.4 |
) |
|
|
|
|
Plus: Non-cash director
compensation |
|
|
0.3 |
|
|
|
0.2 |
|
|
|
0.1 |
|
Distributable cash flow |
|
$ |
105.9 |
|
|
$ |
71.6 |
|
|
$ |
9.6 |
|
(1) |
The Preferred Equity Interest is a perpetual, non-convertible preferred equity interest entitled to the Preferred Return Distributions. Any excess in cash available from Cove
Point over the $50.0 million is attributable to the noncontrolling interest held by Dominion but not available for distribution until the distribution reserve has been fully funded. The $25.0 million distribution reserve was fully funded
in the fourth quarter of 2016. |
(2) |
Represents net cash provided by operating activities of DCG from January 31, 2015, the inception date of common control, through March 31, 2015, the date just prior to Dominion Midstream acquiring DCG.
|
(3) |
Represents net cash provided by operating activities of Questar Pipeline from September 16, 2016, the inception date of common control, through November 30, 2016, the date just prior to Dominion Midstream
acquiring Questar Pipeline. |
(4) |
Beginning in the first quarter of 2016, distributable cash flow no longer reflects an adjustment for the timing difference between cash paid for property taxes and the amount recognized into expense. All prior
periods presented have been recalculated to reflect a consistent approach. Previously, distributable cash flow for the year ended December 31, 2015 was $75.7 million. There was no change to the amount presented as distributable cash flow
for the year ended December 31, 2014. |
(5) |
Represents distributions to which holders of the Series A Preferred Units are entitled. |
(6) |
Adjustment to reflect the difference between cash received and revenue recognized related to facilities payments that are deferred and will be recognized over the related customer contract periods.
|
(7) |
Represents the monetization of a bankruptcy claim being amortized into income through February 2024. |
(8) |
Amounts include accruals. For the years ended December 31, 2016, 2015 and 2014, amounts exclude $23.0 million, $13.7 million and $4.5 million, respectively, of Dominion funded maintenance capital
expenditures related to the Cove Point LNG Facility and Cove Point Pipeline. Dominion has indicated that it intends to continue providing the funding necessary for such expenditures, but it is under no obligation to do so. In addition, the year
ended December 31, 2016 excludes $2.8 million of maintenance capital expenditures incurred by the Questar Pipeline Predecessor and the year ended December 31, 2015 excludes $1.3 million of maintenance capital expenditures
incurred by the DCG Predecessor. |
ANALYSIS OF CONSOLIDATED OPERATIONS
Overview
Net revenue reflects operating revenue less purchased gas
expense. Purchased gas expense includes the value of natural gas retained for use in routine operations and the cost of LNG cooling cargo purchases. Increases or decreases in purchased gas expenses related to LNG cooling cargo are offset by
corresponding increases or decreases in operating revenues and are thus financially neutral to Dominion Midstream. LNG cooling cargo purchases are required for Cove Point to maintain the cryogenic readiness of the Cove Point LNG Facility. Each year,
one or two LNG cooling cargos are procured and billed to the Import Shippers pursuant to certain provisions in Cove Points FERC gas tariff.
An analysis of Dominion Midstreams results of operations follows:
2016 vs. 2015
Net revenue increased 27% primarily due to
the Questar Pipeline Acquisition ($70.6 million), DCG results being included in Dominion Midstream for twelve months in 2016, as compared to eleven months in 2015 ($5.9 million), the Edgemoor Project ($4.2 million), which was placed into
service in December 2015, the St. Charles Transportation Project ($1.9 million), which was placed into service in June 2016, and the Columbia to Eastover Project ($0.5 million), which was placed into service in November 2016. Operating revenue
and purchased gas decreased approximately $26.5 million due to the receipt of one LNG cooling cargo in 2016, as compared to the receipt of two LNG cooling cargoes in 2015. The decrease in purchased gas was partially offset by an increase in gas
costs as a result of the Questar Pipeline Acquisition ($12.2 million).
Other operations and maintenance increased 68% primarily
due to the Questar Pipeline Acquisition ($16.5 million), increases in acquisition-related costs as compared to 2015 ($6.5 million), increases in labor and outside services for Cove Points operations affected by the Liquefaction Project
($6.2 million), organizational design initiative costs incurred during the first quarter of 2016 ($3.3 million) and the impact of DCG results being included in Dominion Midstream for twelve months in 2016, as compared to eleven months in 2015 ($2.4
million).
Depreciation and amortization increased 40% primarily due to the Questar Pipeline Acquisition ($15.6 million), DCG
results being included in Dominion Midstream for twelve months in 2016, as compared to eleven months in 2015 ($0.8 million) and depreciation related to growth projects placed into service ($1.0 million). These increases were partially offset by the
absence of accelerated depreciation from 2015 asset retirements associated with the Liquefaction Project ($1.5 million).
Other taxes
increased 16% primarily due to the Questar Pipeline Acquisition ($2.3 million), increased property taxes related to expansion capital projects ($1.0 million) and the impact of DCG results being included in Dominion Midstream for twelve months in
2016, as compared to eleven months in 2015 ($0.6 million).
Earnings for equity method investees increased $16.4 million
primarily as a result of the September 2015 acquisition of a 25.93% noncontrolling partnership interest in Iroquois.
Other income
increased $2.2 million, primarily related to an increase in AFUDC associated with rate-regulated projects in 2016.
Interest and
related charges increased $6.7 million, primarily due to the Questar Pipeline Acquisition.
Income tax expense increased
$4.2 million as a result of $6.3 million of income taxes attributable to the Questar Pipeline Predecessor, partially offset by the absence of income taxes associated with the DCG Predecessor ($2.1 million).
2015 vs. 2014
Net revenue increased 24% primarily related
to increased transportation and storage revenue as a result of the DCG Acquisition ($61.5 million). Additionally, operating revenue and purchased gas expense decreased approximately $5.0 million primarily due to pricing declines at Cove
Points transportation and storage operations, including pricing declines related to LNG cooling cargo during 2015 ($20.6 million), partially offset by an increase of $21.0 million from the receipt of two LNG cooling cargoes during 2015 as
compared to one LNG cooling cargo during 2014.
Other operations and maintenance increased 62% primarily due to the DCG Acquisition
($22.8 million), an increase in corporate general and administrative costs associated with operating as a stand-alone publicly traded partnership for the entire year ($2.0 million) and certain transition service costs associated with the DCG
Acquisition ($3.0 million). This increase was partially offset by a decrease of $6.5 million in stakeholder outreach expenditures associated with the Liquefaction Project.
Depreciation and amortization increased 7% primarily due to the DCG Acquisition ($7.5 million), partially offset by the absence of
accelerated depreciation recorded in 2014 for 2015 asset retirements associated with the Liquefaction Project ($4.8 million).
Other
taxes increased 17% primarily due to the DCG Acquisition.
Earnings for equity method investee increased
$6.6 million as a result of the acquisition of a 25.93% noncontrolling partnership interest in Iroquois.
Interest and related
charges increased $0.6 million as a result of the issuance of affiliated long-term debt in connection with the DCG Acquisition.
Income tax expense decreased $51.8 million as a result of Dominion Midstreams treatment as a pass-through entity for federal
and state income tax purposes effective October 20, 2014, partially offset by $2.1 million of income taxes attributable to the DCG Predecessor.
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
SEGMENT RESULTS OF OPERATIONS
Presented below is a summary of contributions by Dominion Midstreams operating segments to net income including noncontrolling interest and
predecessors:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
$ Change |
|
|
2015 |
|
|
$ Change |
|
|
2014 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
$ |
238.2 |
|
|
$ |
40.0 |
|
|
$ |
198.2 |
|
|
$ |
91.3 |
|
|
$ |
106.9 |
|
Corporate and Other |
|
|
(8.5 |
) |
|
|
(6.8 |
) |
|
|
(1.7 |
) |
|
|
(1.7 |
) |
|
|
|
|
Consolidated |
|
$ |
229.7 |
|
|
$ |
33.2 |
|
|
$ |
196.5 |
|
|
$ |
89.6 |
|
|
$ |
106.9 |
|
Dominion Energy
Presented below,
on an after-tax basis, are the key factors impacting Dominion Energys contribution to net income including noncontrolling interest and predecessors. Subsequent to October 20, 2014, Dominion
Midstream, as a pass-through entity, is generally not subject to income taxes.
2016 VS. 2015
|
|
|
|
|
|
|
Increase
(Decrease) |
|
|
|
Amount |
|
(millions) |
|
|
|
Questar Pipeline Acquisition |
|
$ |
21.7 |
|
Acquisition of noncontrolling interest in Iroquois |
|
|
14.8 |
|
Growth projects placed into service |
|
|
5.6 |
|
DCG Acquisition |
|
|
2.6 |
|
Absence of income taxes attributable to the DCG Predecessor |
|
|
2.1 |
|
Accelerated depreciation in 2015 |
|
|
1.5 |
|
2016 organizational design initiative costs |
|
|
(3.3 |
) |
Labor and outside service costs associated with the Liquefaction Project |
|
|
(6.2 |
) |
Other |
|
|
1.2 |
|
Change in net income contribution |
|
$ |
40.0 |
|
2015 VS. 2014
|
|
|
|
|
|
|
Increase
(Decrease) |
|
|
|
Amount |
|
(millions) |
|
|
|
Absence of income taxes subsequent to the Offering |
|
$ |
51.8 |
|
DCG Acquisition |
|
|
25.3 |
|
Acquisition of noncontrolling interest in Iroquois |
|
|
6.6 |
|
Stakeholder outreach expenses for the Liquefaction Project |
|
|
6.5 |
|
Other |
|
|
1.1 |
|
Change in net income contribution |
|
$ |
91.3 |
|
Corporate and Other
Presented
below are the Corporate and Other segments after-tax results.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(millions, except earnings per unit amounts) |
|
|
|
|
|
|
|
|
|
Items attributable to operating segment |
|
$ |
(1.6 |
) |
|
$ |
(1.7 |
) |
|
$ |
|
|
Items attributable to corporate segment |
|
|
(6.9 |
) |
|
|
|
|
|
|
|
|
Total net charge |
|
$ |
(8.5 |
) |
|
$ |
(1.7 |
) |
|
$ |
|
|
Corporate and Other includes items attributable to Dominion Midstreams operating segment that are not included in profit
measures evaluated by executive management in assessing segment performance or in allocating resources among the segments. See
Note 23 to the Consolidated Financial Statements for discussion of these items in more detail. Corporate and Other also includes specific items attributable to the Corporate and Other segment. In
2016, this primarily included transition costs of $7.9 million ($6.9 million after-tax) attributable to the Questar Pipeline Predecessor associated with Dominions acquisition of Dominion Questar.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Dominion Midstreams ongoing principal sources of
liquidity may include distributions received from Cove Point from our Preferred Equity Interest, cash generated from operations of DCG and Questar Pipeline, distributions received from our noncontrolling partnership interest in Iroquois, borrowings
under our credit facility with Dominion and issuances of debt and equity securities. We believe that cash from these sources will be sufficient to pay distributions on our common, subordinated and preferred units while continuing to meet our
short-term working capital requirements and our long-term capital expenditure requirements. We expect to have sufficient distributable cash flow to pay the minimum quarterly distribution of $0.1750 per common unit and subordinated unit, which
equates to $17.4 million per quarter, or $69.4 million per year in the aggregate, based on the number of common units and subordinated units currently outstanding. We do not have a legal or contractual obligation to pay distributions
quarterly or on any other basis or at the minimum quarterly distribution rate or at any other rate on our common or subordinated units, and there is no guarantee that we will pay distributions to such unitholders in any quarter.
Additionally, the holders of the Series A Preferred Units are entitled to receive cumulative quarterly distributions of $0.3134 per Series A
Preferred Unit, commencing with the quarter ended December 31, 2016 with a prorated amount from the date of issuance to be paid for such quarter. We cannot pay any distributions on any junior securities, including any of the common units,
subordinated units and the IDRs, prior to paying the quarterly distribution payable to holders of the Series A Preferred Units including any previously accrued and unpaid distributions.
Outstanding Indebtedness
In connection with the Offering, Dominion
Midstream entered into a $300.0 million credit facility with Dominion, allowing it to competitively pursue acquisitions and future organic growth opportunities or to otherwise meet its financial needs. At December 31, 2016 and 2015,
$63.2 million and $5.9 million was outstanding against the credit facility, respectively. During 2016, Dominion Midstream borrowed a net $38.5 million against the credit facility to fund expansion capital expenditures. In December
2016, Dominion Midstream drew $18.8 million on the credit facility associated with the financing of the Questar Pipeline Acquisition. Additionally, in January and February 2017, Dominion Midstream drew $11.4 million on the credit facility to
fund property tax at DCG and expansion capital expenditures and repaid $11.0 million. See Note 20 to the Consolidated Financial Statements for a summary of certain key terms of the credit facility with Dominion.
On April 1, 2015, in connection with the DCG Acquisition, Dominion Midstream issued a two-year, $300.8 million senior unsecured promissory note payable to Dominion, as adjusted for working capital, at an annual interest rate of 0.6%. In December 2016, as a condition to closing of the Questar
Pipeline Acquisition, Dominion Midstream repaid the $300.8 million of outstanding principal on this note, and the associated accrued interest of $0.3 million.
On December 1, 2016, in connection with the Questar Pipeline Acquisition, Dominion Midstream borrowed $300.0 million under a
three-year term loan agreement, with a variable interest rate. Interest on the term loan agreement is payable quarterly, and all principal and accrued interest is due and payable at maturity on December 1, 2019. See Note 15 to the Consolidated
Financial Statements for a summary of certain key terms of the term loan agreement.
In connection with the Questar Pipeline Acquisition,
Dominion Midstream acquired the existing long-term debt at Questar Pipeline, which remains outstanding. At December 31, 2016, this debt consisted of the following instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Type |
|
Principal |
|
|
Rate |
|
|
Maturity |
|
|
|
(millions) |
|
|
|
|
|
|
|
Medium-term notes |
|
$ |
5.0 |
|
|
|
6.48 |
% |
|
|
2018 |
|
Senior notes |
|
|
250.0 |
|
|
|
5.83 |
% |
|
|
2018 |
|
Senior notes |
|
|
180.0 |
|
|
|
4.875 |
% |
|
|
2041 |
|
Total |
|
$ |
435.0 |
|
|
|
|
|
|
|
|
|
Capital Requirements
CAPITAL
SPENDING
Our operations can be capital intensive, requiring investments to expand, upgrade, maintain or enhance existing operations and to meet
environmental and operational regulations. As defined in our partnership agreement, our capital requirements consist of:
|
|
|
Maintenance capital expenditures used to maintain the long-term operating capacity and operating income of our pipelines and facilities. Examples include expenditures to refurbish and replace pipelines, terminals and
storage facilities, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations; and |
|
|
|
Expansion capital expenditures used to increase our operating capacity or operating income over the long term. Examples include the acquisition of equipment, the development of a new facility or the expansion of an
existing facility. |
For the year ended December 31, 2016, Dominion Midstream paid total capital expenditures
of $1.3 billion (of which $3.3 million relates to the Questar Pipeline Predecessor and was funded by Dominion), which included $41.8 million of maintenance capital expenditures.
Our significant capital projects, all of which are expansion projects, are described further below:
|
|
|
Total costs of developing the Liquefaction Project are estimated to be approximately $4.0 billion, excluding financing costs. Through December 31, 2016, Cove Point incurred approximately $3.3 billion of
development and construction costs associated with the Liquefaction
Proj- |
|
ect. We caused Cove Point to use the net proceeds contributed to it from the Offering to fund a portion of development and construction costs associated with the Liquefaction Project. The
Liquefaction Project is expected to be placed into service in late 2017. |
|
|
|
Total costs of the Keys Energy Project are estimated to be approximately $40 million. Through December 31, 2016, we incurred approximately $22 million of costs associated with this project, and service is
expected to commence in March 2017. |
|
|
|
Total costs of the St. Charles Transportation Project were approximately $20 million. The project was placed into service in June 2016. |
|
|
|
In November 2016, Cove Point filed an application to request FERC authorization to construct the approximately $150 million Eastern Market Access Project. Construction on the project is expected to begin in the
fourth quarter of 2017, and the project facilities are expected to be placed into service in late 2018. |
|
|
|
Total costs of the Columbia to Eastover Project were approximately $40 million, of which Dominion Midstream incurred approximately $38 million subsequent to the DCG Acquisition. In June 2016, DCG received FERC
authorization to construct and operate the project facilities, which were placed into service in November 2016. |
|
|
|
Total costs of the Charleston Project are estimated to be approximately $120 million. Through December 31, 2016, approximately $17 million of costs had been incurred, all of which Dominion Midstream
incurred subsequent to the DCG Acquisition. In February 2017, DCG received FERC authorization to construct and operate the project facilities, which are expected to be placed into service in the fourth quarter of 2017. |
|
|
|
In September 2016, DCG entered into a facilities agreement with SCE&G to commit up to $9 million to improve certain measuring and regulation stations over the next seven years in exchange for a 20-year firm
transportation commitment of 12,000 Dth/day. We currently expect to improve three to four stations per year over the next seven years, however, DCG is obligated to fund these station improvements only after they are mutually identified and agreed to
with SCE&G. Total costs of this project were less than $1 million through December 31, 2016. |
Dominion has
indicated that it intends to provide the funding necessary for the remaining construction costs and other capital expenditures of Cove Point, including the Liquefaction Project, Keys Energy Project and Eastern Market Access Project, but it is under
no contractual obligation to do so and has not secured all of the funding necessary to cover these costs, as it intends to finance these costs as they are incurred using its consolidated operating cash flows in addition to proceeds from capital
markets transactions. However, Dominion has entered into guarantee arrangements on behalf of Cove Point to facilitate the Liquefaction Project, including guarantees supporting the terminal services and transportation agreements as well as the
engineering, procurement and construction contract for the Liquefaction Project. Two of the guarantees have no stated limit, one guarantee
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
has a $150 million limit and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million. In the event that Dominion does not satisfy its
obligations under these guarantee arrangements or otherwise does not agree to provide the funding necessary for the remaining development costs and other capital expenditures of Cove Point, or is unable to obtain such funding in the amounts required
or on terms acceptable to Dominion, Cove Point would require substantial external debt or equity financing to complete the construction of the Liquefaction Project, Keys Energy Project and Eastern Market Access Project.
Distributions
Distributions are declared
subsequent to quarter end. The table below summarizes the quarterly distributions on common and subordinated units.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly Period Ended |
|
Total Quarterly Distribution (per unit) |
|
|
Total Cash Distribution
(in millions) |
|
|
Date of Declaration |
|
|
Date of Record |
|
|
Date of Distribution |
|
December 31, 2014 |
|
$ |
0.1389 |
(1) |
|
$ |
8.9 |
|
|
|
January 23, 2015 |
|
|
|
February 3, 2015 |
|
|
|
February 13, 2015 |
|
March 31, 2015 |
|
|
0.1750 |
|
|
|
12.1 |
|
|
|
April 22, 2015 |
|
|
|
May 5, 2015 |
|
|
|
May 15, 2015 |
|
June 30, 2015 |
|
|
0.1875 |
|
|
|
12.9 |
|
|
|
July 17, 2015 |
|
|
|
August 4, 2015 |
|
|
|
August 14, 2015 |
|
September 30, 2015 |
|
|
0.2000 |
|
|
|
15.5 |
|
|
|
October 23, 2015 |
|
|
|
November 3, 2015 |
|
|
|
November 13, 2015 |
|
December 31, 2015 |
|
|
0.2135 |
|
|
|
16.8 |
|
|
|
January 21, 2016 |
|
|
|
February 5, 2016 |
|
|
|
February 15, 2016 |
|
March 31, 2016 |
|
|
0.2245 |
|
|
|
17.8 |
|
|
|
April 19, 2016 |
|
|
|
May 3, 2016 |
|
|
|
May 13, 2016 |
|
June, 30, 2016 |
|
|
0.2355 |
|
|
|
19.0 |
|
|
|
July 22, 2016 |
|
|
|
August 5, 2016 |
|
|
|
August 15, 2016 |
|
September 30, 2016 |
|
|
0.2475 |
|
|
|
24.3 |
|
|
|
October 21, 2016 |
|
|
|
November 4, 2016 |
|
|
|
November 15, 2016 |
|
December 31, 2016 |
|
|
0.2605 |
|
|
|
27.5 |
|
|
|
January 25, 2017 |
|
|
|
February 6, 2017 |
|
|
|
February 15, 2017 |
|
(1) |
For the period subsequent to the Offering through December 31, 2014, the initial quarterly cash distribution was calculated as the minimum quarterly distribution of $0.1750 per unit prorated for the portion of
the quarter subsequent to the Offering. |
Record holders of the Series A Preferred Units are entitled to receive cumulative quarterly
distributions, payable in cash, payable in kind or a combination thereof at the option of our general partner, equal to $0.3134 in respect of each quarter ending before December 1, 2018. The table below summarizes the quarterly distributions on
the Series A Preferred Units.
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly Period Ended |
|
Total Distribution
(in millions) |
|
|
Amount Payable
in Cash (in millions) |
|
|
Amount Payable in Kind (in millions) |
|
December 31, 2016 |
|
$ |
3.2 |
(1) |
|
$ |
3.2 |
|
|
$ |
|
|
(1) |
For the period subsequent to the issuance of the Series A Preferred Units through December 31, 2016, the initial quarterly cash distribution was calculated as the minimum quarterly distribution of $0.3134 per
unit prorated for the portion of the quarter subsequent to the issuance of the Series A Preferred Units.
|
Cash Flows
A summary of cash flows is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
$ |
35.0 |
|
|
$ |
175.4 |
|
|
$ |
11.2 |
|
Cash flows provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
|
288.6 |
|
|
|
243.5 |
|
|
|
156.1 |
|
Investing activities |
|
|
(2,122.8 |
) |
|
|
(1,282.7 |
) |
|
|
(571.6 |
) |
Financing activities |
|
|
1,838.8 |
|
|
|
898.8 |
|
|
|
579.7 |
|
Net increase (decrease) in cash and cash equivalents |
|
|
4.6 |
|
|
|
(140.4 |
) |
|
|
164.2 |
|
Cash and cash equivalents at end of year |
|
$ |
39.6 |
|
|
$ |
35.0 |
|
|
$ |
175.4 |
|
OPERATING CASH FLOWS
In 2016, net cash provided by Dominion Midstreams operating activities increased by $45.1 million primarily due to the Questar Pipeline Acquisition
and the September 2015 acquisition of a 25.93% noncontrolling partnership interest in Iroquois.
INVESTING CASH
FLOWS
In 2016, net cash used in Dominion Midstreams investing activities increased by $840.1 million, primarily due to the
Questar Pipeline Acquisition.
FINANCING CASH FLOWS
In 2016, net cash provided by Dominion Midstreams financing activities increased by $940.0 million, primarily due to the issuances of common and
preferred units in connection with the Questar Pipeline Acquisition.
In May 2016, Dominion Midstream filed an SEC shelf registration for
the ability to sell common units through an at-the-market program and pursuant to which it may offer from time to time up to $150.0 million aggregate amount of its common units. Sales of common units, if any, will be made by means of ordinary
brokers transactions on the NYSE, in block transactions, or as otherwise agreed to between the sales agent and us. In July 2016, Dominion Midstream entered into an equity distribution agreement with nine separate managers to effect sales under
the program; however, we have not issued any units in 2016.
CUSTOMER CONCENTRATION
Dominion Midstream provides service to approximately 130 customers, including the Storage Customers, marketers or end users, power generators, utilities and
the Import Shippers. The two largest customers comprised approximately 57% of the total transportation and storage revenues for the year ended December 31, 2016. See Note 19 to the Consolidated Financial Statements for additional information.
CONTRACTUAL OBLIGATIONS
Dominion Midstream is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include debt
agreements, contracts for capital projects and the purchase of goods and services. Presented below is a table summarizing cash payments that may result from contracts of which Dominion Midstream or its subsidiaries is party as of
December 31, 2016. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based
prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in the Consolidated Balance Sheets. The
majority of Dominion Midstreams current liabilities will be paid in cash in 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
|
2018- 2019 |
|
|
2020- 2021 |
|
|
2022 and thereafter |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
$ |
|
|
|
$ |
555.0 |
|
|
$ |
|
|
|
$ |
180.0 |
|
|
$ |
735.0 |
|
Interest payments |
|
|
31.3 |
|
|
|
38.9 |
|
|
|
17.6 |
|
|
|
175.4 |
|
|
|
263.2 |
|
Purchase obligations(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital projects |
|
|
243.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
243.0 |
|
Transportation service-demand |
|
|
0.2 |
|
|
|
0.4 |
|
|
|
0.4 |
|
|
|
1.2 |
|
|
|
2.2 |
|
Other(2) |
|
|
|
|
|
|
1.0 |
|
|
|
|
|
|
|
3.0 |
|
|
|
4.0 |
|
Other long-term liabilities(3): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CPCN obligation(4) |
|
|
|
|
|
|
16.8 |
|
|
|
0.8 |
|
|
|
6.4 |
|
|
|
24.0 |
|
Total cash payments |
|
$ |
274.5 |
|
|
$ |
612.1 |
|
|
$ |
18.8 |
|
|
$ |
366.0 |
|
|
$ |
1,271.4 |
|
(1) |
Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined. |
(2) |
Represents operations and maintenance commitments. |
(3) |
Excludes regulatory liabilities and employee benefit plan obligations, which are not contractually fixed as to timing and amount. See Notes 11 and 16 to the Consolidated Financial Statements. Deferred revenue is also
excluded as it is not expected to require future cash payments by Dominion Midstream. |
(4) |
Relates to payments required by the CPCN granted by the Maryland Commission. Payments approximating $8 million are accrued as a current liability and are therefore excluded from this table. See Note 17 to the
Consolidated Financial Statements for further information. |
Off-Balance Sheet Arrangements
Other than the holding of surety bonds as discussed in Note 18 to the Consolidated Financial Statements, Dominion Midstream had no off-balance sheet arrangements at December 31, 2016.
FUTURE ISSUES
AND OTHER MATTERS
See Item 1. Business and Notes 11 and 12 to the Consolidated Financial Statements
for additional information on various environmental, regulatory, legal and other matters that may impact future results of operations, financial condition and/or cash flows.
Environmental Matters
Dominion Midstream 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.
ENVIRONMENTAL PROTECTION AND MONITORING
EXPENDITURES
Expenses (including depreciation) related to environmental protection and monitoring activities were $2.1 million,
$1.7 million and $1.2 million during 2016, 2015, and 2014, respectively. These expenses are expected to approximate $2.3 million and $2.4 million in 2017 and 2018, respectively. In addition, capital expenditures related to
environmental controls were $5.2 million, $0.2 million, and $3.7 million for 2016, 2015 and 2014, respectively. These expenditures are expected to approximate $3.7 million and $2.3 million in 2017 and 2018, respectively.
FUTURE ENVIRONMENTAL REGULATIONS
Air
The CAA, as amended, is a comprehensive program
utilizing a broad range of regulatory tools to protect and preserve the nations air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop
regulatory programs that are more restrictive. Dominion Midstreams facilities are subject to the CAAs permitting and other requirements.
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 meet state-by-state emission rate or intensity-based CO2 binding
goals or limits. States are required to submit plans to the EPA identifying how they will comply with the rule by September 2018. The final rule has been challenged in the U.S. Court of Appeals for the D.C. Circuit. In February 2016, the
U.S. Supreme Court issued a stay of the Clean Power Plan until the disposition of the petitions challenging the rule now before the Court of Appeals, and, if such petitions are filed in the future, before the U.S. Supreme Court. Dominion Midstream
cannot predict the impact of this rule on its financial performance at this time.
In September 2015, the EPA issued a proposed NSPS (for
the oil and gas sector) to regulate methane and VOC emissions from new and modified facilities in transportation and storage, gathering and boosting, production and processing facilities. The proposed regulation was finalized in June 2016. All
projects which commence construction after September 2015 will be required to comply with the final regulation. The costs are not expected to be material for Dominion Midstreams current projects.
In October 2015, the EPA issued a final rule tightening the ozone standard from 75 ppb to 70 ppb. The EPA is expected to complete attainment
designations for a new standard by December 2017 and states will have until 2020 or 2021 to develop plans to address the new standard. In September 2016, the Virginia Department of Environmental Quality required that a reasonable available control
technology analysis be conducted for Cove Points compressor stations in Loudoun County. The reasonable available control technology analysis was submitted in October 2016. Until the states have developed implementation plans, Dominion
Midstream is unable to predict whether or to what extent the new rules will ultimately require additional controls.
Managements Discussion and Analysis of Financial Condition and Results of Operations, Continued
In September 2016, the Maryland Department of the Environment notified Dominion Midstream that
certain combustion air emission sources at the Cove Point LNG terminal are subject to the non-electric generating unit provisions of the NOx SIP Call for Maryland. Maryland is preparing a state rule change to
extend the NOx SIP Call to Cove Point. Implementation will involve state allocations for NOx emissions and a change to monitoring and reporting of NOx emissions from Cove Point. The costs are not expected to be material to Dominion Midstream.
Climate Change
In March 2016, as part of its Climate
Action Plan, the EPA began development of regulations for reducing methane emissions from existing sources in the oil and natural gas sectors. In November 2016, the EPA issued an Information Collection Request to collect information on existing
sources upstream of local distribution companies in this sector. Depending on the results of this Information Collection Request effort, the EPA may propose new regulations on existing sources. Dominion Midstream cannot currently estimate the
potential impacts on results of operations, financial condition or cash flows related to this matter.
PHMSA Regulation
The most recent reauthorization of PHMSA included new provisions on historical records research, maximum-allowed operating pressure validation, use of
automated or remote-controlled valves on new or replaced lines, increased civil penalties and evaluation of expanding integrity management beyond high-consequence areas. PHMSA has not yet issued new rulemaking on most of these items.
Legal Matters
In January 2015, DCG, while it was a subsidiary of
SCANA, self-reported potentially non-compliant natural gas pipeline exposure maintenance activities to the U.S. Army Corps of Engineers. During pipeline maintenance activities, it was discovered that prior authorization had not been obtained from
the U.S. Army Corps of Engineers for seventeen locations that involved the additions of fill, culverts and concrete mats. In June 2015, DCG submitted a draft CRA to the U.S. Army Corps of Engineers with proposed plans for rehabilitation and
minimization of potential adverse impacts to water bodies and proposed to apply for after-the-fact permits. In June 2016, the U.S. Army Corps of Engineers provided the approved CRA to Dominion Midstream, which was executed in July 2016. Dominion
Midstream expects SCANA will provide funding for all material costs, if any, to satisfy the requirements imposed by the United States Army Corps of Engineers as required by the CRA. DCG is implementing the CRA.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide information about our potential exposure to market risk. The term market risk
refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The readers attention is directed to Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact Dominion Midstream.
Commodity Price Risk
We will be entitled to the Preferred
Return Distributions so long as Cove Point has sufficient cash and undistributed Net Operating Income from which to make the Preferred Return Distributions. The cash flow attributable to the Preferred Equity Interest and from the operations of DCG
and Questar Pipeline is underpinned by long-term fixed reservation fee agreements. Accordingly, we believe we are not subject to any material impacts of commodity price risk.
Interest Rate Risk
Upon the closing of the Offering, we entered
into a $300.0 million variable rate credit facility with Dominion. At December 31, 2016 and 2015, we had $63.2 million and $5.9 million outstanding indebtedness against the credit facility, respectively. In connection with the Questar Pipeline
Acquisition, we borrowed $300.0 million under a three-year variable rate term loan agreement. We may hedge the interest portions of our borrowings from time-to-time in order to manage risks associated with floating interest rates. A hypothetical 10%
increase in market interest rates would not have resulted in a material change in earnings at December 31, 2016 or 2015.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Dominion Midstream GP, LLC and Members of
Dominion Midstream Partners, LP
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Dominion Midstream Partners, LP and its subsidiaries (Dominion Midstream) as of
December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, equity and partners capital, and cash flows for each of the three years in the period ended December 31, 2016. These financial
statements are the responsibility of Dominion Midstreams management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial
position of Dominion Midstream Partners, LP and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with
accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), Dominion Midstreams internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal ControlIntegrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2017 expressed an unqualified opinion on Dominion Midstreams internal control over financial reporting.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 28, 2017
Dominion Midstream Partners, LP
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(in millions, except per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenue(1) |
|
$ |
441.3 |
|
|
$ |
369.6 |
|
|
$ |
313.3 |
|
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Purchased gas(1) |
|
|
41.7 |
|
|
|
54.6 |
|
|
|
59.6 |
|
Other operations and maintenance: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliated suppliers |
|
|
34.8 |
|
|
|
22.1 |
|
|
|
9.4 |
|
Other |
|
|
60.5 |
|
|
|
34.6 |
|
|
|
25.5 |
|
Depreciation and amortization |
|
|
56.6 |
|
|
|
40.4 |
|
|
|
37.7 |
|
Other taxes |
|
|
30.6 |
|
|
|
26.3 |
|
|
|
22.4 |
|
Total operating expenses |
|
|
224.2 |
|
|
|
178.0 |
|
|
|
154.6 |
|
Income from operations |
|
|
217.1 |
|
|
|
191.6 |
|
|
|
158.7 |
|
Earnings from equity method investees |
|
|
23.0 |
|
|
|
6.6 |
|
|
|
|
|
Other income |
|
|
3.2 |
|
|
|
1.0 |
|
|
|
|
|
Interest and related charges(1) |
|
|
7.3 |
|
|
|
0.6 |
|
|
|
|
|
Income from operations including noncontrolling interest before income taxes |
|
|
236.0 |
|
|
|
198.6 |
|
|
|
158.7 |
|
Income tax expense |
|
|
6.3 |
|
|
|
2.1 |
|
|
|
51.8 |
|
Net income including noncontrolling interest and
predecessors |
|
$ |
229.7 |
|
|
$ |
196.5 |
|
|
$ |
106.9 |
|
Less: Predecessor income prior to initial public offering on October 20, 2014 |
|
|
|
|
|
|
|
|
|
|
80.6 |
|
Less: Net income attributable to DCG Predecessor |
|
|
|
|
|
|
2.3 |
|
|
|
|
|
Less: Net income attributable to Questar Pipeline
Predecessor |
|
|
5.5 |
|
|
|
|
|
|
|
|
|
Net income including noncontrolling interest |
|
|
224.2 |
|
|
|
194.2 |
|
|
|
26.3 |
|
Less: Net income attributable to noncontrolling interest |
|
|
117.8 |
|
|
|
121.7 |
|
|
|
16.8 |
|
Net income attributable to partners |
|
$ |
106.4 |
|
|
$ |
72.5 |
|
|
$ |
9.5 |
|
|
|
|
|
Net income attributable to partners ownership
interest(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Preferred unitholders interest in net income |
|
$ |
3.2 |
|
|
$ |
|
|
|
$ |
|
|
General partners interest in net income |
|
|
2.3 |
|
|
|
(0.5 |
) |
|
|
|
|
Common unitholders interest in net income |
|
|
63.9 |
|
|
|
41.3 |
|
|
|
4.8 |
|
Subordinated unitholders interest in net income |
|
|
37.0 |
|
|
|
31.7 |
|
|
|
4.7 |
|
Net income per limited partner unit (basic and diluted) |
|
|
|
|
|
|
|
|
|
|
|
|
Common units |
|
$ |
1.30 |
|
|
$ |
1.08 |
|
|
$ |
0.15 |
|
Subordinated units |
|
$ |
1.17 |
|
|
$ |
1.00 |
|
|
$ |
0.15 |
|
(1) |
See Note 20 for amounts attributable to related parties. |
(2) |
Allocation of net income attributable to partners ownership interest for 2014 has been adjusted for rounding. |
The accompanying notes are an integral part of Dominion Midstreams Consolidated Financial Statements.
Dominion Midstream Partners, LP
Consolidated Statements of Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Net income including noncontrolling interest and predecessors |
|
$ |
229.7 |
|
|
$ |
196.5 |
|
|
$ |
106.9 |
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Changes in other comprehensive loss from equity method
investees |
|
|
(0.4 |
) |
|
|
|
|
|
|
|
|
Other comprehensive loss |
|
|
(0.4 |
) |
|
|
|
|
|
|
|
|
Comprehensive income including noncontrolling interest and predecessors |
|
|
229.3 |
|
|
|
196.5 |
|
|
|
106.9 |
|
Comprehensive income attributable to Predecessor income prior to initial public offering on
October 20, 2014 |
|
|
|
|
|
|
|
|
|
|
80.6 |
|
Comprehensive income attributable to DCG Predecessor |
|
|
|
|
|
|
2.3 |
|
|
|
|
|
Comprehensive income attributable to Questar Pipeline Predecessor |
|
|
5.5 |
|
|
|
|
|
|
|
|
|
Comprehensive income attributable to noncontrolling
interests |
|
|
117.8 |
|
|
|
121.7 |
|
|
|
16.8 |
|
Comprehensive income attributable to partners |
|
$ |
106.0 |
|
|
$ |
72.5 |
|
|
$ |
9.5 |
|
Dominion Midstream Partners, LP
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
At December 31, |
|
2016 |
|
|
2015 |
|
(millions) |
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
39.6 |
|
|
$ |
35.0 |
|
Restricted cash |
|
|
25.0 |
|
|
|
|
|
Customer and other receivables |
|
|
45.9 |
|
|
|
27.0 |
|
Affiliated receivables |
|
|
18.3 |
|
|
|
6.2 |
|
Prepayments |
|
|
8.7 |
|
|
|
10.6 |
|
Inventories: |
|
|
|
|
|
|
|
|
Materials and supplies |
|
|
19.1 |
|
|
|
12.5 |
|
Gas stored |
|
|
1.0 |
|
|
|
|
|
Regulatory assets |
|
|
5.1 |
|
|
|
1.7 |
|
Other(1) |
|
|
8.2 |
|
|
|
2.8 |
|
Total current assets |
|
|
170.9 |
|
|
|
95.8 |
|
Investment in Equity Method Affiliates |
|
|
257.8 |
|
|
|
220.5 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
6,911.4 |
|
|
|
3,845.7 |
|
Accumulated depreciation and amortization |
|
|
(1,032.0 |
) |
|
|
(351.0 |
) |
Total property, plant and equipment, net |
|
|
5,879.4 |
|
|
|
3,494.7 |
|
Deferred Charges and Other Assets |
|
|
|
|
|
|
|
|
Goodwill |
|
|
819.2 |
|
|
|
295.5 |
|
Intangible assets, net |
|
|
17.6 |
|
|
|
15.8 |
|
Regulatory assets |
|
|
40.2 |
|
|
|
2.5 |
|
Other |
|
|
1.8 |
|
|
|
0.4 |
|
Total deferred charges and other assets |
|
|
878.8 |
|
|
|
314.2 |
|
Total assets |
|
$ |
7,186.9 |
|
|
$ |
4,125.2 |
|
(1) |
See Note 20 for amounts attributable to related parties. |
|
|
|
|
|
|
|
|
|
At December 31, |
|
2016 |
|
|
2015 |
|
(millions) |
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
21.5 |
|
|
$ |
8.6 |
|
Payables to affiliates |
|
|
9.9 |
|
|
|
5.2 |
|
Accrued interest, payroll and taxes |
|
|
12.7 |
|
|
|
6.0 |
|
Regulatory liabilities |
|
|
7.5 |
|
|
|
6.7 |
|
Dominion credit facility borrowings |
|
|
63.2 |
|
|
|
5.9 |
|
Deferred revenue |
|
|
4.3 |
|
|
|
4.2 |
|
Natural gas imbalances(1) |
|
|
1.4 |
|
|
|
1.0 |
|
CPCN obligation |
|
|
8.0 |
|
|
|
8.0 |
|
Other |
|
|
20.7 |
|
|
|
14.4 |
|
Total current liabilities |
|
|
149.2 |
|
|
|
60.0 |
|
Long-Term Debt |
|
|
729.9 |
|
|
|
|
|
Affiliated Long-Term Debt |
|
|
|
|
|
|
300.8 |
|
Deferred Credits and Other Liabilities |
|
|
|
|
|
|
|
|
Pension and other postretirement benefit
liabilities(1) |
|
|
6.2 |
|
|
|
5.0 |
|
Regulatory liabilities |
|
|
129.1 |
|
|
|
66.7 |
|
CPCN obligation |
|
|
21.4 |
|
|
|
29.0 |
|
Asset retirement obligation |
|
|
29.3 |
|
|
|
13.0 |
|
Deferred revenue |
|
|
14.0 |
|
|
|
9.1 |
|
Other |
|
|
7.9 |
|
|
|
0.6 |
|
Total deferred credits and other liabilities |
|
|
207.9 |
|
|
|
123.4 |
|
Total liabilities |
|
|
1,087.0 |
|
|
|
484.2 |
|
Commitments and Contingencies (see Note 18) |
|
|
|
|
|
|
|
|
Equity and Partners Capital |
|
|
|
|
|
|
|
|
Preferred unitholderspublic (18,942,714 units issued and outstanding at December 31, 2016; no such
units issued or outstanding at December 31, 2015) |
|
|
492.1 |
|
|
|
|
|
Preferred unitholderDominion (11,365,628 units issued and outstanding at December 31, 2016; no
such units issued or outstanding at December 31, 2015) |
|
|
301.2 |
|
|
|
|
|
Common unitholderspublic (48,734,195 and 27,867,938 units issued and outstanding at December 31,
2016 and 2015, respectively) |
|
|
1,082.1 |
|
|
|
600.8 |
|
Common unitholderDominion (18,504,628 and 17,846,672 units issued and outstanding at December 31,
2016 and 2015, respectively) |
|
|
457.4 |
|
|
|
438.8 |
|
Subordinated unitholderDominion (31,972,789 units issued and outstanding at December 31, 2016 and
2015) |
|
|
483.0 |
|
|
|
475.4 |
|
General Partner interestDominion (non-economic
interest) |
|
|
(29.2 |
) |
|
|
(12.4 |
) |
Accumulated other comprehensive loss |
|
|
(0.4 |
) |
|
|
|
|
Total Dominion Midstream Partners, LP partners capital |
|
|
2,786.2 |
|
|
|
1,502.6 |
|
Noncontrolling interest |
|
|
3,313.7 |
|
|
|
2,138.4 |
|
Total equity and partners capital |
|
|
6,099.9 |
|
|
|
3,641.0 |
|
Total liabilities and equity and partners capital |
|
$ |
7,186.9 |
|
|
$ |
4,125.2 |
|
(1) |
See Note 20 for amounts attributable to related parties. |
The accompanying notes are an integral
part of Dominion Midstreams Consolidated Financial Statements.
Dominion Midstream Partners, LP
Consolidated Statements of Equity and Partners Capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partnership
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Members Equity |
|
|
DCG Predecessor Equity |
|
|
Questar Pipeline Predecessor Equity |
|
|
Preferred Unitholders Public |
|
|
Preferred Unitholder Dominion |
|
|
Common Unitholders Public |
|
|
Common Unitholder Dominion |
|
|
Subordinated Unitholder Dominion |
|
|
General Partner Dominion (non-
economic interest) |
|
|
AOCI |
|
|
Total Dominion Midstream Partners, LP Partners Equity and Capital |
|
|
Noncontrolling interest |
|
|
Total Equity and Partners Capital |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
|
$ |
1,272.0 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,272.0 |
|
|
$ |
|
|
|
$ |
1,272.0 |
|
Net income (prior to initial public offering) |
|
|
80.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
80.6 |
|
|
|
|
|
|
|
80.6 |
|
Equity contribution from Dominion (prior to initial public offering) |
|
|
259.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
259.9 |
|
|
|
|
|
|
|
259.9 |
|
Formation and Offering Transactions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution of interest from Dominion |
|
|
(655.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
204.2 |
|
|
|
451.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of predecessor members equity to noncontrolling interest |
|
|
(957.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(957.2 |
) |
|
|
957.2 |
|
|
|
|
|
Settlement of net current and deferred income tax liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18.7 |
|
|
|
41.4 |
|
|
|
|
|
|
|
|
|
|
|
60.1 |
|
|
|
87.8 |
|
|
|
147.9 |
|
Additional basis in property, plant and equipment received from Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.9 |
|
|
|
6.6 |
|
|
|
|
|
|
|
|
|
|
|
9.5 |
|
|
|
13.7 |
|
|
|
23.2 |
|
Issuance of common units, net of offering costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
392.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
392.4 |
|
|
|
|
|
|
|
392.4 |
|
Distribution to Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13.9 |
) |
|
|
(37.6 |
) |
|
|
|
|
|
|
|
|
|
|
(51.5 |
) |
|
|
|
|
|
|
(51.5 |
) |
Net income from October 20, 2014 to December 31, 2014(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.0 |
|
|
|
1.8 |
|
|
|
4.7 |
|
|
|
|
|
|
|
|
|
|
|
9.5 |
|
|
|
16.8 |
|
|
|
26.3 |
|
December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
395.4 |
|
|
|
213.7 |
|
|
|
466.2 |
|
|
|
|
|
|
|
|
|
|
|
1,075.3 |
|
|
|
1,075.5 |
|
|
|
2,150.8 |
|
Net income including noncontrolling interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24.0 |
|
|
|
17.3 |
|
|
|
31.7 |
|
|
|
(0.5 |
) |
|
|
|
|
|
|
72.5 |
|
|
|
121.7 |
|
|
|
194.2 |
|
DCG Acquisition: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Record Dominions net investment in DCG |
|
|
|
|
|
|
497.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
497.0 |
|
|
|
|
|
|
|
497.0 |
|
Net income attributable to DCG Predecessor |
|
|
|
|
|
|
2.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.3 |
|
|
|
|
|
|
|
2.3 |
|
Contribution from Dominion to DCG prior to DCG Acquisition |
|
|
|
|
|
|
2.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.3 |
|
|
|
|
|
|
|
2.3 |
|
Allocation of DCG Predecessor investment |
|
|
|
|
|
|
(501.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
501.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement of net current and deferred income tax assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13.4 |
) |
|
|
|
|
|
|
(13.4 |
) |
|
|
|
|
|
|
(13.4 |
) |
Consideration provided to Dominion for DCG Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
200.0 |
|
|
|
|
|
|
|
(500.8 |
) |
|
|
|
|
|
|
(300.8 |
) |
|
|
|
|
|
|
(300.8 |
) |
Equity contributions from Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.7 |
|
|
|
|
|
|
|
0.7 |
|
|
|
941.2 |
|
|
|
941.9 |
|
Consideration provided to acquire a noncontrolling partnership interest in Iroquois |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
216.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
216.0 |
|
|
|
|
|
|
|
216.0 |
|
Purchase of common units by Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19.1 |
) |
|
|
19.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15.7 |
) |
|
|
(11.3 |
) |
|
|
(22.5 |
) |
|
|
|
|
|
|
|
|
|
|
(49.5 |
) |
|
|
|
|
|
|
(49.5 |
) |
Unit awards (net of unearned compensation) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.2 |
|
|
|
|
|
|
|
0.2 |
|
December 31, 2015 |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
600.8 |
|
|
$ |
438.8 |
|
|
$ |
475.4 |
|
|
$ |
(12.4 |
) |
|
$ |
|
|
|
$ |
1,502.6 |
|
|
$ |
2,138.4 |
|
|
$ |
3,641.0 |
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partnership
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Members Equity |
|
|
DCG Predecessor Equity |
|
|
Questar Pipeline Predecessor Equity |
|
|
Preferred Unitholders Public |
|
|
Preferred Unitholder Dominion |
|
|
Common Unitholders Public |
|
|
Common Unitholder Dominion |
|
|
Subordinated Unitholder Dominion |
|
|
General Partner Dominion (non-
economic interest) |
|
|
AOCI |
|
|
Total Dominion Midstream Partners, LP Partners Equity and Capital |
|
|
Noncontrolling interest |
|
|
Total Equity and Partners Capital |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015 |
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
600.8 |
|
|
$
|
438.8 |
|
|
$
|
475.4 |
|
|
$
|
(12.4 |
) |
|
$
|
|
|
|
$
|
1,502.6 |
|
|
$
|
2,138.4 |
|
|
$
|
3,641.0 |
|
Net income including noncontrolling interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0 |
|
|
|
1.2 |
|
|
|
42.6 |
|
|
|
21.3 |
|
|
|
37.0 |
|
|
|
2.3 |
|
|
|
|
|
|
|
106.4 |
|
|
|
117.8 |
|
|
|
224.2 |
|
Questar Pipeline Acquisition: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Record Dominions net investment in Questar Pipeline |
|
|
|
|
|
|
|
|
|
|
1,019.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,019.8 |
|
|
|
|
|
|
|
1,019.8 |
|
Net income attributable to Questar Pipeline Predecessor |
|
|
|
|
|
|
|
|
|
|
5.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.5 |
|
|
|
|
|
|
|
5.5 |
|
Contribution from Dominion to Questar Pipeline prior to Questar Pipeline Acquisition |
|
|
|
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
|
|
1.0 |
|
Contribution to QPC Services Company |
|
|
|
|
|
|
|
|
|
|
(37.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(37.0 |
) |
|
|
|
|
|
|
(37.0 |
) |
Allocation of Questar Pipeline Predecessor investment |
|
|
|
|
|
|
|
|
|
|
(989.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
989.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement of net current and deferred income tax assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
282.5 |
|
|
|
|
|
|
|
282.5 |
|
|
|
|
|
|
|
282.5 |
|
Consideration provided to Dominion for Questar Pipeline Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
300.0 |
|
|
|
|
|
|
|
167.3 |
|
|
|
|
|
|
|
(1,290.0 |
) |
|
|
|
|
|
|
(822.7 |
) |
|
|
|
|
|
|
(822.7 |
) |
Issuance of common units, net of offering costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
481.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
481.7 |
|
|
|
|
|
|
|
481.7 |
|
Issuance of Series A Preferred Units, net of offering costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
490.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
490.1 |
|
|
|
|
|
|
|
490.1 |
|
Equity contributions from Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.6 |
|
|
|
|
|
|
|
1.6 |
|
|
|
1,056.5 |
|
|
|
1,058.1 |
|
Purchase of common units by Dominion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14.2 |
) |
|
|
14.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase of common units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(167.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(167.3 |
) |
|
|
|
|
|
|
(167.3 |
) |
Distributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29.1 |
) |
|
|
(16.9 |
) |
|
|
(29.4 |
) |
|
|
(2.5 |
) |
|
|
|
|
|
|
(77.9 |
) |
|
|
|
|
|
|
(77.9 |
) |
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.4 |
) |
|
|
(0.4 |
) |
|
|
|
|
|
|
(0.4 |
) |
Unit awards (net of unearned compensation) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.3 |
|
|
|
|
|
|
|
0.3 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.0 |
|
|
|
1.0 |
|
December 31, 2016 |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
492.1 |
|
|
$ |
301.2 |
|
|
$ |
1,082.1 |
|
|
$ |
457.4 |
|
|
$ |
483.0 |
|
|
$ |
(29.2 |
) |
|
$ |
(0.4 |
) |
|
$ |
2,786.2 |
|
|
$ |
3,313.7 |
|
|
$ |
6,099.9 |
|
(1) |
Allocation of net income attributable to partners ownership interest subsequent to initial public offering has been adjusted for rounding. |
The accompanying notes are an integral part of Dominion Midstreams Consolidated Financial Statements.
57
Dominion Midstream Partners, LP
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income including noncontrolling interest and predecessors |
|
$ |
229.7 |
|
|
$ |
196.5 |
|
|
$ |
106.9 |
|
Adjustments to reconcile net income including noncontrolling interest and predecessors to net cash provided
by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
56.6 |
|
|
|
40.4 |
|
|
|
37.7 |
|
Deferred income taxes |
|
|
(1.5 |
) |
|
|
1.5 |
|
|
|
13.1 |
|
Other adjustments |
|
|
0.7 |
|
|
|
(3.4 |
) |
|
|
|
|
Changes in: |
|
|
|
|
|
|
|
|
|
|
|
|
Customer and other receivables |
|
|
1.5 |
|
|
|
(0.4 |
) |
|
|
0.1 |
|
Affiliated receivables |
|
|
5.2 |
|
|
|
(0.1 |
) |
|
|
(1.4 |
) |
Prepayments |
|
|
3.4 |
|
|
|
(1.0 |
) |
|
|
(4.6 |
) |
Accounts payable |
|
|
(3.4 |
) |
|
|
(1.3 |
) |
|
|
0.3 |
|
Payables to affiliates |
|
|
(13.0 |
) |
|
|
2.4 |
|
|
|
1.9 |
|
Accrued interest, payroll and taxes |
|
|
(5.0 |
) |
|
|
3.7 |
|
|
|
1.2 |
|
Other operating assets and liabilities |
|
|
14.4 |
|
|
|
5.2 |
|
|
|
0.9 |
|
Net cash provided by operating activities |
|
|
288.6 |
|
|
|
243.5 |
|
|
|
156.1 |
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Plant construction and other property additions |
|
|
(1,276.8 |
) |
|
|
(1,282.1 |
) |
|
|
(572.2 |
) |
Questar Pipeline Acquisition |
|
|
(819.1 |
) |
|
|
|
|
|
|
|
|
Change in restricted cash |
|
|
(25.0 |
) |
|
|
|
|
|
|
|
|
Other |
|
|
(1.9 |
) |
|
|
(0.6 |
) |
|
|
0.6 |
|
Net cash used in investing activities |
|
|
(2,122.8 |
) |
|
|
(1,282.7 |
) |
|
|
(571.6 |
) |
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of long-term debt |
|
|
300.0 |
|
|
|
|
|
|
|
|
|
Repayment of affiliated long-term debt |
|
|
(300.8 |
) |
|
|
|
|
|
|
|
|
Dominion credit facility borrowings, net |
|
|
57.3 |
|
|
|
5.9 |
|
|
|
|
|
Contributions from Dominion |
|
|
1,057.5 |
|
|
|
942.5 |
|
|
|
238.7 |
|
Net proceeds from issuance of common units |
|
|
481.7 |
|
|
|
|
|
|
|
392.5 |
|
Net proceeds from issuance of preferred units |
|
|
490.1 |
|
|
|
|
|
|
|
|
|
Repurchase of common units from Dominion |
|
|
(167.3 |
) |
|
|
|
|
|
|
|
|
Distributions to common unitholderspublic |
|
|
(29.1 |
) |
|
|
(15.7 |
) |
|
|
|
|
Distribution to common unitholderDominion |
|
|
(16.9 |
) |
|
|
(11.3 |
) |
|
|
(13.9 |
) |
Distribution to subordinated unitholderDominion |
|
|
(29.4 |
) |
|
|
(22.5 |
) |
|
|
(37.6 |
) |
Distribution to general partnerDominion |
|
|
(2.5 |
) |
|
|
|
|
|
|
|
|
Other |
|
|
(1.8 |
) |
|
|
(0.1 |
) |
|
|
|
|
Net cash provided by financing activities |
|
|
1,838.8 |
|
|
|
898.8 |
|
|
|
579.7 |
|
Increase (decrease) in cash and cash equivalents |
|
|
4.6 |
|
|
|
(140.4 |
) |
|
|
164.2 |
|
Cash and cash equivalents at beginning of period |
|
|
35.0 |
|
|
|
175.4 |
|
|
|
11.2 |
|
Cash and cash equivalents at end of period |
|
$ |
39.6 |
|
|
$ |
35.0 |
|
|
$ |
175.4 |
|
Supplemental Cash Flow Information |
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest and related charges, excluding capitalized amounts |
|
$ |
10.4 |
|
|
$ |
0.4 |
|
|
$ |
|
|
Income taxes |
|
|
|
|
|
|
|
|
|
|
38.6 |
|
Significant noncash investing and financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accrued capital expenditures |
|
|
27.5 |
|
|
|
16.3 |
|
|
|
6.7 |
|
Increase in property, plant and equipment from CPCN obligation |
|
|
|
|
|
|
|
|
|
|
44.1 |
|
Additional basis in property, plant and equipment received from Dominion |
|
|
|
|
|
|
|
|
|
|
23.2 |
|
Equity settlement of net current and deferred income taxes |
|
|
282.5 |
|
|
|
13.4 |
|
|
|
147.9 |
|
Equity contribution from Dominion to relieve payables to affiliates |
|
|
1.6 |
|
|
|
1.7 |
|
|
|
20.0 |
|
Equity contribution from Dominion related to income taxes prior to the Offering |
|
|
|
|
|
|
|
|
|
|
1.2 |
|
Questar Pipeline Acquisition through issuance of equity |
|
|
467.3 |
|
|
|
|
|
|
|
|
|
DCG Acquisition through issuance of debt and equity |
|
|
|
|
|
|
500.8 |
|
|
|
|
|
Acquisition of a noncontrolling partnership interest in Iroquois through issuance of equity |
|
|
|
|
|
|
216.0 |
|
|
|
|
|
Equity contribution to QPC Services Company for employee related
assets and liabilities |
|
|
37.0 |
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of Dominion Midstreams Consolidated Financial Statements.
[THIS PAGE INTENTIONALLY LEFT BLANK]
Notes to Consolidated Financial Statements
NOTE 1. DESCRIPTION OF BUSINESS
AND BASIS OF PRESENTATION
Description of Business
Dominion Midstream is a Delaware limited partnership formed in March 2014 by Dominion MLP Holding Company, LLC and Dominion Midstream GP, LLC, both
indirect wholly-owned subsidiaries of Dominion, to grow a portfolio of natural gas terminaling, processing, storage, transportation and related assets. On October 20, 2014, Dominion Midstream completed the Offering of 20,125,000 common units
representing limited partner interests. In connection with the Offering, Dominion Midstream acquired from Dominion the Preferred Equity Interest and non-economic general partner interest in Cove Point. A
registration statement on Form S-1, as amended through the time of its effectiveness, was filed by Dominion Midstream with the SEC and was declared effective on October 10, 2014. See Note 2 for
information regarding the closing of the Offering.
The Preferred Equity Interest is a perpetual,
non-convertible preferred equity interest entitled to Preferred Return Distributions so long as Cove Point has sufficient cash and undistributed Net Operating Income (determined on a cumulative basis from the
closing of the Offering) from which to make Preferred Return Distributions. Preferred Return Distributions are made on a quarterly basis and are not cumulative. Until the Liquefaction Project is completed, Cove Point is prohibited from making a
distribution on its common equity interests until it has a distribution reserve sufficient to pay two quarters of Preferred Return Distributions. The distribution reserve was fully funded in October 2016, but there can be no assurance that funds
will be sufficient for such purpose or that Cove Point will have sufficient cash and undistributed Net Operating Income to permit it to continue to make Preferred Return Distributions after the expiration of certain of its contracts in the second
quarter of 2017. The Preferred Equity Interest is also entitled to the Additional Return Distributions.
Cove Point is the owner and
operator of the Cove Point LNG Facility and the Cove Point Pipeline. The Cove Point LNG Facility is an LNG import/regasification and storage facility located on the Chesapeake Bay in Lusby, Maryland.
On April 1, 2015, Dominion Midstream acquired from Dominion all issued and outstanding membership interests in DCG as described further
in Note 4. DCG owns and operates nearly 1,500 miles of FERC-regulated open access, transportation-only interstate natural gas pipeline in South Carolina and southeastern Georgia.
On September 29, 2015, Dominion Midstream acquired a 25.93% noncontrolling partnership interest in Iroquois as described further in Notes
4 and 8. Iroquois, a Delaware limited partnership, owns and operates a 416-mile FERC-regulated interstate natural gas transmission pipeline that extends from the
Canada-U.S. border through the states of New York and Connecticut.
On December 1, 2016,
Dominion Midstream acquired from Dominion all of the issued and outstanding membership interests in Questar Pipeline as described further in Note 4. Questar Pipeline owns and operates nearly 2,200 miles of interstate natural gas pipelines and 18
transmission and storage compressor stations in the western U.S.
Basis of Presentation
The contribution by Dominion to Dominion Midstream of the general partner interest in Cove Point and a portion of the Preferred Equity Interest is considered
to be a reorganization of entities under common control. As a result, Dominion Midstreams basis is equal to Dominions cost basis in the general partner interest in Cove Point and a portion of the Preferred Equity Interest. As discussed
in Note 14, Dominion Midstream is the primary beneficiary of, and therefore consolidates, Cove Point. As such, Dominion Midstreams investment in the Preferred Equity Interest and Cove Points preferred equity interest are eliminated in
consolidation. Dominions retained common equity interest in Cove Point is reflected as noncontrolling interest.
The Questar
Pipeline Acquisition is considered to be a reorganization of entities under common control. As a result, Dominion Midstreams basis in Questar Pipeline is equal to Dominions cost basis in the assets and liabilities of Questar Pipeline. On
December 1, 2016, Questar Pipeline became a wholly-owned subsidiary of Dominion Midstream and is therefore consolidated by Dominion Midstream. The accompanying financial statements and related notes have been retrospectively adjusted to include
the historical results and financial position of Questar Pipeline beginning September 16, 2016, the inception date of common control.
The DCG Acquisition is considered to be a reorganization of entities under common control. As a result, Dominion Midstreams basis in DCG
is equal to Dominions cost basis in the assets and liabilities of DCG. On April 1, 2015, DCG became a wholly-owned subsidiary of Dominion Midstream and is therefore consolidated by Dominion Midstream. The accompanying financial statements
and related notes include the historical results and financial position of DCG beginning January 31, 2015, the inception date of common control.
For the period prior to the closing of the Offering on October 20, 2014, the financial statements included in this Annual Report on Form 10-K were derived from the financial statements and accounting records of Cove Point as our predecessor for accounting purposes. The financial statements were prepared using Dominions historical basis in the
assets and liabilities of Cove Point and include all revenues, costs, assets and liabilities attributed to Cove Point.
For the periods
subsequent to the closing of the Offering, the Consolidated Financial Statements represent the consolidated results of operations, financial position and cash flows of Dominion Midstream.
|
|
|
The consolidated statements of income, comprehensive income and cash flows for the year ended December 31, 2014, consist of the consolidated results of Dominion Midstream for the period from October 20, 2014
through December 31, 2014, and the results of our Predecessor for the period from January 1, 2014, through October 19, 2014. |
|
|
|
The consolidated statement of equity and partners capital for the year ended December 31, 2014, consists of both the activity for our Predecessor prior to October 20, 2014, and the consolidated activity
for Dominion Midstream completed at and subsequent to the Offering on October 20, 2014. |
The financial statements for all years presented include costs for certain general,
administrative and corporate expenses assigned by DRS, DCGS (Dominion Payroll prior to January 1, 2016) or QPC Services Company to Dominion Midstream and Cove Point on the basis of direct and allocated methods in accordance with Dominion
Midstreams services agreements with DRS, DCGS (Dominion Payroll prior to January 1, 2016) and QPC Services Company and Cove Points services agreement with DRS. Where costs incurred cannot be determined by specific identification,
the costs are allocated based on the proportional level of effort devoted by DRS, DCGS (Dominion Payroll prior to January 1, 2016) or QPC Services Company resources that is attributable to the entities, determined by reference to number of
employees, salaries and wages and other similar measures for the relevant DRS, DCGS (Dominion Payroll prior to January 1, 2016) or QPC Services Company service. Management believes the assumptions and methodologies underlying the allocation of
general corporate overhead expenses are reasonable. Nevertheless, the Consolidated Financial Statements prior to the Offering may not include all of the actual expenses that would have been incurred had we been a stand-alone publicly traded
partnership during the periods presented, and may not reflect our actual results of operations, financial position and cash flows had we been a stand-alone publicly traded partnership during the periods prior to the Offering.
Dominion Midstream reports one operating segment, Dominion Energy, which consists of gas transportation, LNG import and storage. In addition
to the Dominion Energy operating segment, Dominion Midstream also reports a Corporate and Other segment, which primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive
management in assessing the segments performance. See Note 23 for further discussions of Dominion Midstreams operating segment.
NOTE 2. INITIAL
PUBLIC OFFERING AND SERIES A PREFERRED UNITS
On
October 15, 2014, Dominion Midstreams common units began trading on the NYSE under the ticker symbol DM. On October 20, 2014, Dominion Midstream closed the Offering of 20,125,000 common units to the public at a price of
$21.00 per common unit, which included a 2,625,000 common unit over-allotment option that was exercised in full by the underwriters.
In
exchange for Dominions contribution of the general partner interest in Cove Point and a portion of the Preferred Equity Interest to us, which we contributed to Cove Point Holdings, Dominion received:
|
|
11,847,789 common units and 31,972,789 subordinated units, representing an aggregate 68.5% limited partner interest; |
|
|
A non-economic general partner interest; and |
|
|
A cash distribution of $51.5 million as described in the partnership agreement. |
Dominion
Midstream received net proceeds of $392.4 million from the sale of 20,125,000 common units, after deducting underwriting discounts, structuring fees and offering expenses of $30.2 million, which were allocated to the public
common units. Dominion Midstream utilized $340.9 million of net proceeds to make, through Cove Point Holdings, a contribution to Cove Point in exchange for the remaining portion of the
Preferred Equity Interest.
|
|
|
|
|
Reconciliation of Cash Proceeds |
|
|
|
(millions) |
|
|
|
Total proceeds from the Offering |
|
$ |
422.6 |
|
Less: Underwriting discounts, structuring fees and offering
expenses |
|
|
(30.2 |
) |
Net proceeds from the Offering |
|
|
392.4 |
|
Less: Contribution to Cove Point for remaining portion of Preferred
Equity Interest |
|
|
340.9 |
|
Net proceeds distributed to Dominion from the Offering |
|
$ |
51.5 |
|
Additional information pertaining to the transactions effected at the closing of the Offering on
October 20, 2014 is provided as follows:
|
|
Dominions contribution of the general partner interest in Cove Point and a portion of the Preferred Equity Interest to us was an exchange of ownership interests between entities under common control. As a result,
Dominion Midstreams basis is equal to Dominions cost basis in the general partner interest in Cove Point and a portion of the Preferred Equity Interest. Dominions interest in Cove Point is reflected as noncontrolling interest
equity of Dominion Midstream. The equity attributable to the noncontrolling interest is calculated based on the predecessor historical parent net equity adjusted for the transactions effected at the closing of the Offering. |
|
|
In connection with the termination of Cove Points participation in Dominions intercompany tax sharing agreement, the settlement of Cove Points obligations related to existing federal and state income
tax payables, receivables and deferred income taxes is reflected as an equity transaction in the Consolidated Financial Statements. Beginning October 20, 2014, Dominion Midstream, as a pass-through entity, is generally not subject to income
taxes. |
|
|
Dominion Midstream recorded additional basis in Dominions equity interests in Cove Point not reflected on the predecessor financial statements. This increase in basis relates to additional capitalized interest
that was limited at Cove Point to actual interest incurred but is reflected in Dominions basis in Cove Points property, plant and equipment. Since this transaction was an exchange of ownership interest between entities under common
control, Dominion Midstreams basis equals Dominions historical basis. |
Series A Preferred Units
On December 1, 2016, Dominion Midstream issued a total of 30,308,342 Series A Preferred Units representing a limited partner interest for a price of $26.40
per unit. Series A Preferred Units with a value of $300.0 million, or 11,365,628 units, were issued to Dominion as partial consideration in connection with the Questar Pipeline Acquisition. Series A Preferred Units with a value of $490.1 million,
net of offering fees and expenses, or 18,942,714 units, were issued to purchasers of such units pursuant to the Private Placement Agreement for cash. The units issued to Dominion in connection with the Questar Pipeline Acquisition and to the
purchasers of the Series A Preferred Units pursuant to the Private Placement Agreement were issued in reliance upon an exemption from the requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereto.
Notes to Consolidated Financial Statements, Continued
The Series A Preferred Units are convertible into our common units on a one-for-one basis,
subject to certain adjustments, (i) in whole or in part at the option of the Series A Preferred Unitholders any time, but only once per quarter, after December 1, 2018 or prior to a liquidation of Dominion Midstream, subject to certain minimum
conversion amounts, or (ii) in whole or in part at our option any time, but only once per quarter, after December 1, 2019, subject to certain minimum conversion amounts, if the closing price of our common units is greater than $36.96 and the average
trading volume of the common units is at least 100,000 for the preceding 20 trading days. In addition, upon certain events involving a change of control, the holders of our Series A Preferred Units may elect, subject to certain conditions, to (i)
convert their Series A Preferred Units to our common units at the then-applicable conversion rate, (ii) if Dominion Midstream is not the surviving entity (or if Dominion Midstream is the surviving entity, but our common units cease to be listed),
require Dominion Midstream to use commercially reasonable efforts to cause the surviving entity in any such transaction to issue a substantially equivalent security, (iii) if Dominion Midstream is the surviving entity, continue to hold their Series
A Preferred Units, or (iv) require Dominion Midstream to redeem the Series A Preferred Units in accordance with the terms of our partnership agreement, with such redemption to be paid in cash or common units at Dominion Midstreams discretion.
The Series A Preferred Units will vote on an as-converted basis with our common units and will have certain other voting rights with
respect to any amendment to our partnership agreement that would adversely affect the rights, preferences, and privileges of the Series A Preferred Units.
The Series A Preferred Units rank senior to all classes of our equity securities including IDRs with respect to distribution rights. The
holders of the Series A Preferred Units are entitled to receive cumulative quarterly distributions of $0.3134 per Series A Preferred Unit, commencing with the quarter ended December 31, 2016 with a prorated amount from the date of issuance to be
paid for such quarter. For any quarter ending prior to December 1, 2018, the distributions to holders of the Series A Preferred Units are payable in cash, additional Series A Preferred Units, or a combination thereof, at the discretion of our
general partner. For any quarter ending after December 1, 2018, the Series A Preferred Unit distribution amount is equal to the greater of $0.3134 per Series A Preferred Unit and the distribution for such quarter that would have been payable if such
Series A Preferred Unit had converted into common units immediately prior to the record date for such quarter at the then-applicable conversion rate, payable in cash; provided that, if at any time after December 1, 2019, the conditions for our
conversion rights are satisfied, the Series A Preferred Unit distribution amount payable in cash shall be set for each quarter thereafter at an amount equal to greater of $0.3134 per Series A Preferred Unit and the distribution for the quarter
immediately preceding the date on which such conditions are first satisfied that would have been payable if such Series A Preferred Unit had converted into common units on the record date for such quarter at the then-applicable conversion rate.
NOTE 3. SIGNIFICANT ACCOUNTING POLICIES
General
Dominion Midstream makes certain estimates and assumptions
in preparing its financial statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the
reported amounts of revenues, expenses, and cash flows for the periods presented. Actual results may differ from those estimates.
Dominion Midstreams Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of
their respective majority-owned subsidiaries.
Dominion Midstream reports certain contracts and instruments at fair value. The carrying
values of customer and other receivables, affiliated receivables, payables to affiliates, Dominion credit facility borrowings and accounts payable are estimated to be substantially the same as their fair values at December 31, 2016 and 2015.
Cove Point participated in Dominions intercompany tax sharing agreement prior to the Offering. DCG and Questar Pipeline
participated in Dominions intercompany tax sharing agreement prior to the DCG Acquisition and the Questar Pipeline Acquisition, respectively. See Note 21 for further information on accounting for income taxes.
Cove Point participates in certain Dominion-sponsored pension and other postretirement benefit plans. See Note 16 for further information on
these plans.
Operating Revenue
Operating revenue is recorded
on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Dominion Midstream is currently generating significant revenue and earnings from annual reservation payments under
long-term regasification, firm peaking storage and firm transportation contracts. Straight-fixed-variable rate designs are used to allow for recovery of substantially all fixed costs in demand or reservation charges, thereby reducing the earnings
impact of volume changes on gas transportation and storage operations. Customer receivables at December 31, 2016 and 2015 included $50.6 million and $19.9 million, respectively, of accrued unbilled revenue based on estimated amounts
of natural gas delivered but not yet billed to its customers.
Cove Point renegotiated certain import-related contracts which resulted in
annual payments in the years 2013 through 2016 totaling approximately $50 million. DCG collects facility charges related with certain of its expansion projects. These facility charges are expected to total approximately $15.5 million and
will be collected in the years 2014 through 2017. At December 31, 2016, DCG has collected $14.0 million in facility charges, including $13.0 million collected subsequent to the DCG Acquisition. These facility charges are amortized to
revenue over the term of the related transportation contract once the related projects have been placed into service. Deferred revenue represents the difference between the amount received and the revenue recognized.
The primary types of sales and service activities reported as operating revenue are as follows:
|
|
Gas transportation and storage revenue consists primarily of FERC-regulated sales of storage and transmission services;
|
|
|
Regulated gas sales consist primarily of FERC-regulated natural gas sales; and |
|
|
Other revenue consists primarily of sales of purchased gas retained for use in routine operations and LNG cargoes and the renegotiated contract payments described above. |
Purchased GasDeferred Costs
The difference between purchased
gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory
asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.
Income Taxes
Dominion Midstream is organized as an MLP. As a pass-through entity for U.S. federal and state income tax purposes, each of its unitholders is responsible for
taking into account the unitholders respective share of Dominion Midstreams items of taxable income, gain, loss and deduction in the preparation of income tax returns. Income before taxes, as determined under GAAP, may differ
significantly from taxable income reportable to unitholders. Such differences may result from different bases of assets and liabilities and timing of recognition for income, gains, losses and expenditures for tax and financial reporting purposes, as
well as the taxable income allocation requirements under the partnership agreement.
As an MLP, at least 90% of Dominion Midstreams
total gross income must constitute qualifying income, determined on a calendar year basis under applicable income tax law. If the amount of qualifying income does not satisfy this requirement, Dominion Midstream would be taxed as a corporation. For
the period October 20, 2014, through December 31, 2016, Dominion Midstreams qualifying income exceeded the required amount. The Consolidated Financial Statements reflect managements conclusion that Dominion Midstreams
status as a pass-through entity, if examined, would be sustained based on the technical merits of applicable tax law.
Prior to the
Offering, Cove Point was not a separate taxable entity for U.S. federal and state income tax purposes. Cove Points business activities were included in the consolidated U.S. federal income tax return filed by Dominion and its subsidiaries,
DCPIs Maryland state income tax returns and combined Virginia income tax returns filed by Dominion and certain subsidiaries. With Dominion Midstreams acquisition of the Preferred Equity Interest and the general partnership interest in
Cove Point, Cove Point is treated as a limited partnership, a pass-through entity for U.S. federal and state income tax purposes. Dominion Midstreams Consolidated Financial Statements reflect Cove Points income taxes for the period prior
to the Offering.
DCG operated as a taxable corporation at the time of Dominions acquisition of DCG. In March 2015, DCG converted to
a single member limited liability company and as a result, became a disregarded entity for income tax purposes and was treated as a taxable division of its corporate parent. Its business activities from the time of Dominions acquisition of DCG
through March 2015 were included in the consolidated U.S. federal and certain state income tax returns of Dominion. Dominion Midstreams Consolidated Financial Statements reflect income taxes for the same period.
Questar Pipeline is a disregarded entity for income tax purposes and was treated as a taxable division of its corporate parent.
Its business activities from the time of Dominions acquisition of Dominion Questar through November 2016 will be included in the consolidated U.S. federal and certain state income tax
returns of Dominion. Dominion Midstreams Consolidated Financial Statements reflect income taxes for the same period.
Current income
taxes for Cove Point, DCG and Questar Pipeline were based on taxable income or loss, determined on a separate company basis, and, where applicable, settled in accordance with the principles of Dominions intercompany tax sharing agreement.
Deferred income tax assets and liabilities were provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes were
recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. In addition, a valuation allowance was established when it was
more-likely-than-not that all, or a portion, of a deferred tax asset would not be realized. Where the treatment of temporary differences was different for rate-regulated operations, a regulatory asset was
recognized if it is probable that future revenues would be provided for the payment of deferred tax liabilities. Dominion Midstreams reported amounts of assets and liabilities exceeded tax bases by $1.4 billion at December 31, 2016.
Judgment and the use of estimates are required in developing the provision for income taxes and reporting of
tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. For periods in which income taxes are included, a position
taken, or expected to be taken, in income tax returns is recognized only if it is more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all
relevant information. If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized
tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility,
the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities,
noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities and current payables are included in accrued payroll and taxes on the Consolidated Balance Sheets.
Under Dominions tax sharing agreement, federal and state income taxes of $38.6 million were paid to Dominion and DCPI for the year
ended December 31, 2014. In addition, the settlements of the federal and state net income tax payables and deferred income taxes of Cove Point, DCG and Questar Pipeline are reflected as equity transactions in Dominion Midstreams
Consolidated Financial Statements.
Interest accrued on uncertain tax positions is included in interest expense or income, as applicable.
No penalties were accrued and interest expense was not material in all years presented.
Cash and Cash Equivalents
Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31,
Notes to Consolidated Financial Statements, Continued
2016 and 2015, accounts payable included $0.3 million and $0.8 million, respectively, of checks outstanding but not yet presented for payment. For purposes of the Balance Sheets and
Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.
Restricted Cash
In October 2016, Cove Point fully funded a
distribution reserve of $25.0 million, sufficient to pay two quarters of Preferred Return Distributions.
Investment in Equity Method Affiliates
Investments in affiliates where Dominion Midstream exercises significant influence over the operating activities of the entity, but does not control the
entity, are accounted for using the equity method. Such investments are included in investment in equity method affiliates in the Consolidated Balance Sheets. Dominion Midstream records equity method adjustments in earnings from equity method
affiliates in the Consolidated Statements of Income, including its proportionate share of investee income or loss and other adjustments required by the equity method.
Dominion Midstream periodically evaluates its equity method investments to determine whether a decline in fair value should be considered
other-than-temporary. If a decline in fair value of an investment is determined to be other-than-temporary, the investment is written down to its fair value at the end of the reporting period.
Property, Plant and Equipment
Property, plant and equipment,
including additions and replacements is recorded at original cost, consisting of labor and materials and other costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as it is incurred.
In 2016, 2015 and 2014, Dominion Midstream capitalized interest costs and AFUDC of $5.7 million, $2.0 million and $0.1 million,
respectively, to property, plant and equipment.
For property subject to
cost-of-service rate regulation, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of
removal collections not representing AROs are recorded as regulatory liabilities.
For property that is not subject to cost-of-service rate regulation, cost of removal not associated with AROs is charged to expense as incurred. Dominion Midstream also records gains and losses upon retirement
based upon the difference between the proceeds received, if any, and the propertys net book value at the retirement date.
Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. Depreciation rates on
utility property, plant and equipment are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(percent) |
|
|
|
|
|
|
|
|
|
Storage |
|
|
2.41 |
|
|
|
2.38 |
|
|
|
2.39 |
|
Transmission |
|
|
2.93 |
|
|
|
3.15 |
|
|
|
2.81 |
|
Gas gathering and processing |
|
|
5.04 |
|
|
|
|
|
|
|
|
|
General and other |
|
|
8.05 |
|
|
|
7.01 |
|
|
|
4.09 |
|
In 2014, Cove Point shortened the useful life of assets expected to be retired as a result of commencement of
construction on the generating station associated with the Liquefaction Project, which resulted in an increase to depreciation expense of $6.2 million.
In connection with its rate case filing in November 2016, Cove Point revised its depreciation rates effective January 2017. The estimated
annual impact is a $4.1 million increase to depreciation expense.
Long-Lived and Intangible Assets
Dominion Midstream performs an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or
intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite
lives are amortized over their estimated useful lives.
Regulatory Assets and Liabilities
For regulated businesses subject to FERC cost-of-service rate regulation,
regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that FERC will permit the recovery of current costs through future rates charged to
customers, these costs that otherwise would be expensed by nonregulated companies, are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that FERC will require customer refunds through future rates or
when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by FERC.
Dominion Midstream evaluates whether or not recovery of its regulatory assets through future rates is probable and makes various assumptions
in its analyses. The expectations of future recovery are generally based on orders issued by FERC, legislation or historical experience, as well as discussions with FERC and legal counsel. If recovery of a regulatory asset is determined to be less
than probable, it will be written off in the period such assessment is made.
Inventories
Materials and supplies and gas stored are valued primarily using the weighted-average cost method.
Natural Gas Imbalances
Natural gas imbalances occur when the
physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion Midstream values these imbalances due to, or from, shippers and
operators at an appropriate index price at period end, subject to the terms of the tariff for each regulated entity. Imbalances are settled in-kind and in cash. Imbalances due to Dominion Midstream from other
parties are reported as current assets and imbalances that Dominion Midstream owes to other parties are reported as current liabilities in the Consolidated Balance Sheets.
Debt Issuance Costs
Dominion Midstream defers and amortizes debt
issuance costs over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction of
long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with the redemptions of debt securities prior
to stated maturity dates are generally recognized and recorded in interest expense immediately. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate
regulation are deferred and amortized over the lives of the new issuances.
Goodwill
Dominion Midstream evaluates goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that
would more-likely-than-not reduce the fair value of a reporting unit below its carrying value.
Asset Retirement
Obligations
Dominion Midstream recognizes AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable
estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not
available, fair value is estimated using discounted cash flow analyses. Periodically, Dominion Midstream evaluates the key assumptions underlying its AROs including estimates of the amounts and timing of future cash flows associated with retirement
activities. AROs are adjusted when significant changes in these assumptions are identified. Dominion Midstream reports accretion of AROs and depreciation on asset retirement costs associated with its natural gas pipeline assets as an adjustment to
the related regulatory liabilities when revenue is recoverable from customers for AROs.
New Accounting Standards
In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. The core principle of this revised accounting
guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.
The amendments in this update also require disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
For Dominion Midstream, the revised accounting guidance is effective for interim and annual periods beginning January 1, 2018. We have
completed the preliminary stages of evaluating the impact of this guidance and, pending evaluation of the item discussed below, expect no significant impact on our results of operations. Now that our preliminary evaluation is complete, we will
expand the scope of our assessment to include all contracts with customers. In addition, we are considering certain issues including recognition of revenue in contracts with variable consideration. Dominion Midstream intends to apply the standard
using the modified retrospective method as opposed to the full retrospective method.
NOTE 4.
ACQUISITIONS
Questar Pipeline
In October
2016, Dominion Midstream, following approval by the Conflicts Committee of Dominion Midstream GP, LLC, its general partner, entered into the Questar Pipeline Contribution Agreement to acquire Questar Pipeline from Dominion. Upon
closing of the agreement on December 1, 2016, Dominion Midstream became the owner of all of the issued and outstanding membership interests of Questar Pipeline in exchange for consideration
consisting of: (1) 6,656,839 common units with a value of $167.3 million (the number of Dominion Midstream common units issued to Dominion was determined by the volume-weighted average trading price of Dominion Midstreams common units on
the NYSE for the 10-day trading period immediately preceding closing,) (2) 11,365,628 Series A Preferred Units with a value of $300.0 million and (3) a cash payment of $822.7 million,
$300.0 million of which is treated as a debt-financed distribution, for total consideration of $1.29 billion. In addition, Questar Pipelines debt of $435.0 million remains outstanding. As a result of the transaction, Dominion
Midstream owns 100% of the membership interests in Questar Pipeline and will therefore consolidate Questar Pipeline in its financial statements. Because the contribution of Questar Pipeline by Dominion to Dominion Midstream is considered a
reorganization of entities under common control, Questar Pipelines assets and liabilities are recorded in Dominion Midstreams consolidated financial statements at Dominions historical cost of $989.3 million at December 1, 2016.
Common control began on September 16, 2016, concurrent with Dominions acquisition of Dominion Questar, which was accounted for using the acquisition method of accounting. Accordingly, the consolidated financial statements of Dominion
Midstream reflect Questar Pipelines financial results beginning September 16, 2016. The Questar Pipeline Acquisition supports the expansion of Dominion Midstreams portfolio of natural gas terminaling, processing, storage,
transportation and related assets.
To facilitate the financing of the acquisition of Questar Pipeline, Dominion Midstream completed a
public issuance of 15,525,000 common units, which included a 2,025,000 common unit over-allotment option that was exercised in full by the underwriters, resulting in proceeds of $347.6 million, net of offering costs of $12.6 million, in
November 2016. In addition, in December 2016, Dominion Midstream completed the private placement of 5,990,634 common units with a value of $137.5 million (determined by the price of the common units in the public offering discussed above,
less $0.2475 in accordance with the Private Placement Agreement) and 18,942,714 Series A Preferred Units with a value of $500.0 million. Also in December 2016, Dominion Midstream entered into a $300.0 million three-year term loan
agreement, which bears interest at a variable rate. The key terms of the term loan agreement are discussed in Note 15. Offering expenses associated with the private placement of common units ($3.1 million) and Series A Preferred Units
($9.9 million) and the term loan agreement ($1.5 million) were funded through a draw on the existing revolving credit facility with Dominion. As a condition to closing under the Questar Pipeline Contribution Agreement, Dominion Midstream
repaid the outstanding $300.8 million senior unsecured promissory note payable to Dominion and repurchased 6,656,839 common units from Dominion for $167.3 million (based on the volume-weighted average trading price of Dominion
Midstreams common units on the NYSE for the 10-day trading period immediately preceding closing) in December 2016.
In connection with the private placement of common units and Series A Preferred Units, Dominion Midstream entered into
Notes to Consolidated Financial Statements, Continued
a registration rights agreement under which Dominion Midstream is required to register (1) the common units by March 31, 2017, (2) common units issuable upon conversion of the
Series A Preferred Units by December 1, 2018, and (3) the Series A Preferred Units no earlier than December 1, 2021 provided that the required amount of units remain outstanding. Dominion Midstreams registration statement for the
applicable common units became effective in February 2017.
In connection with the acquisition of Questar Pipeline, transaction and
transition costs of $2.0 million incurred by our general partner were expensed to operations and maintenance expense in the Consolidated Statements of Income. Dominion paid $1.6 million of these costs. Dominion did not seek reimbursement
for such costs and accordingly, Dominion Midstream recognized an equity contribution from the general partner.
DCG
On April 1, 2015, Dominion Midstream entered into a Purchase, Sale and Contribution Agreement with Dominion pursuant to which Dominion Midstream acquired
from Dominion all of the issued and outstanding membership interests of DCG in exchange for total consideration of $500.8 million, as adjusted for working capital. Total consideration to Dominion consisted of the issuance of a two-year $300.8 million senior unsecured promissory note, as adjusted for working capital, payable to Dominion at an annual interest rate of 0.6%, and 5,112,139 common units, valued at $200.0 million,
representing limited partner interests in Dominion Midstream, to Dominion. The number of units was based on the volume weighted average trading price of Dominion Midstreams common units for the 10 trading days prior to April 1, 2015, or
$39.12 per unit. For the year ended December 31, 2016, total transition costs of $1.3 million were expensed as incurred to operations and maintenance expense in the Consolidated Statements of Income. These costs were paid by Dominion, and
Dominion Midstream subsequently reimbursed Dominion. Subsequent to the DCG Acquisition through December 31, 2015, total transaction and transition costs of $2.0 million were expensed as incurred to operations and maintenance expense in the
Consolidated Statements of Income. These costs were paid by Dominion. Dominion did not seek reimbursement for $0.7 million of such costs incurred subsequent to the DCG Acquisition in 2015, and accordingly Dominion Midstream recognized a capital
contribution by the general partner. The DCG Acquisition supports the expansion of Dominion Midstreams portfolio of natural gas terminaling, processing, storage, transportation and related assets.
The contribution of DCG by Dominion to Dominion Midstream is considered to be a reorganization of entities under common control. Accordingly,
Dominion Midstreams net investment in DCG is recorded at Dominions historical cost of $501.6 million as of April 1, 2015. Common control began on January 31, 2015, concurrent with Dominions acquisition of DCG from
SCANA, which was accounted for using the acquisition method of accounting. Accordingly, the Consolidated Financial Statements of Dominion Midstream reflect DCGs financial results beginning January 31, 2015.
In connection with the DCG Acquisition, Dominion Midstream entered into a registration rights agreement with Dominion pursuant to which
Dominion Midstream must register the 5,112,139 common units issued to Dominion at its request, subject to certain terms and conditions. Additionally, at the time of
Dominions acquisition of DCG, DCG entered into services agreements and an intercompany tax sharing agreement with Dominion as described in Note 20.
Iroquois
On August 14, 2015, Dominion Midstream entered into
Contribution Agreements with NG and NJNR. On September 29, 2015, pursuant to the Contribution Agreements, Dominion Midstream acquired a 25.93% noncontrolling partnership interest in Iroquois, consisting of NGs 20.4% and NJNRs 5.53%
partnership interests in Iroquois and, in exchange, Dominion Midstream issued common units representing limited partnership interests in Dominion Midstream to both NG (6,783,373 common units) and NJNR (1,838,932 common units). The number of units
was based on the volume-weighted average trading price of Dominion Midstreams common units for the five trading days prior to August 14, 2015, or $33.23 per unit. The acquisition of the 25.93% noncontrolling partnership interest in
Iroquois supports the expansion of Dominion Midstreams portfolio of natural gas terminaling, processing, storage, transportation and related assets. The Iroquois investment, accounted for under the equity method, was recorded at
$216.5 million based on the value of Dominion Midstreams common units at closing, including $0.5 million of external transaction costs.
NG and NJNR agreed to certain transfer restrictions applicable to the 8,622,305 common units issued to them, including, with limited
exceptions, a one-year lockup period following the closing of the transactions described above. In addition, at closing, Dominion Midstream entered into registration rights agreements with NG and NJNR pursuant
to which Dominion Midstream was required to register the common units issued to NG and NJNR for resale when Dominion Midstream became eligible to file a registration statement on Form S-3. Such registration
statement, filed on November 2, 2015, does not change the lockup periods to which NG and NJNR are subject. No market issuance of the common units is planned in connection with the transactions described above.
NOTE 5. NET INCOME PER LIMITED PARTNER UNIT
Net income per limited partner unit applicable to common and subordinated units is computed by dividing the respective limited partners
interest in net income attributable to Dominion Midstream, after deducting any distributions to holders of Series A Preferred Units and incentive distributions, by the weighted average number of common and subordinated units outstanding. Because
Dominion Midstream has more than one class of participating securities, the two-class method is used when calculating the net income per unit applicable to limited partners. The classes of participating
securities include common units, subordinated units, Series A Preferred Units and IDRs.
Dominion Midstreams net income is allocated
to the limited partners in accordance with their respective partnership interests, after giving effect to priority income allocations to the holders of the Series A Preferred Units and incentive distributions, if any, to Dominion, the holder of the
IDRs, pursuant to the partnership agreement. The distributions are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the common and subordinated unitholders based on their
respective ownership interests. Payments made to Dominion Midstreams unitholders are determined in relation to actual distributions declared and are not based on the net income allocations
used in the calculation of earnings per limited partner unit.
Net income per limited partner unit is only calculated for the periods
subsequent to the Offering as no units were outstanding prior to October 20, 2014. Diluted net income per limited partner unit is the same as basic net income per limited partner unit as there were no potentially dilutive common or subordinated
units outstanding at December 31, 2015 and 2014. The Series A Preferred Units are potentially dilutive securities but for the year ended December 31, 2016 were antidilutive.
The calculation of net income per limited partner unit is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Net income attributable to partners |
|
$ |
106.4 |
|
|
$ |
72.5 |
|
|
$ |
9.5 |
|
Less: General partner allocation(1) |
|
|
(1.6 |
) |
|
|
(0.7 |
) |
|
|
|
|
Less: Preferred unitholder allocation |
|
|
3.2 |
|
|
|
|
|
|
|
|
|
Distributions declared on: |
|
|
|
|
|
|
|
|
|
|
|
|
IDRs(2) |
|
|
3.9 |
|
|
|
0.2 |
|
|
|
|
|
Common unitholders(3) |
|
|
53.8 |
|
|
|
32.3 |
|
|
|
4.5 |
|
Subordinated
unitholder(3) |
|
|
30.9 |
|
|
|
24.8 |
|
|
|
4.4 |
|
Total distributions declared |
|
|
88.6 |
|
|
|
57.3 |
|
|
|
8.9 |
|
Undistributed earnings |
|
$ |
16.2 |
|
|
$ |
15.9 |
|
|
$ |
0.6 |
|
(1) |
See Note 4 for further information. |
(2) |
Dominion is a non-economic general partner that holds all of the IDRs. |
(3) |
Allocation of distributions for 2014 has been adjusted for rounding. |
Distributions are
declared subsequent to quarter end. The table below summarizes the quarterly distributions on common and subordinated units related to 2014, 2015 and 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly Period Ended |
|
Total Quarterly Distribution (per unit) |
|
|
Total Cash Distribution
(in millions) |
|
|
Date of Declaration |
|
|
Date of Record |
|
|
Date of Distribution |
|
December 31, 2014 |
|
$ |
0.1389 |
(1) |
|
$ |
8.9 |
|
|
|
January 23, 2015 |
|
|
|
February 3, 2015 |
|
|
|
February 13, 2015 |
|
March 31, 2015 |
|
|
0.1750 |
|
|
|
12.1 |
|
|
|
April 22, 2015 |
|
|
|
May 5, 2015 |
|
|
|
May 15, 2015 |
|
June 30, 2015 |
|
|
0.1875 |
|
|
|
12.9 |
|
|
|
July 17, 2015 |
|
|
|
August 4, 2015 |
|
|
|
August 14, 2015 |
|
September 30, 2015 |
|
|
0.2000 |
|
|
|
15.5 |
|
|
|
October 23, 2015 |
|
|
|
November 3, 2015 |
|
|
|
November 13, 2015 |
|
December 31, 2015 |
|
|
0.2135 |
|
|
|
16.8 |
|
|
|
January 21, 2016 |
|
|
|
February 5, 2016 |
|
|
|
February 15, 2016 |
|
March 31, 2016 |
|
|
0.2245 |
|
|
|
17.8 |
|
|
|
April 19, 2016 |
|
|
|
May 3, 2016 |
|
|
|
May 13, 2016 |
|
June, 30, 2016 |
|
|
0.2355 |
|
|
|
19.0 |
|
|
|
July 22, 2016 |
|
|
|
August 5, 2016 |
|
|
|
August 15, 2016 |
|
September 30, 2016 |
|
|
0.2475 |
|
|
|
24.3 |
|
|
|
October 21, 2016 |
|
|
|
November 4, 2016 |
|
|
|
November 15, 2016 |
|
December 31,
2016 |
|
|
0.2605 |
|
|
|
27.5 |
|
|
|
January 25, 2017 |
|
|
|
February 6, 2017 |
|
|
|
February 15, 2017 |
|
(1) |
For the period subsequent to the Offering through December 31, 2014, the initial quarterly cash distribution was calculated as the minimum quarterly distribution of $0.1750 per unit prorated for the portion of
the quarter subsequent to the Offering.
|
Record holders of the Series A Preferred Units are entitled to receive cumulative quarterly distributions,
payable in cash, payable in kind or a combination thereof at the option of our general partner, equal to $0.3134 in respect of each quarter ending before December 1, 2018. The table below summarizes the quarterly distributions on the Series A
Preferred Units related to 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly Period Ended |
|
Total Distribution
(in millions) |
|
|
Amount Payable in Cash
(in millions) |
|
|
Amount Payable in Kind (in millions) |
|
December 31, 2016 |
|
$ |
3.2 |
(1) |
|
$ |
3.2 |
|
|
$ |
|
|
(1) |
For the period subsequent to the issuance of the Series A Preferred Units through December 31, 2016, the initial quarterly cash distribution was calculated as the minimum quarterly distribution of $0.3134 per
unit prorated for the portion of the quarter subsequent to the issuance of the Series A Preferred Units. |
Basic and
diluted net income per limited partner unit for the year ended December 31, 2016 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Units |
|
|
Subordinated Units |
|
|
Series A Preferred Units |
|
|
General Partner (including IDRs) |
|
|
Total |
|
(millions, except for weighted average units and per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner allocation |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1.6 |
) |
|
$ |
(1.6 |
) |
Preferred unitholder allocation |
|
|
|
|
|
|
|
|
|
|
3.2 |
|
|
|
|
|
|
|
3.2 |
|
Distributions declared |
|
|
53.8 |
|
|
|
30.9 |
|
|
|
|
|
|
|
3.9 |
|
|
|
88.6 |
|
Undistributed earnings |
|
|
9.8 |
|
|
|
6.4 |
|
|
|
|
|
|
|
|
|
|
|
16.2 |
|
Net income attributable to partners |
|
$ |
63.6 |
|
|
$ |
37.3 |
|
|
$ |
3.2 |
|
|
$ |
2.3 |
|
|
$ |
106.4 |
|
Weighted average units outstanding |
|
|
48,732,519 |
|
|
|
31,972,789 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per limited partner unit |
|
$ |
1.30 |
|
|
$ |
1.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income per limited partner unit for the year ended December 31, 2015 are
as follows: |
|
|
|
Common Units |
|
|
Subordinated Units |
|
|
General Partner (including IDRs) |
|
|
Total |
|
(millions, except for weighted average units and per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
General partner allocation |
|
$ |
|
|
|
$ |
|
|
|
$ |
(0.7 |
) |
|
|
$(0.7 |
) |
Distributions declared |
|
|
32.3 |
|
|
|
24.8 |
|
|
|
0.2 |
|
|
|
57.3 |
|
Undistributed earnings |
|
|
8.7 |
|
|
|
7.2 |
|
|
|
|
|
|
|
15.9 |
|
Net income attributable to partners |
|
$ |
41.0 |
|
|
$ |
32.0 |
|
|
$ |
(0.5 |
) |
|
|
$72.5 |
|
Weighted average units
outstanding |
|
|
38,052,303 |
|
|
|
31,972,789 |
|
|
|
|
|
|
|
|
|
Net income per limited partner unit |
|
$ |
1.08 |
|
|
$ |
1.00 |
|
|
|
|
|
|
|
|
|
Notes to Consolidated Financial Statements, Continued
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income per limited partner unit for the period subsequent to the Offering
through December 31, 2014 are as follows: |
|
|
|
Common Units |
|
|
Subordinated Units |
|
|
Total |
|
(millions, except for weighted average units and per unit data) |
|
|
|
|
|
|
|
|
|
Distributions declared(1) |
|
$ |
4.5 |
|
|
$ |
4.4 |
|
|
|
$8.9 |
|
Undistributed earnings |
|
|
0.3 |
|
|
|
0.3 |
|
|
|
0.6 |
|
Net income attributable to partners |
|
$ |
4.8 |
|
|
$ |
4.7 |
|
|
|
$9.5 |
|
Weighted average units outstanding |
|
|
31,975,079 |
|
|
|
31,972,789 |
|
|
|
|
|
Net income per limited partner unit |
|
$ |
0.15 |
|
|
$ |
0.15 |
|
|
|
|
|
(1) |
Allocation of distributions declared has been adjusted for rounding. |
NOTE 6. UNIT
ACTIVITY
Activity in number of units was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible Preferred |
|
|
Common |
|
|
|
|
|
|
|
|
|
|
|
|
Public |
|
|
Dominion |
|
|
Public |
|
|
Dominion |
|
|
Subordinated |
|
|
General Partner |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(non-economic interest) |
|
|
|
|
Balance at closing of the Offering |
|
|
|
|
|
|
|
|
|
|
20,125,000 |
|
|
|
11,847,789 |
|
|
|
31,972,789 |
|
|
|
|
|
|
|
63,945,578 |
|
Unit-based compensation |
|
|
|
|
|
|
|
|
|
|
2,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,322 |
|
Balance at December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
20,127,322 |
|
|
|
11,847,789 |
|
|
|
31,972,789 |
|
|
|
|
|
|
|
63,947,900 |
|
Unit-based compensation |
|
|
|
|
|
|
|
|
|
|
5,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,055 |
|
Units issued in connection with the DCG Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,112,139 |
|
|
|
|
|
|
|
|
|
|
|
5,112,139 |
|
Units issued in connection with the acquisition of a noncontrolling partnership interest in Iroquois |
|
|
|
|
|
|
|
|
|
|
8,622,305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,622,305 |
|
Dominion purchase of common units(1) |
|
|
|
|
|
|
|
|
|
|
(886,744 |
) |
|
|
886,744 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2015 |
|
|
|
|
|
|
|
|
|
|
27,867,938 |
|
|
|
17,846,672 |
|
|
|
31,972,789 |
|
|
|
|
|
|
|
77,687,399 |
|
Unit-based compensation |
|
|
|
|
|
|
|
|
|
|
8,579 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,579 |
|
Dominion purchase of common units(1) |
|
|
|
|
|
|
|
|
|
|
(657,956 |
) |
|
|
657,956 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Units issued in connection with the Questar Pipeline
Acquisition(2) |
|
|
18,942,714 |
|
|
|
11,365,628 |
|
|
|
21,515,634 |
|
|
|
6,656,839 |
|
|
|
|
|
|
|
|
|
|
|
58,480,815 |
|
Repurchase of common units(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,656,839 |
) |
|
|
|
|
|
|
|
|
|
|
(6,656,839 |
) |
Balance at December 31, 2016 |
|
|
18,942,714 |
|
|
|
11,365,628 |
|
|
|
48,734,195 |
|
|
|
18,504,628 |
|
|
|
31,972,789 |
|
|
|
|
|
|
|
129,519,954 |
|
(1) |
These units were purchased by Dominion as part of Dominions program initiated in September 2015, which expired in September 2016, to purchase from the market up to $50.0 million of common units
representing limited partner interests in Dominion Midstream at the discretion of Dominions management. |
(2) |
These transactions occurred in conjunction with the Questar Pipeline Acquisition, and are discussed further in Note 4. |
NOTE 7. OPERATING REVENUE
Operating revenue consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Gas transportation and storage |
|
$ |
400.2 |
|
|
$ |
310.4 |
|
|
$ |
257.2 |
|
Regulated gas sales |
|
|
6.4 |
|
|
|
|
|
|
|
|
|
Other |
|
|
34.7 |
|
|
|
59.2 |
|
|
|
56.1 |
|
Total operating revenue |
|
$ |
441.3 |
|
|
$ |
369.6 |
|
|
$ |
313.3 |
|
NOTE 8. EQUITY METHOD INVESTMENTS
At December 31, 2016, Dominion Midstream used the equity method to account for its 25.93% noncontrolling partnership interest in Iroquois and its 50%
noncontrolling partnership interest in White River Hub. See further discussion of Iroquois in Notes 1 and 14. White River Hub is a FERC-regulated transporter of natural gas with facilities that connect with six interstate
pipeline systems and a major processing plant in Colorado. The table below summarizes distributions received and income earned from Dominion Midstreams equity method investees and the
carrying amount of the investments at December 31, 2016 and 2015, as applicable.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
(in millions) |
|
Iroquois |
|
|
White River Hub |
|
|
Iroquois |
|
Distributions received |
|
$ |
23.3 |
|
|
$ |
1.8 |
|
|
$ |
2.6 |
|
Income from equity method investees |
|
|
21.9 |
|
|
|
1.1 |
|
|
|
6.6 |
|
Carrying amount of investment |
|
|
218.7 |
|
|
|
39.1 |
|
|
|
220.5 |
|
Excess of investment over Dominion Midstreams share of
underlying equity in net assets(1) |
|
|
122.9 |
|
|
|
16.1 |
|
|
|
122.9 |
|
(1) |
The difference between the carrying value of Dominion Midstreams equity method investments and its share in the underlying equity of its share in net assets reflects equity method goodwill and is not being
amortized. |
Summarized financial information provided to us by Iroquois for 100% of Iroquois at December 31, 2016 and 2015,
for the year ended December 31, 2016 and for the period from September 29, 2015 through December 31, 2015 is presented below.
|
|
|
|
|
|
|
|
|
(in millions) |
|
At December 31, 2016 |
|
|
At December 31, 2015 |
|
Current assets |
|
$ |
120.1 |
|
|
$ |
109.7 |
|
Noncurrent assets |
|
|
610.6 |
|
|
|
630.3 |
|
Current liabilities |
|
|
23.9 |
|
|
|
23.3 |
|
Noncurrent liabilities |
|
|
335.0 |
|
|
|
340.9 |
|
|
|
|
|
|
|
|
|
|
(in millions) |
|
Year ended
December 31, 2016 |
|
|
Period ended December 31, 2015 |
|
Revenues |
|
$ |
195.2 |
|
|
$ |
49.7 |
|
Operating income |
|
|
102.9 |
|
|
|
26.0 |
|
Net income |
|
|
86.1 |
|
|
|
22.0 |
|
Summarized financial information provided to us by White River Hub for 100% of White River Hub from September 16, 2016,
the inception date of common control for Questar Pipeline as described in Note 4, through December 31, 2016 is presented below.
|
|
|
|
|
(in millions) |
|
At December 31, 2016 |
|
Current assets |
|
$ |
2.9 |
|
Noncurrent assets |
|
|
44.0 |
|
Current liabilities |
|
|
0.7 |
|
Noncurrent liabilities |
|
|
0.2 |
|
|
|
|
|
|
(in millions) |
|
Period Ended December 31, 2016 |
|
Revenues |
|
$ |
2.8 |
|
Operating income |
|
|
2.2 |
|
Net income |
|
|
2.0 |
|
NOTE 9. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment and their respective balances for Dominion Midstream are as follows:
|
|
|
|
|
|
|
|
|
At December 31, |
|
2016 |
|
|
2015 |
|
(millions) |
|
|
|
|
|
|
Storage |
|
$ |
1,189.1 |
|
|
$ |
875.9 |
|
Transmission |
|
|
2,212.9 |
|
|
|
695.0 |
|
Gas gathering and processing |
|
|
17.4 |
|
|
|
|
|
General and other |
|
|
83.9 |
|
|
|
38.5 |
|
Plant under construction |
|
|
3,408.1 |
|
|
|
2,236.3 |
|
Total property, plant and equipment |
|
$ |
6,911.4 |
|
|
$ |
3,845.7 |
|
NOTE 10. GOODWILL AND INTANGIBLE ASSETS
Goodwill
The changes in Dominion Midstreams carrying amount
and segment allocation of goodwill are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dominion Energy |
|
|
Corporate and Other |
|
|
Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
Balance at December 31, 2014(1) |
|
$ |
45.9 |
|
|
$ |
|
|
|
$ |
45.9 |
|
DCG Acquisition |
|
|
249.6 |
|
|
|
|
|
|
|
249.6 |
|
Balance at December 31, 2015(1) |
|
$ |
295.5 |
|
|
$ |
|
|
|
$ |
295.5 |
|
Questar Pipeline Acquisition |
|
|
523.7 |
|
|
|
|
|
|
|
523.7 |
|
Balance at December 31, 2016(1) |
|
$ |
819.2 |
|
|
$ |
|
|
|
$ |
819.2 |
|
(1) |
There are no accumulated impairment losses.
|
Other Intangible Assets
Dominion Midstreams other intangible assets are subject to amortization over their estimated useful lives. Dominion Midstreams amortization
expense for intangible assets was $2.2 million, $2.1 million and $0.6 million in 2016, 2015 and 2014, respectively. The increase in intangible assets in 2016 is primarily due to software acquired in the Questar Pipeline Acquisition.
The acquired intangible assets have an estimated weighted-average amortization period of approximately five years. The components of intangible assets are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
2016 |
|
|
2015 |
|
|
|
Gross
Carrying Amount |
|
|
Accumulated
Amortization |
|
|
Gross
Carrying Amount |
|
|
Accumulated
Amortization |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Software |
|
$ |
34.5 |
|
|
$ |
26.8 |
|
|
$ |
17.4 |
|
|
$ |
12.8 |
|
Licenses |
|
|
11.0 |
|
|
|
3.6 |
|
|
|
11.0 |
|
|
|
3.3 |
|
Other |
|
|
4.9 |
|
|
|
2.4 |
|
|
|
14.0 |
|
|
|
10.5 |
|
Total |
|
$ |
50.4 |
|
|
$ |
32.8 |
|
|
$ |
42.4 |
|
|
$ |
26.6 |
|
Annual amortization expense for these intangible assets is estimated to be as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
2020 |
|
|
2021 |
|
(millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2.0 |
|
|
$ |
1.8 |
|
|
$ |
1.6 |
|
|
$ |
0.7 |
|
|
$ |
0.6 |
|
NOTE 11. REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities include the following:
|
|
|
|
|
|
|
|
|
At December 31, |
|
2016 |
|
|
2015 |
|
(millions) |
|
|
|
|
|
|
Regulatory assets: |
|
|
|
|
|
|
|
|
Unrecovered gas costs(1) |
|
$ |
3.3 |
|
|
$ |
1.4 |
|
Interest rate hedges(2) |
|
|
0.6 |
|
|
|
|
|
Other |
|
|
1.2 |
|
|
|
0.3 |
|
Regulatory assets-current |
|
|
5.1 |
|
|
|
1.7 |
|
Income taxes recoverable through future
rates(3) |
|
|
3.6 |
|
|
|
2.5 |
|
Interest rate hedges(2) |
|
|
34.0 |
|
|
|
|
|
Cost of reacquired debt(4) |
|
|
1.5 |
|
|
|
|
|
Other |
|
|
1.1 |
|
|
|
|
|
Regulatory assets-non-current |
|
|
40.2 |
|
|
|
2.5 |
|
Total regulatory assets |
|
$ |
45.3 |
|
|
$ |
4.2 |
|
Regulatory liabilities: |
|
|
|
|
|
|
|
|
Overrecovered gas costs(1) |
|
$ |
0.4 |
|
|
$ |
0.1 |
|
LNG cargo obligations(5) |
|
|
3.2 |
|
|
|
3.0 |
|
Customer bankruptcy settlement(6) |
|
|
2.8 |
|
|
|
3.1 |
|
Other |
|
|
1.1 |
|
|
|
0.5 |
|
Regulatory liabilities-current |
|
|
7.5 |
|
|
|
6.7 |
|
Provision for future cost of removal and
AROs(7) |
|
|
100.0 |
|
|
|
45.7 |
|
Unrecognized other postretirement benefit
costs(8) |
|
|
11.1 |
|
|
|
|
|
Customer bankruptcy settlement(6) |
|
|
17.6 |
|
|
|
20.5 |
|
Other |
|
|
0.4 |
|
|
|
0.5 |
|
Regulatory liabilities-non-current |
|
|
129.1 |
|
|
|
66.7 |
|
Total regulatory liabilities |
|
$ |
136.6 |
|
|
$ |
73.4 |
|
(1) |
Reflects unrecovered/overrecovered gas costs, which are subject to annual filings with FERC. |
(2) |
Reflects interest rate cash flow hedges recoverable from customers. Questar Pipeline entered into forward
starting swaps totaling $150.0 million |
Notes to Consolidated Financial Statements, Continued
|
in the second and third quarters of 2011 in anticipation of issuing $180.0 million of notes in December 2011. Settlement of these swaps required payments of $37.3 million in the fourth
quarter of 2011 because of declines in interest rates. These swaps qualified as cash flow hedges and the settlement payments are being amortized to interest expense over the 30-year life of the debt.
|
(3) |
Amounts to be recovered through future rates to pay income taxes that become payable by unitholders when rate revenue is provided to recover AFUDC-equity when such amounts are recovered through book depreciation.
|
(4) |
Represents charges incurred on the reacquisition of debt by Questar Pipeline that are deferred and amortized as interest expense over the would-be remaining life of the
reacquired debt. The reacquired debt costs had a weighted-average life of approximately 4.0 years at December 31, 2016. |
(5) |
Reflects obligations to the Import Shippers for LNG cargo received. See Note 12 for further information. |
(6) |
Represents the balance of proceeds from the monetization of a bankruptcy claim acquired as part of the DCG Acquisition, which is being amortized into operating revenue through February 2024. |
(7) |
Rates charged to customers include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement. |
(8) |
Reflects a regulatory liability for the collection of postretirement medical costs allowed in rates in excess of expenses incurred at Questar Pipeline. |
At December 31, 2016 and 2015, approximately $39.0 million and $1.7 million, respectively, of regulatory assets represented past
expenditures on which Dominion Midstream does not currently earn a return. With the exception of regulatory assets related to interest rate hedges, these expenditures are expected to be recovered within two years.
NOTE 12. REGULATORY MATTERS
FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the NGA and the Natural Gas Policy Act of 1978, as amended.
Under the NGA, FERC has authority over rates, terms and conditions of services performed by Cove Point, DCG and Questar Pipeline. FERC also has jurisdiction over siting, construction and operation of natural gas import and export facilities and
interstate natural gas pipeline facilities.
In November 2016, pursuant to the terms of a previous settlement, Cove Point filed a general
rate case for its FERC-jurisdictional services, with 23 proposed rates to be effective January 1, 2017. Cove Point proposed an annual cost-of-service of approximately $140 million. In December 2016, FERC accepted a January 1, 2017
effective date for all proposed rates but five which were suspended to be effective June 1, 2017. This case is pending.
In April
2013, Cove Point filed its application with FERC requesting authorization to construct, modify and operate the Liquefaction Project, as well as enhance the Cove Point Pipeline. In May 2014, FERC staff issued its EA for the Liquefaction Project. In
the EA, FERC staff addressed a variety of topics related to the proposed construction and development of the Liquefaction Project and its potential impact to the environment, including in the areas of geology, soils, groundwater, surface waters,
wetlands, vegetation, wildlife and aquatic resources, special status species, land use, recreation, socioeconomics, air quality and noise, reliability and safety, and cumulative impacts. Based on the analysis in the EA, FERC staff determined that
with the implementation of appropriate mitigation measures in these areas, the Liquefaction Project can be built and operated safely with no significant impact to the environment. In September 2014, the FERC Order was issued authorizing the
Liquefaction Project. In October 2014,
several parties filed a motion with FERC to stay the FERC Order and requested rehearing. In May 2015, FERC denied rehearing and the request for stay.
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
have been 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 partys petition for review of the FERC
Order authorizing the Liquefaction Project. The court also issued a decision remanding the other partys petition for review of the FERC Order to FERC for further explanation of how FERCs decision that a previous transaction with an
existing import shipper was not unduly discriminatory. Cove Point believes that on remand FERC will be able to justify its decision. This case is pending.
Prior to importing or exporting LNG, Cove Point must receive approvals from the DOE. In September 2013, the DOE granted Non-FTA Authorization approval for the export of up to 0.77 bcfe/day of natural gas to countries that do not have a free trade agreement 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 2014, DCG executed three binding precedent
agreements for the approximately $120 million Charleston Project. In February 2017, DCG received FERC authorization to construct and operate the project facilities, which are expected to be placed into service in the fourth quarter of 2017.
In 2015, Cove Point executed binding agreements for the approximately $150 million Eastern Market Access Project. In November 2016,
Cove Point filed an application to request FERC authorization to construct and operate the project facilities which are expected to be placed into service in late 2018.
NOTE 13. ASSET
RETIREMENT OBLIGATIONS
AROs represent obligations that result from laws, statutes, contracts and regulations related to
the eventual retirement of certain of Dominion Midstreams long-lived assets. Dominion Midstreams AROs primarily represent the cost associated with the legal obligation to cap and purge underground transmission pipe and the interim
retirement of natural gas transmission pipeline components.
The changes to AROs during 2015 and 2016 are as follows:
|
|
|
|
|
|
|
Amount |
|
(millions) |
|
|
|
AROs at December 31, 2014 |
|
$ |
0.4 |
|
DCG Acquisition |
|
|
12.6 |
|
Obligations settled during the period |
|
|
(1.8 |
) |
Revisions in estimated cash flows |
|
|
1.7 |
|
Accretion |
|
|
0.6 |
|
AROs at December 31, 2015(1) |
|
$ |
13.5 |
|
Questar Pipeline Acquisition |
|
|
16.5 |
|
Obligations settled during the period |
|
|
(0.7 |
) |
Revisions in estimated cash flows |
|
|
|
|
Accretion |
|
|
0.9 |
|
AROs at December 31, 2016(1) |
|
$ |
30.2 |
|
(1) |
Includes $0.5 million and $0.9 million reported in other current liabilities at December 31, 2015 and 2016, respectively.
|
Under the terms of the 2005 Agreement, Cove Point would be responsible for certain onshore and
offshore site restoration activities at the Cove Point site only if it voluntarily tenders title according to the terms of this agreement. As Cove Point is permitted to operate the Cove Point LNG Facility for an indefinite time period and currently
has no plans to voluntarily tender title, Cove Point does not have sufficient information to determine a reasonable range of settlement dates for decommissioning and therefore has not recorded an ARO.
Dominion Midstream has also identified, but not recognized, AROs related to the retirement of Questar Pipelines storage wells in its
underground natural gas storage network as it currently does not have sufficient information to estimate a reasonable range of expected retirement dates for these assets since the economic lives of these assets can be extended indefinitely through
regular repair and maintenance. Dominion Midstream currently does not have any plans to retire or dispose of these assets. As a result, a settlement date is not determinable for these assets and AROs will not be reflected in the Consolidated
Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. Dominion Midstream continues to monitor operational and strategic developments to identify if
sufficient information exists to reasonably estimate a retirement date for these assets.
NOTE 14. VARIABLE
INTEREST ENTITIES
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain
information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both: (1) the power to direct the activities that most significantly impact the entitys economic performance and
(2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
Cove Point
Dominion Midstream concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Dominion
Midstream is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
Iroquois
Dominion Midstream previously concluded that Iroquois was
a VIE because a non-affiliated Iroquois equity holder had the ability during a limited period of time to transfer its ownership interests to another Iroquois equity holder or its affiliate. At the end of the
first quarter of 2016, such right no longer existed and Dominion Midstream concluded that Iroquois is no longer a VIE.
DRS, DCGS, Dominion Payroll and QPC
Services Company
In connection with the Offering, our general partner entered into a services agreement with DRS. DRS provides administrative,
management and other services to Dominion and its subsidiaries as a subsidiary service company. From time to time and at the option of our general partner, our general partner will request that DRS provide, and reimburse DRS for the cost of
providing, such administrative, management and other services as it deems necessary or appropriate for our operations. We will reimburse our general partner and its affiliates for the associated costs of
obtain-
ing these services. For the years ended December 31, 2016, 2015 and 2014, these costs were $1.2 million, $0.9 million and $0.1 million, respectively.
In connection with Dominions acquisition of DCG, DCG entered into services agreements beginning February 1, 2015 with DRS, for
similar services as described above, and with Dominion Payroll, which provides human resources and operations services to Dominion and its subsidiaries as a subsidiary service company. Effective January 1, 2016, DCGS provides these services to
Dominion Midstream with Dominion Payroll no longer providing any services to Dominion Midstream.
Additionally, in connection with
Dominion Midstreams pending acquisition of Questar Pipeline, Questar Pipeline entered into service agreements effective November 16, 2016 with QPC Services Company and transferred its employees and employee-related assets and liabilities
via an equity contribution of $37.0 million. QPC Services Company provides human resources and operations services to Dominion and its subsidiaries as a subsidiary service company.
In addition to the services purchased by our general partner, Dominion Midstream purchased shared services from DRS, DCGS and QPC Services
Company of approximately $25.4 million, $15.7 million and $2.3 million, respectively, for the year ended December 31, 2016. Dominion Midstream purchased shared services from DRS and Dominion Payroll of approximately
$15.7 million and $12.7 million, respectively, during the year ended December 31, 2015. Cove Point purchased shared services from DRS of approximately $12.2 million during the year ended December 31, 2014. The Consolidated
Balance Sheets at December 31, 2016 and 2015 include amounts due from Dominion Midstream to DRS, DCGS and QPC Services Company of approximately $6.3 million and $2.8 million, respectively.
Dominion Midstream determined that neither it nor any of its consolidated entities is the primary beneficiary of DRS, DCGS, Dominion Payroll
or QPC Services Company, as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be
significant to them. Neither Dominion Midstream nor any of its consolidated entities has any obligation to absorb more than its allocated share of DRS, DCGS, Dominion Payroll or QPC Services Company costs.
NOTE 15. LONG-TERM DEBT AND AFFILIATED
LONG-TERM DEBT
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
2016 Weighted- average Coupon(1) |
|
|
2016 |
|
|
2015 |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
Term loan, variable rate, due in 2019(2) |
|
|
2.19 |
% |
|
$ |
300.0 |
|
|
$ |
|
|
Unsecured senior and medium-term notes, 5.83% and 6.48%, due in 2018(3) |
|
|
5.84 |
|
|
|
255.0 |
|
|
|
|
|
Unsecured senior notes, 4.875%, due in 2041(3) |
|
|
4.88 |
|
|
|
180.0 |
|
|
|
|
|
Affiliated senior unsecured promissory note, 0.6%, due in 2017(4) |
|
|
0.60 |
|
|
|
|
|
|
|
300.8 |
|
Total principal |
|
|
|
|
|
|
735.0 |
|
|
|
300.8 |
|
Unamortized debt issuance costs |
|
|
|
|
|
|
(5.1 |
) |
|
|
|
|
Total long-term debt and affiliated long-term debt |
|
|
|
|
|
$ |
729.9 |
|
|
$ |
300.8 |
|
Notes to Consolidated Financial Statements, Continued
(1) |
Represents weighted-average coupon rates for debt outstanding at December 31, 2016. |
(2) |
Secured by a guarantee provided by Dominion. |
(3) |
Represents debt acquired by Dominion Midstream as a result of the Questar Pipeline Acquisition. |
(4) |
Dominion Midstream repaid this note in December 2016 in connection with the Questar Pipeline Acquisition. See Note 4 for further information. |
Based on stated maturity dates, the scheduled principal payments of long-term debt at December 31, 2016, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
2020 |
|
|
2021 |
|
|
Thereafter |
|
|
Total |
|
(millions, except percentages) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Term loan |
|
$ |
|
|
|
$ |
|
|
|
$ |
300.0 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
300.0 |
|
Unsecured senior and medium-term notes |
|
$ |
|
|
|
$ |
255.0 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
180.0 |
|
|
$ |
435.0 |
|
Weighted-average coupon |
|
|
|
|
|
|
5.84 |
% |
|
|
2.19 |
% |
|
|
|
|
|
|
|
|
|
|
4.88 |
% |
|
|
|
|
The debt instruments described above are reported at historical cost. At December 31, 2016 and 2015, the
fair value of Dominion Midstreams outstanding debt was $744.8 million and $282.4 million, respectively. The estimated fair value has been determined using available market information and valuation methodologies considered
appropriate by management. The fair value was calculated using market interest rates currently available for issuance of debt with similar terms and remaining maturities. The fair value measurement is classified as Level 2.
Covenants of Term Loan Agreement
The key terms of Dominion
Midstreams $300.0 million term loan agreement include limitations on the incurrence of additional indebtedness by Dominion Midstreams subsidiaries, a requirement that amounts due and payable under the term loan agreement be paid prior to
Dominion Midstream making any distributions to unitholders and the maintenance of a quarterly leverage ratio, defined as the ratio of debt to cash flow for the four-fiscal quarter period most recently ended, not greater than 5.0 to 1.0 (or during
the period following certain acquisitions, 5.50 to 1.0). If Dominion Midstream fails to make payments under the term loan agreement or becomes subject to bankruptcy or other insolvency proceedings, these covenants could result in the acceleration of
principal and interest payments and restrictions on distributions to unitholders.
NOTE 16. EMPLOYEE
BENEFIT PLANS
Defined Benefit Plans
Cove Point participates in retirement benefit plans sponsored by Dominion, which provide certain retirement benefits to eligible active employees, retirees
and qualifying dependents of Cove Point. Under the terms of its benefit plans, Dominion reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced
benefits.
Pension benefits for Cove Point employees are covered by the Dominion Pension Plan, a defined benefit pension plan sponsored by
Dominion that provides benefits to multiple Dominion subsidiaries. Retirement benefits payable are based primarily on years of service, age and the employees compensation. As a
participating employer, Cove Point is subject to Dominions funding policy, which is to contribute annually an amount that is in accordance with the provisions of ERISA. During 2016, Cove
Point made no contributions to the Dominion Pension Plan, and no contributions to this plan are currently expected in 2017. Net periodic pension cost related to this plan was $1.2 million, $1.4 million and $1.1 million in 2016, 2015
and 2014, respectively, recorded in other operations and maintenance expense in the Consolidated Statements of Income. The funded status of various Dominion subsidiary groups and employee compensation are the basis for determining the share of total
pension costs for participating Dominion subsidiaries. At December 31, 2016 and 2015, amounts due to Dominion associated with this plan, were $6.2 million and $5.0 million, respectively, recorded in pension and other postretirement
benefit liabilities on the Consolidated Balance Sheets.
Retiree healthcare and life insurance benefits for Cove Point employees are
covered by the Dominion Retiree Health and Welfare Plan, a plan sponsored by Dominion that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Annual employee premiums are based on several factors such
as age, retirement date and years of service. Net periodic benefit (credit) cost related to this plan was $(0.4) million for 2016, 2015 and 2014, recorded in other operations and maintenance expense in the Consolidated Statements of Income. Employee
headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion subsidiaries. At December 31, 2016 amounts owed to Dominion Midstream associated with this plan were $0.9 million, recorded
in other noncurrent assets on the Consolidated Balance Sheets. At December 31, 2015, liabilities to Dominion associated with this plan were less than $0.1 million, recorded in pension and other postretirement benefit liabilities on the
Consolidated Balance Sheets.
Dominion holds investments in trusts to fund employee benefit payments for the pension and other
postretirement benefit plans in which Cove Points employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included
in the determination of the amount of cash that Cove Point will provide to Dominion for its share of employee benefit plan contributions.
Defined Contribution
Plans
Cove Point also participates in Dominion-sponsored defined contribution employee savings plans that cover multiple Dominion subsidiaries. Cove
Point recognized $0.4 million, $0.3 million and $0.2 million of expense in other operations and maintenance expense in the Consolidated Statements of Income in 2016, 2015 and 2014, respectively, as employer matching contributions to
these plans.
NOTE 17. CPCN OBLIGATION
In April 2013, Cove Point filed an application with the Maryland Commission requesting authorization to construct a generating station in connection with the
Liquefaction Project. In May 2014, the Maryland Commission granted the CPCN authorizing the construction of such generating station. The CPCN obligates
Cove Point to make payments totaling approximately $48.0 million. These payments consist of $40.0 million to the SEIF over a five-year period beginning in 2015 and $8.0 million to
Maryland low income energy assistance programs over a twenty-year period expected to begin in 2018. In December 2014, upon receipt of applicable approvals to commence construction of the generating station, Dominion Midstream recorded the present
value of the obligation as an increase to property, plant and equipment and a corresponding liability for these future payments using an effective interest rate of 1.9%.
In June 2014, a party filed a notice of petition for judicial review of the CPCN with the Circuit Court for Baltimore City in Maryland. In
September 2014, the party filed with the Maryland Commission a motion to stay the CPCN pending judicial review of the CPCN. In December 2014, the Circuit Court issued an order affirming the Maryland Commissions grant of the CPCN and
dismissing the appeal, and the motion for stay was denied by the Maryland Commission. In January 2015, the same party filed a Notice of Appeal of the Baltimore Circuit Courts Order affirming the Maryland Commissions grant of the CPCN
with the Court of Special Appeals of Maryland. In February 2016, the Court of Special Appeals of Maryland issued an order affirming the judgment of the Circuit Court for Baltimore City in Maryland which affirmed the decision of the Maryland
Commission granting the CPCN. In December 2016, following further appeal, the Court of Appeals of Maryland issued an order affirming the judgment of the Court of Special Appeals.
NOTE 18. COMMITMENTS AND CONTINGENCIES
As a result of issues generated in the ordinary course of business, Dominion Midstream is involved in legal proceedings before various courts and is
periodically subject to governmental examinations (including by FERC), 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 Dominion Midstream to estimate a range of possible loss. For such matters that
Dominion Midstream cannot estimate, 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 Dominion Midstream is able to
estimate a range of possible loss. For legal proceedings and governmental examinations for which Dominion Midstream 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. 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 accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Any estimated range of possible loss may not represent Dominion Midstreams 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. Management does not anticipate that the liabilities, if
any, arising from such proceedings would have a material effect on Dominion Midstreams financial position, liquidity or results of operations.
Cove Point Natural Heritage Trust
Under the terms of the 2005
Agreement, Cove Point is required to make an annual contribution to the Cove Point Natural Heritage Trust, an affiliated non-profit trust focused on the preservation and protection of ecologically sensitive
sites at or near Cove Point, of $0.3 million for each year the facility is in operation. These annual payments are recorded in other operations and maintenance expense in the Consolidated Statements of Income. If Cove Point voluntarily tenders
title according to the terms of this agreement, no contributions are required. There are no current plans to voluntarily tender title to the Cove Point site.
Surety Bonds
At December 31, 2016, Dominion Midstream had
purchased $13.3 million of surety bonds including $9.8 million held by Cove Point. Under the terms of surety bonds, Dominion Midstream is obligated to indemnify the respective surety bond company for any amounts paid.
Lease Commitments
Dominion Midstream leases various facilities,
vehicles and equipment under operating lease arrangements, the majority of which include terms of one year or less, require payments on a monthly or annual basis and can be canceled at any time. Rental expense for Dominion Midstream totaled
$3.2 million, $2.8 million and $2.8 million for the years ended December 31, 2016, 2015 and 2014, respectively. The majority of rent expense is included within other operations and maintenance expense in the Consolidated
Statements of Income.
NOTE 19. CREDIT RISK
Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit
policies are maintained, including the evaluation of counterparty financial condition. In addition, counterparties may make available collateral, including letters of credit, payment guarantees, or cash deposits.
Dominion Midstream provides service to approximately 130 customers, including the Storage Customers, marketers or end users, power generators,
utilities and the Import Shippers. The two largest customers comprised approximately 57% and 71% of the total transportation and storage revenues for the years ended December 31, 2016 and 2015, respectively, with Dominion Midstreams
largest customer representing approximately 44% and 57% of such amounts during 2016 and 2015.
For the year ended December 31, 2014,
Cove Point provided service to 23 customers, including the Storage Customers, sixteen marketers or end users and the Import Shippers. The three largest customers comprised approximately 93% of the total transportation and storage revenues for the
year ended December 31, 2014. Cove Points largest customer represented approximately 72% of such amounts in 2014.
Dominion
Midstream maintains a provision for credit losses based on factors surrounding the credit risk of its customers,
his-
Notes to Consolidated Financial Statements, Continued
torical trends and other information. At December 31, 2016 and 2015, the provision for credit losses was less than $0.1 million. Management believes, based on credit policies and the
December 31, 2016 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
NOTE 20. RELATED-PARTY TRANSACTIONS
Dominion Midstream engages in related-party transactions primarily with other Dominion subsidiaries (affiliates), including our general partner. Dominion
Midstreams 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. Cove Point participates in certain Dominion benefit plans as
described in Note 16. Transactions related to the DCG Acquisition and Questar Pipeline Acquisition are described in Notes 4 and 15. A discussion of the remaining significant related party transactions follows.
Transactions with Affiliates
DRS provides accounting, legal,
finance and certain administrative and technical services to Dominion Midstream and DCGS (Dominion Payroll prior to January 1, 2016) and QPC Services Company provide human resources and operations services to Dominion Midstream. Refer to Note
14 for further information.
Dominion may seek reimbursement from DCG for costs incurred related to Dominions transition services
agreement with SCANA to provide administrative functions related to DCG. For the year ended December 31, 2016, DCG reimbursed Dominion a total of $1.5 million for such costs. Subsequent to the DCG Acquisition through December 31,
2015, DCG reimbursed Dominion a total of $2.9 million for such costs.
Dominion Midstream provides transportation and other services
to affiliates and affiliates provide goods and services to Dominion Midstream.
Affiliated transactions are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
(millions) |
|
|
|
|
|
|
|
|
|
Sales of natural gas transportation services to affiliates |
|
$ |
25.9 |
|
|
$ |
2.2 |
|
|
$ |
2.4 |
|
Services provided to affiliates |
|
|
1.1 |
|
|
|
|
|
|
|
|
|
Purchased gas from affiliates |
|
|
2.4 |
|
|
|
0.5 |
|
|
|
6.0 |
|
Goods and services provided by affiliates to Dominion Midstream(1) |
|
|
63.1 |
|
|
|
35.4 |
|
|
|
16.1 |
|
(1) |
Includes $28.3 million, $13.3 million and $6.7 million of capitalized expenditures in 2016, 2015 and 2014, respectively. |
Dominion Credit Facility
In connection with the Offering, Dominion
Midstream entered into a credit facility with Dominion with a borrowing capacity of $300 million. A summary of certain key terms of the credit facility with Dominion is as follows:
|
|
No upfront commitment fee in order to enter into the facility, and no ongoing facility or similar charges assessed against undrawn amounts. |
|
|
Five-year term, with only interest payments on any drawn amounts payable prior to maturity or acceleration.
|
|
|
Interest payments on any drawn balances are due on a quarterly basis and amounts drawn accrue interest at variable interest rates, determined based on our ratio of total debt to Adjusted EBITDA or, if we obtain
long-term debt credit ratings in the future, based on such credit ratings in effect from time to time. |
|
|
Amounts then due and payable under the credit facility will need to be satisfied prior to making any distributions to unitholders. The credit facility does not include any other financial tests, covenants or conditions
that must be satisfied as a condition to making distributions for so long as the facility remains in place. |
|
|
The credit facility contains limited representations, warranties and ongoing covenants consistent with other credit facilities made available by Dominion to certain of its other affiliates. |
|
|
In the event we breach our payment obligations under the credit facility, or our obligations under any future third-party indebtedness, or if we become subject to certain bankruptcy, insolvency, liquidation or similar
proceedings, in each case after any applicable cure periods, Dominion may accelerate our payment obligations and terminate the credit facility. |
|
|
We are required to obtain Dominions consent prior to creating any mortgage, security interest, lien or other encumbrance outside the ordinary course of business on any of our property, assets or revenues during
the term of the facility. Failure to obtain any such consent from Dominion in the future could have an adverse impact on our ability to implement our business strategies, generate revenues and pay distributions to our unitholders. |
At December 31, 2016 and 2015, $63.2 million and $5.9 million was outstanding against the credit facility, respectively. In
January and February 2017, Dominion Midstream drew an additional $11.4 million on the credit facility to fund property tax at DCG and expansion capital expenditures and repaid $11.0 million. Outstanding borrowings are presented within current
liabilities as such amounts could become payable on demand after a 90-day termination notice provided by either party. No such notice has been provided through the date of this filing. The weighted-average
interest rate of these borrowings was 2.30% and 2.28% at December 31, 2016 and 2015, respectively. Interest charges related to Dominion Midstreams borrowings against the facility were $0.4 million and $0.1 million for the years ended
December 31, 2016 and 2015.
Income Taxes
As described in
Note 21, Cove Point, DCG and Questar Pipeline participated in Dominions intercompany tax sharing agreement prior to Dominion Midstreams acquisition of the Preferred Equity Interest and non-economic
general partner interest in Cove Point and its acquisitions of DCG and Questar Pipeline.
In 2014, Cove Point settled $1.2 million of
income taxes payable prior to the Offering, and at the time of the Offering, settled $147.9 million of income taxes payable and deferred income taxes. In 2016 and 2015, Questar Pipeline and DCG settled $282.5 million and $13.4 million
of income taxes payable and deferred income taxes, respectively. These settlements are reflected as equity transactions in Dominion Midstreams Consolidated Financial Statements.
Cove Points participation in this tax sharing agreement was terminated in 2014 in connection with the Offering, and DCGs
and Questar Pipelines participation was terminated in 2015 and 2016 in connection with the DCG Acquisition and the Questar Pipeline Acquisition, respectively.
Natural Gas Imbalances
Dominion Midstream maintains natural gas
imbalances with affiliates. The imbalances with affiliates are provided below:
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
(millions) |
|
|
|
|
|
|
Imbalances payable to affiliates |
|
$ |
0.1 |
|
|
$ |
0.8 |
|
Imbalances receivable from affiliates(1) |
|
|
6.3 |
|
|
|
|
|
(1) |
Recorded in other current assets in the Consolidated Balance Sheets. |
Right of First Offer
In connection with the Offering, we entered into a right of first offer agreement with Dominion, pursuant to which Dominion agreed and caused its affiliates
to agree, for so long as Dominion or its affiliates, individually or as part of a group, control our general partner, that if Dominion or any of its affiliates decide to attempt to sell (other than to another affiliate of Dominion) the ROFO Assets,
Dominion or its affiliate will notify us of its desire to sell such ROFO Assets and, prior to selling such ROFO Assets to a third-party, will negotiate with us exclusively and in good faith for a period of 30 days in order to give us an opportunity
to enter into definitive documentation for the purchase and sale of such ROFO Assets on terms that are mutually acceptable to Dominion or its affiliate and us. If we and Dominion or its affiliate have not entered into a letter of intent or a
definitive purchase and sale agreement with respect to such ROFO Assets within such 30-day period, or if any such letter of intent or agreement is entered into but subsequently terminated, Dominion or its
affiliate may, at any time during the succeeding 150 day period, enter into a definitive transfer agreement with any third party with respect to such ROFO Assets on terms and conditions that, when taken as a whole, are superior, in the good faith
determination of Dominion or its affiliate, to those set forth in the last written offer we had proposed during negotiations with Dominion or its affiliate, and Dominion or its affiliate has the right to sell such ROFO Assets pursuant to such
transfer agreement.
Contributions from Dominion
In 2014,
prior to the Offering, Dominion contributed $238.7 million to Cove Point. For the years ended December 31, 2016 and 2015, Dominion contributed $1.1 billion and $941.2 million, respectively, to Cove Point. In January and February
2017, Dominion contributed a total of $253.1 million to Cove Point. These contributions from Dominion to Cove Point represent funding for capital expenditures related to the Liquefaction Project. In November 2016, Dominion contributed
$1.0 million in cash to Questar Pipeline to fund operations. In February 2015, Dominion contributed $1.3 million in cash to DCG to fund operations.
NOTE 21. INCOME
TAXES
Dominion Midstream is organized as an MLP, a pass-through entity for U.S. federal and state income tax purposes. Each unitholder
is responsible for taking into account the unitholders respective share of Dominion Midstreams items of taxable
income, gain, loss and deduction in the preparation of income tax returns. Upon the closing of the Offering, Cove Point became a pass-through entity for U.S. federal and state income tax
purposes. Effective April 1, 2015, the date of the DCG Acquisition, DCG is treated as a component of Dominion Midstream for income tax purposes. Effective December 1, 2016, the date of the Questar Pipeline Acquisition, Questar Pipeline is
treated as a component of Dominion Midstream for income tax purposes. Accordingly, Dominion Midstreams Consolidated Financial Statements do not include income taxes for the period subsequent to the Offering, with the exception of income taxes
attributable to the DCG Predecessor and Questar Pipeline Predecessor.
Prior to the completion of the Offering, Cove Point was not treated
as a partnership for U.S. federal and state income tax purposes. Its business activities were included in the consolidated U.S. federal and certain state income tax returns of Dominion or DCPI. DCG operated as a taxable corporation at the time of
Dominions acquisition of DCG. In March 2015, DCG converted to a single member limited liability company and as a result, became a disregarded entity for income tax purposes and was treated as a taxable division of its corporate parent. Its
business activities from the time of Dominions acquisition of DCG through March 2015, were included in the consolidated U.S. federal and certain state income tax returns of Dominion for 2015. Questar Pipeline is a disregarded entity for
income tax purposes and was treated as a taxable division of its corporate parent. Its business activities from the time of Dominions acquisition of Dominion Questar through November 2016 will be included in the consolidated U.S. federal and
certain state income tax returns of Dominion. Dominion Midstreams Consolidated Financial Statements reflect income taxes for the same period. For periods prior to Dominions acquisition of Dominion Questar in September 2016, Questar
Pipeline was included in the consolidated federal and certain state tax returns of its parent, Dominion Questar.
Current income taxes for
Cove Point, DCG and Questar Pipeline were based on taxable income or loss, determined on a separate company basis, and, where applicable, settled in accordance with the principles of Dominions intercompany tax sharing agreement. The
settlements of Cove Points, DCGs and Questar Pipelines federal and state income taxes payable and net deferred income taxes are reflected as equity transactions in Dominion Midstreams Consolidated Financial Statements.
The income tax (benefit) provision is summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016(1) |
|
|
2015(2) |
|
|
2014(3) |
|
(millions) |
|
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
7.2 |
|
|
$ |
0.5 |
|
|
$ |
33.6 |
|
State |
|
|
0.6 |
|
|
|
0.1 |
|
|
|
5.1 |
|
Total current expense |
|
|
7.8 |
|
|
|
0.6 |
|
|
|
38.7 |
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
(1.3 |
) |
|
|
1.3 |
|
|
|
9.9 |
|
State |
|
|
(0.2 |
) |
|
|
0.2 |
|
|
|
3.2 |
|
Total deferred expense |
|
|
(1.5 |
) |
|
|
1.5 |
|
|
|
13.1 |
|
Total income tax expense |
|
$ |
6.3 |
|
|
$ |
2.1 |
|
|
$ |
51.8 |
|
(1) |
2016 income taxes are attributable to the Questar Pipeline Predecessor. |
(2) |
2015 income taxes are attributable to the DCG Predecessor. |
(3) |
Income taxes recognized prior to the Offering. |
Notes to Consolidated Financial Statements, Continued
The statutory U.S. federal income tax rate reconciles to the effective income tax rate as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2016 |
|
|
2015 |
|
|
2014 |
|
U.S. statutory rate |
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
Partnership income not subject to income
taxes(1) |
|
|
(32.4 |
) |
|
|
(34.1 |
) |
|
|
(5.8 |
) |
Increases resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
State taxes, net of federal benefit |
|
|
0.1 |
|
|
|
0.1 |
|
|
|
3.4 |
|
Other, net |
|
|
|
|
|
|
|
|
|
|
0.1 |
|
Effective tax rate |
|
|
2.7 |
% |
|
|
1.0 |
% |
|
|
32.7 |
% |
(1) |
Reflects the pass-through entity status of Dominion Midstream, including the operations of Questar Pipeline subsequent to the Questar Pipeline Acquisition, DCG subsequent to the DCG Acquisition and Cove Point.
|
In 2016 and 2015, there were no unrecognized tax benefits, and amounts for 2014 were immaterial.
Effective for its 2014 tax year, Dominion was accepted into the CAP. Through the CAP, Dominion has the opportunity to resolve complex tax
matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions agreed to by the IRS. The IRS has completed its audit of Dominions consolidated federal tax returns for tax years
2013, 2014, and 2015, for which the statute of limitations has not yet expired. Although Dominion has not received a final letter indicating no changes to its taxable income for tax year 2015, no adjustments are expected. The IRS examination of tax
year 2016 is ongoing. For Dominion Questar and its consolidated subsidiaries which also participate in a CAP maintenance program, the IRS has completed its examination of tax years through 2015. For Dominion Questars consolidated returns, the
statute of limitations has expired for tax years prior to 2013.
For Cove Point, the earliest tax year remaining open for examination by
Maryland tax authorities is 2013. Since DCG was included in SCANAs consolidated South Carolina tax returns for periods prior to being acquired by Dominion in January 2015, SCANA is obligated for any additional taxes assessed for those periods.
Questar Pipeline was included in Dominion Questars consolidated Utah and Colorado returns for periods prior to Dominions acquisition of Dominion Questar and will be included in Dominions consolidated Utah and Colorado returns for
tax year 2016. The earliest year open for examination of both Dominion Questars consolidated Utah and Colorado returns is 2013.
Dominion will pay any additional income taxes assessed by tax authorities related to Questar Pipelines business activities for periods
prior to December 1, 2016, DCGs business activities during the period January 31, 2015 through March 31, 2015, and Cove Points business activities occurring prior to October 20, 2014.
NOTE 22. UNIT-BASED COMPENSATION
In October 2014, the Board of Directors of our general partner adopted the Dominion Midstream LTIP. Awards under the Dominion Midstream LTIP are available for
directors of our general partner and employees and consultants of our general partner and any of its affiliates, including Dominion, who perform services for us. The Dominion Midstream LTIP authorizes the grant, from time to time, at the discretion
of the Board of
Directors of our general partner or a committee thereof, of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards,
substitute awards, unrestricted unit awards and cash awards. No more than 3,000,000 of our common units will be available for delivery under the Dominion Midstream LTIP. The common units to be delivered under the Dominion Midstream LTIP will
consist, in whole or in part, of common units acquired in the open market or from any affiliate or any other person, newly issued common units or any combination of the foregoing as determined by the Board of Directors of our general partner or a
committee thereof.
The following table depicts the issuance of common units to non-employee
directors of the general partner of Dominion Midstream as part of the annual equity retainer granted under the Dominion Midstream LTIP.
|
|
|
|
|
Issuance Date |
|
Common Units Issued |
|
October 2014 |
|
|
2,322 |
|
January 2015 |
|
|
5,055 |
|
January 2016 |
|
|
7,761 |
|
October 2016 |
|
|
818 |
|
January 2017 |
|
|
10,740 |
|
February 2017 |
|
|
2,389 |
|
For the years ended December 31, 2016, 2015 and 2014, $0.3 million, $0.2 million and
$0.1 million, respectively, of expense was recognized within other operations and maintenance expense in the Consolidated Statements of Income.
NOTE 23. OPERATING
SEGMENT
Dominion Midstream is organized primarily on the basis of products and services sold in the U.S. Dominion Energy, Dominion
Midstreams operating segment, consists of gas transportation, LNG import and storage.
Dominion Midstream also reports a Corporate
and Other segment. The Corporate and Other segment primarily includes items attributable to Dominion Midstreams operating segment that are not included in profit measures evaluated by executive management in assessing the segments
performance or in allocating resources among the segments. In 2016, expenses of $7.9 million ($6.9 million after tax) were recorded related to certain transaction and transition costs associated with the Questar Pipeline Acquisition. Additionally,
$1.6 million of such costs were incurred by our general partner in 2016, for which Dominion did not seek reimbursement. In 2015, expenses of $1.7 million were recorded related to certain transition costs associated with the DCG Acquisition.
There were no such items in 2014.
The following table presents segment information pertaining to Dominion Midstreams
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Dominion Energy |
|
|
Corporate and
Other |
|
|
Consolidated Total |
|
(millions) |
|
|
|
|
|
|
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
441.3 |
|
|
$ |
|
|
|
$ |
441.3 |
|
Depreciation and amortization |
|
|
56.6 |
|
|
|
|
|
|
|
56.6 |
|
Earnings from equity method investees |
|
|
23.0 |
|
|
|
|
|
|
|
23.0 |
|
Interest and related charges |
|
|
7.3 |
|
|
|
|
|
|
|
7.3 |
|
Income tax expense |
|
|
7.3 |
|
|
|
(1.0 |
) |
|
|
6.3 |
|
Net income (loss) including noncontrolling interest and Questar Pipeline Predecessor |
|
|
238.2 |
|
|
|
(8.5 |
) |
|
|
229.7 |
|
Net income (loss) including noncontrolling interest |
|
|
225.8 |
|
|
|
(1.6 |
) |
|
|
224.2 |
|
Net income (loss) attributable to partners |
|
|
108.0 |
|
|
|
(1.6 |
) |
|
|
106.4 |
|
Investment in equity method affiliates |
|
|
257.8 |
|
|
|
|
|
|
|
257.8 |
|
Capital expenditures |
|
|
1,276.8 |
|
|
|
|
|
|
|
1,276.8 |
|
Total assets at December 31 |
|
|
7,186.9 |
|
|
|
|
|
|
|
7,186.9 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
369.6 |
|
|
$ |
|
|
|
$ |
369.6 |
|
Depreciation and amortization |
|
|
40.4 |
|
|
|
|
|
|
|
40.4 |
|
Earnings from equity method investee |
|
|
6.6 |
|
|
|
|
|
|
|
6.6 |
|
Interest and related charges |
|
|
0.6 |
|
|
|
|
|
|
|
0.6 |
|
Income tax expense |
|
|
2.1 |
|
|
|
|
|
|
|
2.1 |
|
Net income (loss) including noncontrolling interest and DCG Predecessor |
|
|
198.2 |
|
|
|
(1.7 |
) |
|
|
196.5 |
|
Net income (loss) including noncontrolling interest |
|
|
194.9 |
|
|
|
(0.7 |
) |
|
|
194.2 |
|
Net income (loss) attributable to partners |
|
|
73.2 |
|
|
|
(0.7 |
) |
|
|
72.5 |
|
Investment in equity method affiliate |
|
|
220.5 |
|
|
|
|
|
|
|
220.5 |
|
Capital expenditures |
|
|
1,282.1 |
|
|
|
|
|
|
|
1,282.1 |
|
Total assets at December 31 |
|
|
4,125.2 |
|
|
|
|
|
|
|
4,125.2 |
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
313.3 |
|
|
$ |
|
|
|
$ |
313.3 |
|
Depreciation and amortization |
|
|
37.7 |
|
|
|
|
|
|
|
37.7 |
|
Interest and related charges |
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
|
|
51.8 |
|
|
|
|
|
|
|
51.8 |
|
Net income including noncontrolling interest |
|
|
106.9 |
|
|
|
|
|
|
|
106.9 |
|
Net income including noncontrolling interest subsequent to initial public offering |
|
|
26.3 |
|
|
|
|
|
|
|
26.3 |
|
Net income attributable to limited partners subsequent to initial public offering |
|
|
9.5 |
|
|
|
|
|
|
|
9.5 |
|
Capital expenditures |
|
|
572.2 |
|
|
|
|
|
|
|
572.2 |
|
NOTE 24. QUARTERLY FINANCIAL AND PER UNIT DATA
(UNAUDITED)
A summary of Dominion Midstreams quarterly results of operations for the years ended December 31, 2016 and 2015
follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
|
Second Quarter |
|
|
Third Quarter(1) |
|
|
Fourth Quarter |
|
|
Full Year |
|
(millions, except per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
83.0 |
|
|
$ |
85.6 |
|
|
$ |
95.2 |
|
|
$ |
177.5 |
|
|
$ |
441.3 |
|
Income from operations |
|
|
44.8 |
|
|
|
48.5 |
|
|
|
46.5 |
|
|
|
77.3 |
|
|
|
217.1 |
|
Net income including noncontrolling interest and predecessors |
|
|
51.8 |
|
|
|
53.1 |
|
|
|
50.2 |
|
|
|
74.6 |
|
|
|
229.7 |
|
Net income including noncontrolling interest |
|
|
51.8 |
|
|
|
53.1 |
|
|
|
53.4 |
|
|
|
65.9 |
|
|
|
224.2 |
|
Net income attributable to partners |
|
|
23.1 |
|
|
|
22.5 |
|
|
|
24.3 |
|
|
|
36.5 |
|
|
|
106.4 |
|
Net income per limited partner unit (basic and diluted) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Units |
|
$ |
0.29 |
|
|
$ |
0.28 |
|
|
$ |
0.30 |
|
|
$ |
0.38 |
|
|
$ |
1.30 |
|
Subordinated Units |
|
|
0.29 |
|
|
|
0.28 |
|
|
|
0.30 |
|
|
|
0.34 |
|
|
|
1.17 |
|
Unit prices (intraday
high-low) |
|
$ |
35.88 - 23.12 |
|
|
$ |
34.47 - 25.25 |
|
|
$ |
28.92 - 23.17 |
|
|
$ |
29.75 - 23.20 |
|
|
$ |
35.88 - 23.12 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
78.4 |
|
|
$ |
105.4 |
|
|
$ |
103.1 |
|
|
$ |
82.7 |
|
|
$ |
369.6 |
|
Income from operations |
|
|
44.7 |
|
|
|
47.2 |
|
|
|
48.7 |
|
|
|
51.0 |
|
|
|
191.6 |
|
Net income including noncontrolling interest and DCG Predecessor |
|
|
42.8 |
|
|
|
47.2 |
|
|
|
48.8 |
|
|
|
57.7 |
|
|
|
196.5 |
|
Net income including noncontrolling interest |
|
|
40.5 |
|
|
|
47.2 |
|
|
|
48.8 |
|
|
|
57.7 |
|
|
|
194.2 |
|
Net income attributable to partners |
|
|
11.8 |
|
|
|
17.6 |
|
|
|
18.0 |
|
|
|
25.1 |
|
|
|
72.5 |
|
Net income per limited partner unit (basic and diluted) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Units |
|
$ |
0.19 |
|
|
$ |
0.26 |
|
|
$ |
0.28 |
|
|
$ |
0.32 |
|
|
$ |
1.08 |
|
Subordinated Units |
|
|
0.19 |
|
|
|
0.26 |
|
|
|
0.24 |
|
|
|
0.32 |
|
|
|
1.00 |
|
Unit prices (intraday
high-low) |
|
$ |
42.31 - 33.16 |
|
|
$ |
44.34 - 36.90 |
|
|
$ |
39.63 - 24.50 |
|
|
$ |
34.86 - 25.64 |
|
|
$ |
44.34 - 24.50 |
|
(1) |
The third quarter of 2016 has been recast to give effect to the Questar Pipeline Acquisition beginning on September 16, 2016, the date of Dominions acquisition of Dominion Questar and the inception date of
common control. Prior to the Questar Pipeline Acquisition, Dominion Midstreams third quarter operating revenues, income from operations and net income including noncontrolling interest and predecessors were $85.0 million,
$47.7 million and $53.4 million, respectively. |
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial
Disclosure
None.
Item 9A. Controls
and Procedures
Senior management of Dominion Midstreams general partner, Dominion Midstream GP, LLC, including its CEO and CFO, evaluated the
effectiveness of Dominion Midstreams disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, the CEO and CFO of Dominion Midstreams general partner have concluded that
Dominion Midstreams disclosure controls and procedures are effective. There were no changes in Dominion Midstreams internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or
are reasonably likely to materially affect, Dominion Midstreams internal control over financial reporting.
MANAGEMENTS ANNUAL REPORT ON INTERNAL
CONTROL OVER FINANCIAL REPORTING
Management of Dominion Midstreams general partner
understands and accepts responsibility for Dominion Midstreams financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion Midstream continuously strives to
identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion Midstream does throughout all aspects of its business.
Dominion Midstream maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are
safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure
appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.
The Audit
Committee of the Board of Directors of Dominion Midstreams general partner, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss
auditing, internal control, and financial reporting matters of Dominion Midstream and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically
meet alone with the Audit Committee and have free access to the Committee at any time.
SEC rules implementing Section 404 of the
Sarbanes-Oxley Act of 2002 require Dominion Midstreams 2016 Annual Report to contain a managements report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for
the report, Dominion Midstream tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31,
2016, Dominion Midstreams general partner makes the following assertions:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion Midstream.
There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or
overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary
over time.
Management evaluated Dominion Midstreams internal control over financial reporting as of December 31, 2016.
This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on
this assessment, management believes that Dominion Midstream maintained effective internal control over financial reporting as of December 31, 2016.
Dominion Midstreams independent registered public accounting firm is engaged to express an opinion on Dominion Midstreams internal
control over financial reporting, as stated in their report which is included herein.
In December 2016, Dominion Midstream acquired
Questar Pipeline. Dominion Midstream excluded all of the acquired Questar Pipeline business from the scope of managements assessment of the effectiveness of Dominion Midstreams internal control over financial reporting as of
December 31, 2016. Questar Pipeline constituted 19% of Dominion Midstreams total revenues for 2016 and 18% of Dominion Midstreams total assets as of December 31, 2016.
February 28, 2017
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the Board of Directors of Dominion Midstream GP, LLC and Members of
Dominion Midstream Partners, LP
Richmond, Virginia
We have audited the internal control over financial reporting of Dominion Midstream Partners, LP and subsidiaries (Dominion Midstream) as of
December 31, 2016, based on criteria established in Internal ControlIntegrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Managements Annual
Report on Internal Control over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Questar Pipeline, LLC (Questar Pipeline), which was acquired December 1, 2016, and whose
financial statements constitute 19% of total revenues and 18% of total assets of the consolidated financial statement amounts as of and for the year ended December 31, 2016. Accordingly, our audit did not include the internal control over
financial reporting at Questar Pipeline. Dominion Midstreams management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Managements Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion Midstreams internal control over financial reporting based on our
audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control
over financial reporting is a process designed by, or under the supervision of, the companys principal executive and principal financial officers, or persons performing similar functions, and effected by the companys board of directors,
management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the
assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal
control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies
or procedures may deteriorate.
In our opinion, Dominion Midstream maintained, in all material respects, effective internal control over
financial reporting at December 31, 2016, based on the criteria established in Internal ControlIntegrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated
financial statements as of and for the year ended December 31, 2016 of Dominion Midstream and our report dated February 28, 2017 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 28, 2017
Item 9B. Other
Information
None.
Part III
Item 10. Directors, Executive Officers and Corporate Governance
MANAGEMENT OF DOMINION MIDSTREAM
We are managed and operated by the Board of Directors and executive officers of our general partner, Dominion Midstream GP, LLC, an indirect wholly-owned
subsidiary of Dominion. As a result of owning our general partner, Dominion appoints all members of the Board of Directors of our general partner. Our unitholders will not be entitled to elect our general partner or its directors or otherwise
directly participate in our management or operations.
The Board of Directors of our general partner currently has seven members and has
determined that John A. Luke, Jr., Harris H. Simmons, John W. Snow and David A. Wollard are independent under the independence standards of the NYSE. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of
independent directors on the Board of
Directors of our general partner or to establish a compensation committee or a nominating committee. However, the Board of Directors of our general partner has established an Audit Committee and
a Conflicts Committee to address conflict situations.
Dominion Midstream does not have any employees, nor does our general partner. All
of the employees that conduct our business are employed by affiliates, and our general partner secures the personnel necessary to conduct our operations through its services agreements with DRS. We will reimburse our general partner and its
affiliates for the associated costs of obtaining the personnel necessary for our operations pursuant to our partnership agreement.
DIRECTORS OF OUR GENERAL PARTNER
The following table shows information for the directors of our general partner. Directors hold office until their successors have been elected or qualified or
until the earlier of their death, resignation, removal or disqualification. Some of our directors also serve as executive officers of Dominion.
|
|
|
|
|
|
|
Name and Age |
|
Principal Occupation and
Directorships in Public Corporations Past Five Years(1) |
|
Year First Elected as Director |
|
Thomas F. Farrell II (62) |
|
Chairman of the Board of Directors and CEO of our general partner since March 2014 and President since February 2015; Chairman of the Board of
Directors, President and CEO of Dominion from April 2007 to date; Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; CEO of Dominion Gas from September 2013 to date and Chairman of the Board of Directors from
March 2014 to date; and Chairman of the Board of Directors and CEO of Questar Gas Company from September 2016 to date. Mr. Farrell also serves as a director of Altria Group, Inc. and Associated Electric & Gas Insurance Services
Limited. Mr. Farrell received his bachelors degree in economics and his law degree from the University of Virginia. Mr. Farrells
qualifications to serve as a director include his significant and extensive industry experience as well as his legal expertise, having served as General Counsel for Dominion and as a practicing attorney with a private firm. Mr. Farrell also has
extensive community and public interest involvement and serves or has served on many non-profit and university foundations. |
|
|
2014 |
|
|
|
|
Diane Leopold (50) |
|
Director of our general partner since February 2017; Senior Vice President and President & CEODominion Energy of our general partner and
Dominion from January 2017 to date; President of Dominion Gas from January 2017 to date; President of DTI, The East Ohio Gas Company and DCPI from January 2014 to date; Senior Vice President of DTI from April 2012 to December 2013; Senior Vice
PresidentBusiness Development & Generation Construction of Virginia Power from April 2009 to March 2012. Ms. Leopold also serves as chair of the board of directors of the Interstate Natural Gas Association of America and is a member of the
board of the American Gas Association. Ms. Leopold received her bachelors degree in mechanical and electrical engineering from the University of Sussex (United Kingdom), a masters degree in electrical engineering (energy conversion,
power and transmission) from George Washington University, and an MBA from Virginia Commonwealth University. Ms. Leopolds qualifications to
serve as a director include her more than 27 years of utility and energy experience. As President and CEO of the Dominion Energy business unit, she has leadership, management, and direct operational knowledge of Dominion Midstream. |
|
|
2017 |
|
|
|
|
John A. Luke, Jr. (68) |
|
Director of our general partner since February 2017. Mr. Luke has served as non-executive chairman of WestRock Company since July 2015, when it was
formed by the combination of Rock-Tenn Company and MeadWestvaco Corporation. Prior to the combination, Mr. Luke had served as Chairman and CEO of MeadWestvaco Corporation since 2002. He spent 36 years with MeadWestvaco Corporation and its
predecessor company, Westvaco Corporation, serving in a variety of positions. From 1996 to 2002, Mr. Luke served as Chairman, President and CEO of Westvaco Corporation. He serves as a director on the boards of Factory Mutual Insurance Company, The
Bank of New York Mellon Corporation and The Timken Company. Mr. Luke received his bachelors degree from Lawrence University and an MBA from The Wharton School, University of Pennsylvania.
Mr. Lukes qualifications to serve as a director include his experience as a former CEO of a public company and the business, leadership and
management skills needed for that position. As the current non-executive chairman of WestRock Company and the chairman of its predecessor companies, Mr. Luke also brings extensive public company board experience. |
|
|
2017 |
|
|
|
|
Mark F. McGettrick (59) |
|
Director, Executive Vice President and CFO of our general partner since March 2014; Executive Vice President and CFO of Dominion and Virginia Power
from June 2009 to date, Dominion Gas from September 2013 to date and Questar Gas Company from September 2016 to date; Director of Virginia Power from June 2009 to date, Dominion Gas from September 2013 to date and Questar Gas Company from September
2016 to date. Mr. McGettrick received his bachelors degree in business from George Mason University. Mr. McGettricks
qualifications to serve as a director include his more than 35 years of utility management and industry experience. Mr. McGettrick also has community and public interest involvement and serves or has served on many non-profit foundations and boards. As CFO of our general partner, and Dominion and its subsidiaries, he has leadership, management, finance and treasury experience and skills. |
|
|
2014 |
|
|
|
|
|
|
|
|
Name and Age |
|
Principal Occupation and
Directorships in Public Corporations Past Five Years(1) |
|
Year First Elected as Director |
|
|
|
|
Harris H. Simmons (62) |
|
Director of our general partner since October 2016. Mr. Simmons has served as CEO of Zions since 1990 and as Chairman of Zions Board since
2002. He has served in a variety of positions at Zions and Zions First National Bank for more than 35 years, including CFO for Zions for five years. Zions is a financial services company that operates about 450 full-service banking offices in 11
states. He serves as a director and member of the audit committee of O.C. Tanner Company and a director and member of the audit and compensation committees of National Life Group. He is past chairman of the American Bankers Association and a member
of the Financial Services Roundtable. Mr. Simmons received his bachelors degree in economics from the University of Utah and an MBA from Harvard Business School.
Mr. Simmons qualifications to serve as a director include his extensive financial and banking experience, his leadership, corporate
governance and management skills as the CEO of Zions, and his public company director experience. As former lead director of Questar Corporation, he has familiarity with Questar Pipeline, LLC, which is a subsidiary of Dominion Midstream.
Mr. Simmons also has significant community and public interest involvement and serves or has served on many non-profit boards. |
|
|
2016 |
|
|
|
|
John W. Snow (77) |
|
Director of our general partner since October 2014. Mr. Snow is the non-executive chairman of the board
of Cerberus Capital Management, L.P. He is also a member of the board of directors of Armada Hoffler Properties, Inc., Afiniti, and Marathon Petroleum Corporation. Mr. Snow previously served on the boards of International Consolidated Airlines
Group, S.A. (2010 through 2013), Amerigroup Corporation (2010 through 2012), Verizon Communications, Inc. (2007 through 2012) and Lending Processing Servicing, Inc. (2013). Mr. Snow served as U.S. Secretary of the Treasury from February 2003
until June 2006. Prior to becoming Secretary of the Treasury, he served as chairman and CEO of CSX Corporation. Mr. Snow received a bachelors degree from the University of Toledo, a masters degree from John Hopkins University, a
doctorate in economics from the University of Virginia and a juris doctor degree from George Washington University. Mr. Snows
qualifications to serve as a director include experience as chairman of a leading private investment firm and his experience as the U.S. Secretary of the Treasury and as the chairman and CEO of a large public company. Through his current and former
service on the boards of directors of other public companies and as a CEO, he brings leadership, corporate management, governance, finance, and regulatory experience, among other business disciplines. |
|
|
2014 |
|
|
|
|
David A. Wollard (79) |
|
Director of our general partner since October 2014. Mr. Wollard is founding chairman of the board,
emeritus, Exempla Healthcare (1997 to 2001). Mr. Wollard has served as a director of Dominion since 1999 and currently serves on the CGN Committee. He served as a director of Vectra Bank Colorado until January 2016. Mr. Wollard is the past
chairman of the Downtown Denver Partnership and the Denver Metro Chamber of Commerce. He received his undergraduate degree from Harvard College and graduated from the Stonier Graduate School of Banking. Mr. Wollard held a variety of executive
positions with banking institutions in Florida and Colorado, where he was the president of Bank One Colorado, N.A. Mr. Wollards
qualifications to serve as a director include his extensive background in the banking industry. He has held executive positions and has been a director of numerous financial institutions. Mr. Wollard also has regulatory and governmental
experience which is beneficial as the energy industry continues to face legislative and regulatory scrutiny. He has also served on the board of, and has held leadership positions with, many non-profit
organizations. |
|
|
2014 |
|
(1) |
Any service listed for Dominion, Virginia Power, Dominion Gas, Questar Gas Company, DTI, The East Ohio Gas Company and DCPI reflects service at a parent or affiliate. Dominion Midstream GP, LLC, is an indirect
wholly-owned subsidiary of Dominion. Virginia Power, Dominion Gas and Questar Gas Company are affiliates of Dominion Midstream and are also subsidiaries of Dominion. |
EXECUTIVE OFFICERS OF OUR GENERAL PARTNER
The following table shows information for the executive officers of our general partner. Executive Officers serve at the discretion of the Board of Directors.
Some of our executive officers also serve as executive officers of Dominion.
|
|
|
Name and Age |
|
Business Experience Past Five Years(1) |
Thomas F. Farrell II (62) |
|
Chairman of the Board of Directors and CEO of our general partner since March 2014 and President since February 2015; Chairman of the Board of Directors, President and CEO of Dominion from April 2007 to date; Chairman of the
Board of Directors and CEO of Virginia Power from February 2006 to date; CEO of Dominion Gas from September 2013 to date; Chairman of the Board of Directors from March 2014 to date; and Chairman of the Board of Directors and CEO of Questar Gas
Company from September 2016 to date. |
Mark F. McGettrick (59) |
|
Director, Executive Vice President and CFO of our general partner since March 2014; Executive Vice President and CFO of Dominion and Virginia Power from June 2009 to date, Dominion Gas from September 2013 to date and Questar Gas
Company from September 2016 to date; Director of Virginia Power from June 2009 to date, Dominion Gas from September 2013 to date and Questar Gas Company from September 2016 to date. |
Diane Leopold (50) |
|
Director of our general partner since February 2017; Senior Vice President and President & CEODominion Energy of our general partner since January 2017, and Dominion from January 2017 to date; President of Dominion
Gas from January 2017 to date; President of DTI, The East Ohio Gas Company and DCPI from January 2014 to date; Senior Vice President of DTI from April 2012 to December 2013; Senior Vice PresidentBusiness Development & Generation
Construction of Virginia Power from April 2009 to March 2012. |
Paul E. Ruppert (52) |
|
Senior Vice President and PresidentDominion Midstream Operations of our general partner since January 2017; Senior Vice PresidentDominion Midstream Operations of our general partner from January 2016 to December 2016;
Senior Vice PresidentBusiness Development & Generation Construction of Virginia Power from April 2012 to December 2015; Senior Vice President of DTI from June 2009 to March
2012. |
|
|
|
Name and Age |
|
Business Experience Past Five Years(1) |
Mark O. Webb (52) |
|
Senior Vice PresidentCorporate Affairs and Chief Legal Officer of our general partner since January 2017, and Dominion, Virginia Power, Dominion Gas and Questar Gas Company from January 2017 to date; Senior Vice President
and General Counsel of our general partner from May 2016 to December 2016 and Questar Gas Company from September 2016 to December 2016; Senior Vice President, General Counsel and Chief Risk Officer of Dominion, Virginia Power and Dominion Gas from
May 2016 to December 2016; Vice President and General Counsel of our general partner from March 2014 to May 2016; Vice President, General Counsel and Chief Risk Officer of Dominion, Virginia Power and Dominion Gas from January 2014 to May 2016; Vice
President and General Counsel of Dominion and Virginia Power from January 2013 to December 2013, and Dominion Gas from September 2013 to December 2013; Deputy General Counsel of DRS from July 2011 to December 2012. |
Michele L. Cardiff (49) |
|
Vice President, Controller and Chief Accounting Officer of our general partner since March 2014, Dominion and Virginia Power from April 2014 to date, Dominion Gas from March 2014 to date
and Questar Gas Company from September 2016 to date; Vice PresidentAccounting of DRS from January 2014 to March 2014; Vice President and General Auditor of DRS from September 2012 to December 2013; Controller of Virginia Power from June 2009
to August 2012. |
(1) |
Any service listed for Virginia Power, Dominion Gas, Questar Gas Company, DTI, The East Ohio Gas Company, DCPI and DRS reflects service at a parent or affiliate. |
SECTION 16(A) BENEFICIAL OWNERSHIP
REPORTING COMPLIANCE
To our knowledge, no executive officer, director or 10% beneficial owner failed to file, on a
timely basis, the reports required by Section 16(a) of the Securities Exchange Act of 1934, as amended, for the fiscal year ended December 31, 2016.
AUDIT COMMITTEE
The
members of the Audit Committee are David A. Wollard (chairman), Harris H. Simmons and John W. Snow. Each member of the Audit Committee has been determined independent by the Board of Directors in accordance with NYSE listing standards and SEC
regulations. The Board of Directors has also determined that Messrs. Wollard, Simmons and Snow are audit committee financial experts as defined under SEC rules. Our Audit Committee assists the Board of Directors in its oversight of the
integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. Our Audit Committee has the sole authority to retain and terminate our independent registered public accounting
firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services and tax services to be rendered by our independent
registered public accounting firm. Our Audit Committee has a written charter adopted by the Board of Directors of our general partner, which is available on our website at
http://www.dommidstream.com/assets/pdf/mlp-audit-committee-charter.pdf.
CONFLICTS
COMMITTEE
The members of the Conflicts Committee are John A. Luke, Jr. (chairman) and John W. Snow. The Conflicts Committee reviews
specific matters that the Board of Directors believes may involve conflicts of interest and determines to submit to the Conflicts Committee for review. The Conflicts Committee determines if the resolution of the conflict of interest is adverse to
the interest of Dominion Midstream. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Dominion,
and must meet the independence standards established by the NYSE and the Securities Exchange Act of 1934, as amended, to serve on an audit committee of a board of directors, along with other
requirements in our partnership agreement. Any matters approved by the Conflicts Committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our
unitholders.
CODE OF ETHICS AND CORPORATE GOVERNANCE
GUIDELINES
Dominion Midstreams general partner has adopted a Code of Ethics that applies to its principal executive, financial
and accounting officers, as well as its employees. This Code of Ethics is available on our website at http://dommidstream.com/assets/pdf/mlp-code-of-ethics-and-business-conduct.pdf. We have also adopted Corporate Governance Guidelines that outline the important policies and practices
regarding our governance. The Corporate Governance Guidelines are available on our website at http://www.dommidstream.com/assets/pdf/mlp-corporate-governance-guidelines.pdf. You may also request a copy of the
Code of Ethics, the Corporate Governance Guidelines or any other governance document at no charge, by writing to: Corporate Secretary, 120 Tredegar Street, Richmond, Virginia 23219. Any waivers or changes to the Code of Ethics will be posted on the
Dominion Midstream website.
EXECUTIVE SESSIONS AND COMMUNICATIONS WITH
DIRECTORS
Our independent directors hold regularly scheduled executive sessions without management present. Under our Corporate
Governance Guidelines, executive sessions are chaired by an independent lead director or, if no lead director has been appointed, then the Chair of the Audit Committee.
We have established a procedure by which unitholders or interested parties may communicate with the
non-management directors by writing to them at the following address: Board of Directors, c/o Corporate Secretary, Dominion Midstream Partners, LP, P.O. Box 26532, Richmond, VA, 23261.
Item 11. Executive Compensation
COMPENSATION COMMITTEE REPORT
In preparation for filing this Annual Report on Form 10-K, Dominions CGN Committee reviewed and discussed the
following CD&A with management. Based on this review and discussion, the CGN Committee recommended to the Board of Directors of our general partner that the CD&A be included in this Annual Report on Form
10-K for the year ended December 31, 2016. This report was prepared by the following independent directors who compose the CGN Committee:
William P. Barr, Chairman
John W. Harris
Mark J. Kington
Robert H. Spilman, Jr.
David A. Wollard
INTRODUCTION
We do not directly employ any of the executive officers, who are employed by Dominion. All determinations with respect to their compensation and benefits are
made by the CGN Committee or by Dominions CEO as applicable under Dominions compensation governance policies, without any input from us, our general partner or its Board of Directors (other than awards that may be granted under the
long-term incentive plan adopted by our general partner, as noted below). Our executive officers compensation and benefits are paid by Dominion and a portion of that compensation is allocated to and reimbursed by us in accordance with the
services agreement between us and Dominion. Our executive officers participate in employee benefit plans and arrangements sponsored by Dominion.
Our general partner has adopted the Dominion Midstream LTIP, pursuant to which certain of our officers and other Dominion employees who make
significant contributions to Dominion Midstream may receive awards. None of our officers or other Dominion employees received any award under this plan in 2016.
In accordance with SEC rules, our CEO, CFO and three other most-highly compensated executive officers receiving at least $100,000 in
compensation attributable to Dominion Midstream for 2016 are our NEOs subject to disclosure in this Item 11. Mr. Ruppert is our only other executive officer who received at least $100,000 in Dominion Midstream compensation for 2016.
The Compensation Discussion and Analysis and Executive Compensation sections of Dominions 2017 Proxy Statement will
include additional discussion of Dominions compensation policies and programs. Dominions 2017 Proxy Statement will be available upon its filing on the SECs website at http://www.sec.gov and on Dominions website at
http://www.dom.com/investors.
Compensation Discussion and Analysis
Dominions executive compensation program supports its business goals by rewarding performance that serves customers and creates shareholder value. The
following CD&A describes the executive compensation program, focusing on our NEOs.
For 2016, our NEOs are:
|
|
Thomas F. Farrell II, Chairman, President and CEO |
|
|
Mark F. McGettrick, Executive Vice President and CFO
|
|
|
Paul E. Ruppert, Senior Vice President and President Dominion Midstream Operations |
Messrs.
Farrell and McGettrick are also NEOs of Dominion for 2016. The amounts reported in this Item 11 are part of, not in addition to, the aggregate compensation amounts that are reported for these NEOs in Dominions 2017 Proxy Statement.
Compensation Philosophy
Dominion applies pay-for-performance principles to provide a competitive total compensation program tied to results that align with the interests of shareholders, officers and customers. The
major objectives of the executive compensation program are to:
|
|
Attract, develop and retain an experienced and highly qualified management team; |
|
|
Motivate and reward superior performance that supports Dominions business and strategic plans and contributes to the long-term success of the company; |
|
|
Align the interests of management with those of Dominions shareholders and customers by placing a substantial portion of pay at risk through performance goals that, if achieved, are expected to increase TSR and
enhance customer service; |
|
|
Promote internal pay equity; and |
|
|
Reinforce Dominions four core values of safety, ethics, excellence and One Dominion Dominions term for teamwork. |
To determine if the program is meeting these objectives, the CGN Committee compares the companys actual performance to its short-term and long-term
goals and to peer companies performance.
INDIVIDUAL FACTORS IN SETTING
COMPENSATION
In addition to considering Dominions goals and performance, the CGN Committee also considers several individual
factors for each NEO, including:
|
|
Job and leadership performance |
|
|
Scope, complexity and significance of job responsibilities |
|
|
Internal pay equity considerations, such as relative importance of a particular position or individual officer to Dominions strategy and success, and comparability to other officer positions at Dominion
|
|
|
Experience, background and tenure |
|
|
Retention and market competitive concerns |
|
|
The executives role in any succession plan for other key positions |
These individual factors are
important considerations in setting base pay and other compensation opportunities.
VARIABLE COMPENSATION
OPPORTUNITIES IN 2016
Consistent with Dominions objective to reward strong performance based on achievement of
short- and long-term goals, a significant portion of total cash and total direct compensation is variable pay. Approximately 89% of Mr. Farrells targeted 2016 total direct compensation is performance-based; tied to pre-approved performance metrics, including relative TSR and ROIC; or tied to the performance of Dominions stock. For the other NEOs of Dominion, performance-based and stock-based compensation ranges from 67%
to 81% of targeted 2016 total direct compensation. This compares to an average of approximately 55% of targeted variable compensation for Dominion officers at the vice president level and an average of approximately 12% of total variable pay for
Dominions non-officer employees.
The charts below illustrate the elements of targeted total direct compensation opportunities
in 2016 for Mr. Farrell and the average of the other Dominion NEOs as a group and the allocation of such compensation among base salary, targeted 2016 AIP award and targeted 2016 long-term incentive compensation.
Compensation Elements
Dominions executive compensation program is constructed of four building blocks: base pay, AIP, long-term incentive program and executive benefits. Each
element serves a distinct purpose. These complementary components appropriately balance risk with reward and short-term goals with long-term strategies, while providing total compensation that is competitive with peer companies.
BASE SALARY
Competitive
base pay is necessary to attract, motivate and retain talent. For NEOs, base salaries are generally targeted at or above the Compensation Peer Group median, subject to the individual and company-wide considerations discussed above under
Compensation Philosophy.
The CGN Committee approved 3% base salary increases for Messrs. Farrell and McGettrick, recognizing
their continued contributions to Dominions success. In addition, Mr. Ruppert received a 17% base salary increase in connection with his promotion to President Dominion Midstream Operations. The base salary increases were each
effective March 1, 2016.
ANNUAL INCENTIVE PLAN
The AIP is a cash-based program focused on short-term goals, and it is designed to:
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Tie interests of shareholders, customers and employees closely together |
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Focus Dominions workforce on company, operating group, team and individual goals that ultimately influence operational and financial results |
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Reward corporate and operating unit earnings performance |
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Reward safety, diversity and other operating and stewardship goal successes |
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Emphasize teamwork by focusing on common goals |
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Provide a competitive total compensation opportunity |
For Messrs. Farrell and McGettrick, who are also NEOs of
Dominion, funding of the 2016 AIP was tied solely to the achievement of predetermined earnings per share goals. However, the CGN Committee retained discretion to reduce the AIP payout for any NEO for any reason, including missed business unit
financial targets or failure to satisfy operating and stewardship goals. For Mr. Ruppert, who is not an NEO of Dominion, funding of the 2016 AIP was at the discretion of the CGN Committee, with payout subject to business unit financial goals
and operating and stewardship goals.
The CGN Committee calculated 2016 AIP
payouts for the NEOs as follows:
Target Award Percentage
Each NEOs compensation opportunity under the AIP is a percentage of his base salary. AIP target award percentages are set to be consistent with
Dominions intent to keep a significant portion of NEO compensation at risk, taking into account the items described above under Compensation Philosophy. There were no changes to any NEOs AIP target award percentage from 2015 to
2016.
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2016 AIP Target Award Percentage* |
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Thomas F. Farrell II |
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|
125 |
% |
Mark F. McGettrick |
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|
100 |
% |
Paul E. Ruppert |
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50 |
% |
*As |
a percentage of base salary |
Funding Level
For Dominions NEOs, the funding level is determined solely by consolidated operating earnings, which are Dominions reported earnings determined in
accordance with GAAP, adjusted for certain items. Dominion believes that focus on pre-established consolidated operating earnings per share targets encourages behavior and performance that will help achieve
these objectives.
For Dominions NEOs, the CGN Committee set the consolidated operating earnings goal to provide for 100% funding
of the 2016 AIP between $3.50 and $3.80 per share, inclusive of funding for all plan participants. The target for maximum funding of 200% was set at $4.00 operating earnings per share. The CGN Committee also established a funding floor, providing no
funding if operating earnings were less than $3.45 per share.
Dominions consolidated operating earnings for the year ended
December 31, 2016 were $2.3 billion or $3.80 per share, which met the target goal for 100% funding, and consolidated reported earnings in accordance with GAAP for the year ended December 31, 2016 were $2.1 billion or
$3.44 per share. Accordingly, the CGN Committee approved a funding percentage of 100% for all NEOs, including Mr. Ruppert.
Payout Goal
Score
In determining whether and how to exercise its negative discretion for Dominion NEOs, the CGN Committee typically
considers each NEOs accomplishment of pre-determined business unit financial goals and operating and stewardship goals, weighted according to each
NEOs responsibilities. The Committee approved 100% payout scores for Messrs. Farrell and McGettrick.
Mr. Ruppert also
received a 100% payout score, based on the CGN Committees scoring of his business unit financial goal and the accomplishment of his operating and stewardship goals. Mr. Ruppert is an officer of the Dominion Energy business unit, which did
not accomplish 100% of its business unit financial goal. However, as permitted by the terms of and consistent with the design of the AIP, the Committee approved full credit for this goal because corporate-level decisions negatively impacted
individual business unit financial results but benefited Dominion and shareholders overall. This resulted in Dominion achieving its consolidated earnings target, as the benefits of those actions offset the lower earnings at those business units.
Dominions companywide OSHA recordable and lost time/restricted duty incidence rates for 2016 were
all-time lows. With respect to Messrs. Farrell and McGettrick, the Dominion Resources Services business unit met its safety goal of fewer than three OSHA recordable incidents or fewer than 15 FIPs, reporting
just two OSHA recordable incidents and seven FIPs. Mr. Rupperts safety goal was fully achieved, with the Dominion Energy business unit reporting an OSHA incidence rate of 0.98 and a lost time rate of 0.43.
Each NEO met his diversity goal, which related to workforce training and planning. Mr. Ruppert also had discretionary operating and
stewardship goals in the following areas: Cove Point operations, Cove Point construction and Dominion Carolina Gas. Mr. Ruppert fully achieved his Cove Point operations goal, but scored 9.8 points (out of a possible 10 points) for his Cove
Point construction goal and 3.7 points (out of a possible 4 points) for the Dominion Carolina Gas goal. In accordance with pre-established plan terms, Mr. Ruppert earned 5 extra credit points for Dominion
Energys outstanding safety performance, which was sufficient to offset the 0.5 points deducted for the Cove Point operations and Dominion Carolina Gas goals, resulting in a payout score of 100%.
Final AIP Payout
The CGN Committee calculated final 2016 AIP payouts as shown below.
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Base Salary |
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Target Award* |
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Funding Level |
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Payout Goal Score |
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Final AIP Payout |
|
Thomas F. Farrell II |
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$ |
10,993 |
|
|
X |
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|
125 |
% |
|
x |
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|
100 |
% |
|
x |
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|
100 |
% |
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= |
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$ |
13,741 |
|
Mark F. McGettrick |
|
|
13,777 |
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X |
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100 |
% |
|
x |
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100 |
% |
|
x |
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100 |
% |
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= |
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13,777 |
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Paul E. Ruppert |
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344,889 |
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X |
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50 |
% |
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x |
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100 |
% |
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x |
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100 |
% |
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= |
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172,445 |
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*As |
a percentage of base salary |
Note: The NEOs perform services for more than one subsidiary of
Dominion. Compensation included in this table reflects only the applicable portion related to their service for Dominion Midstream.
DOMINIONS LONG-TERM
INCENTIVE PROGRAM
Dominions long-term incentive program is designed to focus on longer-term strategic goals and
the retention of executives. Each year, NEOs receive a long-term incentive award consisting of two components: 50% of the award is a full value equity award in the
form of restricted stock with time-based vesting and the other 50% is a performance-based cash award. Dominion believes restricted stock serves as a strong retention tool and also creates a focus
on its stock price to further align the interests of officers with the interests of shareholders and customers.
Performance-
based awards encourage and reward officers for making decisions and investments that create and maintain long-term shareholder value and benefit customers.
The CGN Committee approves long-term incentive awards in January. In setting long-term award levels for each NEO, the CGN Committee applies
the concepts and individual factors discussed above under Compensation Philosophy. The CGN Committee approved a 15% increase in the 2016 long-term incentive target awards for Messrs. Farrell and McGettrick, noting the complexity of
Dominions operations; the vesting of each officers respective retention award in 2015; that Dominion is in a critical development and building period for the Atlantic Coast Pipeline, Cove Point, and various Generation projects; and the
need to focus on long-term rewards for the longer-term benefits of execution of Dominions strategic plan. The CGN Committee also considered each officers leadership experience and accomplishments, as well as Dominions overall
performance. No change was made to Mr. Rupperts long-term incentive target. The 2016 targets for the NEOs were approved as follows:
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2016 Performance Grant |
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2016 Restricted Stock Grant |
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2016 Total Target Long-Term Incentive Award |
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Thomas F. Farrell II |
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$ |
37,263 |
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$ |
37,263 |
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$ |
74,526 |
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Mark F. McGettrick |
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21,678 |
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27,678 |
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43,356 |
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Paul E. Ruppert |
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150,000 |
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150,000 |
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300,000 |
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Note: The NEOs perform services for more than one subsidiary of Dominion. Compensation included in this table reflects only
the applicable portion related to their service for Dominion Midstream.
2016 Restricted Stock Grants
All NEOs received a restricted stock grant on February 3, 2016, based on the stated dollar value above. The number of shares awarded was determined by
dividing the stated dollar value by the closing price of Dominions common stock on February 3, 2016.
The grants have a three-year vesting
term, with cliff vesting at the end of the restricted period on February 1, 2019. Dividends are paid to officers during the restricted period.
2016 Performance Grants
In January 2016, the CGN
Committee approved cash performance grants for the NEOs, effective February 1, 2016 (2016 Performance Grants). The performance period commenced on January 1, 2016, and will end on December 31, 2017. The 2016 Performance Grants are
denominated as a target dollar value, with potential payouts ranging from 0% to 200% of the target based on Dominions TSR relative to the Philadelphia Stock Exchange Utility Index and ROIC, weighted equally. (See Performance Grant Peer
Group for additional information about the Philadelphia Stock Exchange Utility Index.) In certain circumstances, a portion of the 2016 Performance Grants may also be earned based on Dominions absolute TSR performance for the performance
period.
TSR is the difference between the value of a share of common stock at the beginning and end of the two-year performance period, plus dividends paid as if reinvested in stock. The TSR metric was selected to focus officers on long-term shareholder value when developing and implementing strategic plans and reward
management based on the achievement of TSR levels relative to the Performance Grant Peer Group.
ROIC reflects the companys total return divided by average invested capital for the
performance period. The ROIC goal at target is consistent with the strategic plan and annual business plan as approved by the Board. For this purpose, total return is the companys consolidated operating earnings plus its after-tax interest and related charges, plus preferred dividends. The ROIC metric was selected to reward officers for the achievement of expected levels of return on the companys investments. Dominion believes
an ROIC measure encourages management to choose the right investments, and with those investments, to achieve the highest returns possible through prudent decisions, management and cost control.
Because officers are expected to retain ownership of shares upon vesting of restricted stock awards, as explained in Share Ownership
Guidelines, the cash performance grant balances the long-term program and allows a portion of the long-term incentive award to be accessible to NEOs during the course of their employment.
Officers who have not achieved 50% of their targeted share ownership guideline receive goal-based stock performance grants instead of a cash
performance grant. Dividend equivalents are not paid on any performance-based grants. As Messrs. Farrell, McGettrick and Ruppert have each met their full targeted share ownership guidelines, they each received the performance-based component of
their 2016 long-term incentive award in the form of a cash performance grant.
Performance Grant Peer Group
TSR performance for the 2016 Performance Grant is measured against the TSR of the companies listed as members of the Philadelphia Stock Exchange Utility Index
at the end of the performance period (the Performance Grant Peer Group). In selecting the Philadelphia Stock Exchange Utility Index, the CGN Committee took into consideration that the companies represented in the index are similar to those companies
currently included in Dominions Compensation Peer Group, and the index is a recognized published index whose members are determined externally and independently from Dominion. The companies (other than Dominion) in the Philadelphia Stock
Exchange Utility Index as of January 1, 2017 were as follows:
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The AES Corporation
Ameren Corporation
American Electric Power Company, Inc.
American Water Works Company, Inc.
CenterPoint Energy, Inc.
Consolidated Edison, Inc.
DTE Energy Company
Duke Energy Corporation
Edison International |
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El Paso Electric Company
Entergy Corporation
Eversource Energy
Exelon Corporation
FirstEnergy Corp.
NextEra Energy Inc.
PG&E Corporation
Public Service Enterprise Group Incorporated
The Southern Company
Xcel Energy, Inc. |
2015 Performance Grant Payout
In January 2017, final payouts were made to officers who received cash performance grants in February 2015 (2015 Performance Grants), including the NEOs. The
2015 Performance Grants were based on two goals: TSR for the two-year period ended December 31, 2016, relative to the companies in the Philadelphia
Stock Exchange Utility Index as of the end of the performance period (weighted 50%) and ROIC for the same two-year period (weighted 50%).
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Relative TSR (50% weighting). The relative TSR targets and corresponding payout scores for the 2015 Performance Grant were as follows: |
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Relative TSR Performance Percentile Ranking |
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Goal Achievement %* |
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85th or above |
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200 |
% |
50th |
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100 |
% |
25th |
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50 |
% |
Below
25th |
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% |
* |
TSR weighting is interpolated between the top and bottom of the percentages within a quartile. If the companys relative TSR is below the 25th percentile, but its absolute TSR is at least 9% on a compounded
annual basis for the performance period, a goal achievement of 25% of the TSR percentage will apply. In addition to the foregoing amounts and regardless of the companys relative TSR, if the companys absolute TSR on a compounded annual
basis for the performance period is either (i) at least 10% but less than 15%, then an additional 25% will be added to the goal achievement percentage or (ii) at least 15%, then an additional 50% will be added to the goal achievement
percentage, provided that the aggregate goal achievement may not exceed 200%. |
Actual relative TSR performance for the 2015-2016 period
was in the 26th percentile, which produced a goal achievement percentage of 52.6%. Dominions TSR for the two-year period ended December 31, 2016,
was 7.4%, which is equivalent to 3.7% on a compounded annual basis.
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ROIC (50% weighting). Dominion designed the ROIC goals for the 2015 Performance Grant to provide 100% payout if the company achieved an ROIC between 6.69% and 6.90% over the
two-year performance period. The ROIC performance targets and corresponding payout scores for the 2015 Performance Grant were as follows: |
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ROIC Performance |
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Goal Achievement %* |
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7.47% and above |
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200 |
% |
7.14% |
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125 |
% |
6.69% 6.90% |
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100 |
% |
6.62% |
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50 |
% |
Below 6.62% |
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% |
* |
ROIC percentage payout is interpolated between the top and bottom of the percentages for any range. |
Actual ROIC performance for the 2015-2016 period was 6.90%, which produced a goal achievement percentage of 100%. Based on the achievement
of the TSR and ROIC performance goals, the CGN Committee approved a 76.3% payout for the 2015 Performance Grants, determined as follows:
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Measure |
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Goal Weight % |
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Goal Achievement % |
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Payout % |
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Relative TSR |
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50 |
% |
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X |
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52.6 |
% |
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= |
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26.3 |
% |
ROIC |
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50 |
% |
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X |
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100 |
% |
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= |
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50.0 |
% |
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Combined Overall Performance Score |
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76.3 |
% |
Although the CGN Committee has discretionary authority to reduce this overall score for any
reason, this discretion was not exercised. The resulting payout amounts for the NEOs for the 2015 Performance Grants are shown below.
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2015 Performance Target Grant Award |
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Overall Performance Score |
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Calculated Performance Grant Payout |
|
Thomas F. Farrell II |
|
$ |
32,403 |
|
|
|
X |
|
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76.3 |
% |
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= |
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|
$ |
24,723 |
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Mark F. McGettrick |
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|
18,851 |
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|
X |
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76.3 |
% |
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= |
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14,383 |
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Paul E. Ruppert |
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150,000 |
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|
X |
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76.3 |
% |
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= |
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114,450 |
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Note: The NEOs perform services for more than one subsidiary of Dominion. Compensation included in this table reflects only
the applicable portion related to their service for Dominion Midstream.
EMPLOYEE AND EXECUTIVE
BENEFITS
Benefit plans and limited perquisites comprise the fourth element of Dominions compensation program. These benefits
serve as a retention tool and reward long-term employment.
Retirement Plans
All eligible Dominion non-union employees participate in a tax-qualified
defined benefit pension plan (the Pension Plan) and a 401(k) plan that includes a company match. Each year, officers whose matching contributions under Dominions 401(k) plan are limited by the IRC receive a taxable cash payment to make them
whole for the company match that is lost as a result of these limits. The company matching contributions to the 401(k) plan and the cash payments of company matching contributions above the IRC limits for the NEOs are included in the All Other
Compensation column of the Summary Compensation Table and detailed in the footnote for that column.
Dominion also maintains
two nonqualified retirement plans for Dominions executives, the BRP and the ESRP. These plans help Dominion compete for and retain executive talent. Due to the IRC limits on Pension Plan benefits and because a more substantial portion of total
compensation for Dominions officers is paid as incentive compensation than for other employees, the Pension Plan and 401(k) plan alone would produce a lower percentage of replacement income in retirement for officers than these plans will
provide for other employees. The BRP restores benefits that cannot be paid under the Pension Plan due to IRC limits. The ESRP provides a benefit that covers a portion (25%) of final base salary and target annual incentive compensation to
partially make up for this gap in retirement income. Effective July 1, 2013, the ESRP was closed to any new participants.
The
Pension Plan, 401(k) plan, BRP and ESRP do not include long-term incentive compensation in benefit calculations and, therefore, a significant portion of the potential compensation for officers is excluded from calculation in any retirement plan
benefit. As consideration for the benefits earned under the BRP and ESRP, all officers agree to comply with confidentiality and one-year non-competition requirements set
forth in the plan documents following their retirement or other termination of employment. The present value of accumulated benefits under these retirement plans is disclosed in the Pension Benefits table and the terms of the plans are more
fully explained in the narrative following that table.
In individual situations and primarily for
mid-career changes or retention purposes, the CGN Committee has granted certain
officers additional years of credited age and service for purposes of calculating benefits under the BRP. Age and service credits granted to the NEOs are described in Dominion Retirement
Benefit Restoration Plan under Pension Benefits. Additional age and service may also be earned under the terms of an officers Employment Continuity Agreement in the event of a change in control, as described in Change in
Control under Potential Payments Upon Termination or Change in Control. No additional years of age or service credit were granted to the NEOs during 2016.
Other Benefit Programs
Dominions officers
participate in the benefit programs available to other Dominion employees. The core benefit programs generally include medical, dental and vision benefit plans, a health savings account, health and dependent care flexible spending accounts,
group-term life insurance, travel accident coverage, long-term disability coverage and a paid time off program.
Dominion also maintains
an executive life insurance program for officers to replace a former companywide retiree life insurance program that was discontinued in 2003. The plan is fully insured by individual policies that provide death benefits at a fixed amount depending
on an officers salary tier. This life insurance coverage is in addition to the group-term insurance that is provided to all Dominion employees. The officer is the owner of the policy and the company makes premium payments until the later of 10
years from enrollment date or the date the officer attains age 64. Officers are taxed on the premiums paid by the company. The premiums for these policies are included in the All Other Compensation column of the Summary Compensation
Table.
Perquisites
Dominion provides a limited
number of perquisites for its officers to enable them to perform their duties and responsibilities as efficiently as possible and to minimize distractions. The CGN Committee annually reviews the perquisites to ensure they are an effective and
efficient use of corporate resources. Dominion believes the benefits it receives from offering these perquisites outweigh the costs of providing them. Dominion offers the following perquisites to all officers:
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An allowance of up to $9,500 a year to be used for health club memberships and wellness programs, comprehensive executive physical exams and financial and estate planning. Dominion wants officers to be proactive with
preventive healthcare and also wants executives to use professional, independent financial and estate planning consultants to ensure proper tax reporting of company-provided compensation and to help officers optimize their use of Dominions
retirement and other employee benefit programs. |
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A vehicle leased by Dominion, up to an established lease-payment limit (if the lease payment exceeds the allowance, the officer pays for the excess amount on the vehicle). The costs of insurance, fuel and maintenance
for company-leased vehicles are paid by the company. |
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In limited circumstances, use of corporate aircraft for personal travel by executive officers. For security and other reasons, Dominions Board of Directors has directed Mr. Farrell to use the corporate
aircraft for air travel, including personal travel. Mr. Farrells family and guests may accompany him on any
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personal trips. The use of corporate aircraft for personal travel by other executive officers is limited and usually related to (i) travel with the CEO or (ii) personal travel to
accommodate business demands on an executives schedule. With the exception of Mr. Farrell, personal use of corporate aircraft is not available when there is a company need for the aircraft. Use of corporate aircraft saves substantial time
and allows Dominion to have better access to its executives for business purposes. During 2016, 96% of the use of Dominions aircraft was for business purposes. |
Other than costs associated with comprehensive executive physical exams (which are exempt from taxation under the IRC), these perquisites are fully taxable to
officers. There is no tax gross-up for imputed income on any perquisites.
Employment Continuity Agreements
Dominion has entered into Employment Continuity Agreements with all officers to ensure continuity in the event of a change in control of the company.
These agreements are consistent with competitive practice for Dominions peer companies, and they protect the company in the event of an anticipated or actual change in control. In a time of transition, it is critical to protect shareholder
value by retaining and continuing to motivate the companys core management team. In a change in control situation, workloads typically increase dramatically, outside competitors are more likely to attempt to recruit top performers away from
the company, and officers and other key employees may consider other opportunities when faced with uncertainties at their own company. The Employment Continuity Agreements provide security and protection to officers in such circumstances for the
long-term benefit of the company and its shareholders.
In determining appropriate compensation and benefits payable upon a change in
control, the company evaluated peer group and general practices and considered the levels of protection necessary to retain officers in such situations. The Employment Continuity Agreements are double-trigger agreements that require both a change in
control and a qualifying termination of employment to trigger most benefits. The specific terms of the Employment Continuity Agreements are discussed in Potential Payments Upon Termination or Change in Control.
Other Agreements
Dominion does not have comprehensive
employment agreements or severance agreements with its NEOs. Although the CGN Committee believes the compensation and benefit programs described in this CD&A are appropriate, Dominion, as one of the nations largest producers and
transporters of energy, is part of a constantly changing and increasingly competitive environment. In recognition of their valuable knowledge and experience and to secure and retain their services, Dominion has entered into letter agreements with
certain of our NEOs to provide certain benefit enhancements or other protections, as described in Dominion Retirement Benefit Restoration Plan, Dominion Executive Supplemental Retirement Plan and Potential Payments Upon Termination or
Change in Control. No new letter agreements were entered into for NEOs in 2016.
Dominions Process
The CGN Committee is responsible for reviewing and approving NEO compensation and Dominions overall executive
compensa-
tion program. Each year, the CGN Committee reviews a comprehensive analysis of the executive compensation program, including the elements of each NEOs compensation, with input from senior
management and the CGN Committees independent compensation consultant. As part of its assessment, the CGN Committee reviews the performance of the CEO and other executive officers, annually reviews succession planning for the companys
senior officers, reviews executive officer share ownership guidelines and compliance, and establishes compensation programs designed to achieve Dominions objectives.
The CGN Committee evaluates each NEOs base salary, total cash compensation (base salary plus target AIP award) and total direct
compensation (base salary plus target AIP award and target long-term incentive award) against data from Dominions Compensation Peer Group. To ensure the compensation levels are appropriately competitive and consistent with the companys
overall strategy, the CGN Committee considers the peer data together with the considerations described above under Individual Factors in Setting Compensation. Neither the peer comparison nor the individual factors are assigned any specific
weighting. As part of its analysis, the CGN Committee also considers Dominions size, including market capitalization and price-to-earnings ratio, and complexity
compared to the companies in Dominions Compensation Peer Group, as well as the tenure of the NEO as compared to executives in a similar position in a Compensation Peer Group company.
THE ROLE OF THE INDEPENDENT COMPENSATION
CONSULTANT
The CGN Committee has retained Frederic W. Cook & Co. (Cook & Co.) as its independent compensation consultant
to advise the CGN Committee on executive and director compensation matters. The CGN Committees consultant:
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Attends meetings as requested by the CGN Committee, either in person or by teleconference; |
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Communicates directly with the chairman of the CGN Committee outside of the CGN Committee meetings as needed; |
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Participates in CGN Committee executive sessions as requested without the CEO present to discuss CEO compensation and any other relevant matters, including the appropriate relationship between pay and performance and
emerging trends; |
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Reviews and comments on proposals and materials prepared by management and answers technical questions, as requested; and |
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Generally reviews and offers advice as requested by or on behalf of the CGN Committee regarding other aspects of Dominions executive compensation program, including best practices and other matters.
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In 2016, the CGN Committee reviewed and assessed the independence of Cook & Co. and concluded that Cook & Co.s work
did not raise any conflicts of interest. Cook & Co. did not provide any additional services to Dominion during 2016.
MANAGEMENTS ROLE IN DOMINIONS PROCESS
Although the CGN Committee has the responsibility to approve and monitor all compensation for our NEOs, management plays an important role in
determining executive compensation. Under the
direction of management, internal compensation specialists provide the CGN Committee with data, analysis and counsel regarding the executive compensation program, including an ongoing assessment
of the effectiveness of the program, peer practices, and executive compensation trends and best practices. Management, along with Dominions internal compensation and financial specialists, assist in the design of Dominions incentive
compensation plans, including performance target recommendations consistent with the strategic goals of the company, and recommendations for establishing the peer group. Management also works with the chairman of the CGN Committee to establish the
agenda and prepare meeting information for each CGN Committee meeting.
The CEO is responsible for reviewing senior officer succession
plans with the CGN Committee on an annual basis. Mr. Farrell is also responsible for reviewing the performance of the other senior officers, including the other NEOs, with the CGN Committee at least annually. He makes recommendations on the
compensation and benefits for the NEOs (other than himself) to the CGN Committee and provides other information and advice as appropriate or as requested by the CGN Committee, but all decisions are ultimately made by the CGN Committee.
THE COMPENSATION PEER GROUP
The CGN Committee uses the
Compensation Peer Group to assess the competitiveness of the compensation of the NEOs. A separate Performance Grant Peer Group is used to evaluate the relative performance of the company for purposes of the long-term incentive program (see 2016
Performance Grants and Performance Grant Peer Group for additional information about that group.)
In the fall of each year,
the CGN Committee reviews and approves the Compensation Peer Group. In selecting the Compensation Peer Group, Dominion identifies companies in its industry that compete for customers, executive talent and investment capital. The group is screened
based on size and companies that are much smaller or larger than Dominion in revenues, assets or market capitalization are usually eliminated. No changes were made to the Compensation Peer Group for 2016.
Dominions 2016 Compensation Peer Group was comprised of the following companies:
|
|
|
Ameren Corporation
American Electric Power Company, Inc.
CenterPoint Energy, Inc.
DTE Energy Company
Duke Energy Corporation
Entergy Corporation
Exelon Corporation |
|
FirstEnergy Corp.
NextEra Energy Inc.
NiSource Inc.
PPL Corporation
Public Service Enterprise Group Incorporated
The Southern Company
Xcel Energy, Inc. |
The CGN Committee and management use the Compensation Peer Group to: (i) compare Dominions stock and financial
performance against these peers using a number of different metrics and time periods to evaluate how Dominion is performing as compared to peers; (ii) analyze compensation practices within Dominions industry; (iii) evaluate peer
company practices and determine peer median and 75th percentile ranges for base pay, annual incentive pay, long-term incentive pay and total direct compensation, both generally and for specific positions; and (iv) compare Dominions
benefits and perquisites. In setting the levels for base pay, annual incentive pay, long-term incentive pay
and total direct compensation, the CGN Committee also takes into consideration Dominions size compared with the median of the Compensation Peer Group and the complexity of its business.
SURVEY AND OTHER DATA
Survey compensation data and information on local companies with whom Dominion competes for talent and other companies with comparable market capitalization
to Dominion are used only to provide a general understanding of compensation practices and trends, not as benchmarks for compensation decisions. The CGN Committee takes into account individual and company-specific factors, including internal pay
equity, along with data from the Compensation Peer Group, in establishing compensation opportunities. The CGN Committee believes this reflects Dominions specific needs in its distinct competitive market and with respect to its size and
complexity versus its peers.
CEO COMPENSATION RELATIVE TO OTHER NEOS
Mr. Farrell generally participates in the same compensation programs and receives compensation based on the same philosophy and factors as the
other NEOs. Application of the same philosophy and factors to Mr. Farrells position results in overall CEO compensation that is significantly higher than the compensation of the other NEOs. Mr. Farrells compensation is
commensurate with his greater responsibilities and decision-making authority, broader scope of duties encompassing the entirety of the company (as compared to the other NEOs who are responsible for significant but distinct areas within the company)
and his overall responsibility for corporate strategy. His compensation also reflects his role as Dominions principal corporate representative to investors, customers, regulators, analysts, legislators, industry and the media.
Dominion considers CEO compensation trends as compared to the next highest-paid officer, as well as to its executive officers as a group,
over a multi-year period to monitor the ratio of Mr. Farrells pay relative to the pay of other executive officers. The CGN Committee did not make any adjustments to the compensation of any NEOs based on this review for 2016.
Governance
Dominions strong corporate governance is rooted in its core value of ethics. Dominion supports a culture of good governance with solid compensation
practices that pay for performance and promote strategic risk management.
|
|
|
Dominion Does: |
|
Dominion Does Not: |
✓ Balance short- and long-term incentives
✓ Place a substantial portion of NEO pay at risk and tied to
enhanced shareholder value ✓ Use different performance measures
for annual and long-term incentive programs ✓ Review the
executive compensation program to ensure it does not promote excessive risk taking
✓ Measure relative TSR for its performance grant payout using the
Philadelphia Stock Exchange Utility Index, an independently-determined peer group
✓ Maintain rigorous share ownership guidelines
✓ Incorporate clawback provisions in incentive compensation
✓ Include a non-compete
clause in executive retirement plans ✓ Proactively engage with
top shareholders on compensation and governance issues ✓ Conduct
annual Say on Pay votes ✓ Require two triggers for the payment
of most change-in-control benefits |
|
X Allow payout of AIP awards or performance grants greater than 200% of target
X Offer long-term or indefinte employment agreements to executives
X Include long-term incentive awards in retirement or severance calculations (other than prorated payout of
outstanding awards) X Permit officers or directors to hedge or pledge shares
X Offer excessive executive perquisites or provide tax gross-up on
executive perquisites X Dilute shareholder value by issuing excessive equity compensation
X Offer excessive change-in-control
severance benefits or provide excise tax-gross-ups in change-in-control agreements for
new officers (elected after February 1, 2013) X Offer the ESRP to new officers (elected
after July 1, 2013) |
ANNUAL COMPENSATION RISK REVIEW
Dominions management, including Dominions Chief Risk Officer and other executives, annually reviews the overall structure of Dominions
executive compensation program and policies to ensure that they are consistent with effective management of enterprise key risks and that they do not encourage executives to take unnecessary or excessive risks that could threaten the value of the
enterprise. With respect to the programs and policies that apply to NEOs, this review includes an analysis of:
|
|
How different elements of the compensation program may increase or mitigate risk-taking; |
|
|
Performance metrics used for short- and long-term incentive programs and the relation of such incentives to the objectives of Dominion; |
|
|
Whether the performance measurement periods for short- and long-term incentive compensation are appropriate; and |
|
|
The overall structure of compensation programs as related to business risks. |
Among the
factors considered in managements assessment are: (i) the balance of overall program design, including the mix of cash and equity compensation; (ii) the mix of fixed and variable compensation; (iii) the balance of short-term and
long-term objectives of incentive compensation; (iv) the performance metrics, performance targets, threshold performance requirements and capped payouts related to incentive compensation; (v) clawback provisions on incentive compensation;
(vi) share
ownership guidelines, including share ownership levels and retention practices and prohibitions on hedging, pledging and other derivative transactions related to Dominion stock; (vii) the
CGN Committees ability to exercise negative discretion to reduce the amount of the annual and long-term incentive awards; and (viii) internal controls and oversight structures in place at Dominion.
Based on managements review, the CGN Committee believes Dominions well-balanced mix of salary and short-term and long-term
incentives, as well as the performance metrics that are included in the incentive programs, are appropriate and consistent with the companys risk management practices and overall strategies.
SHARE OWNERSHIP GUIDELINES
Dominion requires officers to own and retain significant amounts of Dominion stock to align their interests with those of shareholders by promoting a
long-term focus through long-term share ownership. The guidelines ensure that management maintains a personal stake in the company through significant equity investment in the company. Targeted ownership levels are the lesser of the following value
or number of shares:
|
|
|
|
|
Position |
|
Value /# of Shares |
|
Chairman, President & CEO |
|
|
8 x salary /145,000 |
|
Executive Vice President Dominion |
|
|
5 x salary / 35,000 |
|
Senior Vice President Dominion & Subsidiaries/President Dominion Subsidiaries |
|
|
4 x salary / 20,000 |
|
Vice President Dominion & Subsidiaries |
|
|
3 x salary / 10,000 |
|
The levels of ownership reflect the increasing level of responsibility for that officers position.
Shares owned by an officer and his or her immediate family members as well as shares held under company benefit plans count toward the ownership targets. Restricted stock, goal-based stock and shares underlying stock options do not count toward the
ownership targets until the shares vest or the options are exercised.
Until an officer meets his or her ownership target, an officer
must retain all after-tax shares from the vesting of restricted stock and goal-based stock awards. Dominion refers to shares held by an officer that are more than 15% above his or her ownership target as
qualifying excess shares. An officer may sell, gift or transfer qualifying excess shares at any time, subject to insider trading rules and other policy provisions as long as the sale, gift or transfer does not cause an executive to fall below his or
her ownership target.
At least annually, the CGN Committee reviews the share ownership guidelines and monitors compliance by executive
officers, both individually and by the officer group as a whole. As of January 1, 2017, Messrs. Farrell, McGettrick and Ruppert each exceeded their share ownership targets as shown below:
|
|
|
|
|
|
|
|
|
|
|
Shares Owned and Counted Toward Target
1) |
|
|
Share Ownership Target (2) |
|
Thomas F. Farrell II |
|
|
756,037 |
|
|
|
145,000 |
|
Mark F. McGettrick |
|
|
249,492 |
|
|
|
35,000 |
|
Paul E. Ruppert |
|
|
32,596 |
|
|
|
20,000 |
|
Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Amounts shown are actual
and not reduced by their Dominion Midstream allocation factor.
(1) |
Does not include shares of unvested restricted stock that are not counted toward ownership targets |
(2) |
Share ownership target is the lesser of salary multiple or number of shares |
ANTI-HEDGING POLICY
Dominion prohibits employees and directors from engaging in certain types of transactions that are designed to or may result in protection against potential
decreases in the value of Dominion stock that they own, including owning derivative securities, hedging transactions, using margin accounts and pledging shares as collateral.
RECOVERY OF INCENTIVE COMPENSATION
Dominions Corporate Governance Guidelines authorize the Board to seek recovery of performance-based compensation paid to officers who are found to be
personally responsible for fraud or intentional misconduct that causes a restatement of financial results filed with the SEC. The AIP and long-term incentive performance grant documents include a broader clawback provision that authorizes the CGN
Committee, in its discretion and based on facts and circumstances, to recoup AIP and performance grant payouts from any employee whose fraudulent or intentional misconduct (i) directly causes or partially causes the need for a restatement of a
financial statement or (ii) relates to or materially affects Dominions operations or the employees duties at Dominion. Dominion reserves the right to recover a payout by seeking repayment from the employee, by reducing the amount
that would otherwise be payable to the employee under another company benefit plan or compensation program to the extent permitted by applicable law, by withholding future incentive compensation, or any combination of these actions. The clawback
provision is in addition to, and not in lieu of, other actions the company may take to remedy or discipline misconduct, including termination of employment or a legal action for breach of fiduciary duty, and any actions imposed by law enforcement
agencies.
Dominion is also monitoring developments regarding the SECs proposed compensation recovery rules under the Dodd-Frank
Wall Street Reform and Consumer Protection Act. Currently, Dominion includes provisions in its long-term incentive program performance grants and restricted stock grants that subject those awards to any additional or revised clawback guidelines that
Dominion may adopt in the future in response to the Dodd-Frank rules.
TAX DEDUCTIBILITY OF
COMPENSATION
Section 162(m) of the IRC generally disallows a deduction by publicly held corporations for compensation in excess
of $1 million paid to the CEO and the next three most highly compensated officers other than the CFO. If certain requirements are met, performance-based compensation qualifies for an exemption from the IRC Section 162(m) deduction limit.
Dominion generally seeks to provide competitive executive compensation while maximizing Dominions tax deduction. While the CGN Committee considers IRC Section 162(m) tax implications when designing annual and long-term incentive
compensation programs and approving payouts under such programs, it reserves the right to approve, and in some cases has approved, non-deductible compensation when it feels that corporate objectives justify
the cost of being unable to deduct such compensation.
ACCOUNTING FOR STOCK-BASED
COMPENSATION
Dominion measures and recognizes compensation expense in accordance with the Financial Accounting Standards Board
guidance for stock-based payments, which requires that compensation expense relating to stock-based payment transactions be recognized in the financial statements based on the fair value of the equity or liability instruments issued. The CGN
Committee considers the accounting treatment of equity and performance-based compensation when approving awards.
SAY ON
PAY AND SHAREHOLDER FEEDBACK
Dominions shareholders voted on an advisory basis on
its executive compensation program (also known as Say on Pay) and approved it with a 96% vote at Dominions 2016 Annual Meeting of Shareholders, which followed an approval by an 86% vote in 2015. After considering feedback received from
shareholders and business drivers, the CGN Committee retained the overall structure of Dominions compensation program in 2016 but determined to increase the length of the performance grants performance period from two to three years,
beginning with the 2017 long-term incentive program.
EXECUTIVE COMPENSATION
SUMMARY
COMPENSATION TABLE AN OVERVIEW
The Summary Compensation Table provides information
in accordance with SEC requirements regarding compensation earned by the NEOs, stock awards made to the NEOs, as well as amounts accrued or accumulated during years reported with respect to retirement plans and other items.
The amounts reported in the Summary Compensation Table and the other tables below represent the prorated compensation amounts attributable
to each NEOs services performed for Dominion Midstream. The approximate percentage of each NEOs overall Dominion services performed for Dominion Midstream during 2016 was as follows: 0.73% for Mr. Farrell; 1.61% for
Mr. McGettrick; and 100.00% for Mr. Ruppert. Because we were considered an emerging growth company subject to reduced disclosure requirements for purposes of our 2014 executive compensation disclosures, our CEO was our only NEO for 2014
and is the only NEO for whom 2014 historical compensation information is presented in the Summary Compensation Table below.
The
following highlights some of the disclosures contained in this table. Detailed explanations regarding certain types of compensation paid to an NEO are included in the footnotes to the table.
Salary. The amounts in this column are the base salaries earned by the NEOs for the years indicated.
Stock Awards. The amounts in this column reflect the grant date fair value of the stock awards for accounting purposes for the
respective year. Stock awards are reported in the year in which the awards are granted regardless of when or if the awards vest.
Non-Equity Incentive Plan Compensation. This column includes amounts earned under two
performance-based programs: the AIP and cash-based performance grant awards under Dominions long-term incentive program. These performance programs are based on performance criteria established by the CGN Committee at the beginning of the
performance period, with actual performance scored against the pre-set criteria by the CGN Committee at the end of the performance period.
Change in Pension Value and Nonqualified Deferred Compensation Earnings. This column shows any year-over-year increases in the annual
accrual of pension and supplemental retirement benefits for NEOs. These are accruals for future benefits under the terms of the retirement plans, and are not actual payments made during the year to NEOs. The amounts disclosed reflect the annual
change in the actuarial present value of benefits under defined benefit plans sponsored by Dominion, which include Dominions tax-qualified pension plan and the nonqualified plans described in the
narrative following the Pension Benefits table. The annual change equals the difference in the accumulated amount for the current fiscal year and the accumulated amount for the prior fiscal year, generally using the same actuarial assumptions
used for Dominions audited financial statements for the applicable fiscal year. Accrued benefit calculations are based on assumptions that the NEOs would retire at the earliest age at which they are projected to become eligible for full,
unreduced pension benefits (including the effect of future service for eligibility purposes), instead of their unreduced retirement age based on current years of service. The application of these assumptions results in a greater increase in the
accumulated amount of pension benefits for certain NEOs than would result without the application of these assumptions. This method of calculation does not increase actual benefits payable at retirement but only how much of that benefit is allocated
to the increase during the years presented in the Summary Compensation Table. Please refer to the footnotes to the Pension Benefits table and the narrative following that table for additional information related to actuarial assumptions used
to calculate pension benefits.
All Other Compensation. The amounts in this column disclose compensation that is not classified
as compensation reportable in another column, including perquisites and benefits with an aggregate value of at least $10,000, the value of company-paid life insurance premiums, company matching contributions to an NEOs 401(k) Plan account, and
company matching contributions paid directly to the NEO that would be credited to the 401(k) Plan account if IRC contribution limits did not apply.
Total. The number in this column provides a single figure that represents the total compensation either earned by each NEO for the
years indicated or accrued benefits payable in later years and required to be disclosed by SEC rules in this table. It does not reflect actual compensation paid to the NEO during the year, but is the sum of the dollar values of each type of
compensation quantified in the other columns in accordance with SEC rules.
SUMMARY COMPENSATION TABLE
The following table presents information concerning compensation paid or earned by our NEOs for the years ended December 31, 2016, 2015 and 2014 as well
as the grant date fair value of stock awards and changes in pension value.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name and Principal Position |
|
Year |
|
|
Salary(1) |
|
|
Stock Awards(2) |
|
|
Non-Equity Incentive Plan Compensation(3) |
|
|
Change in
Pension Value and Nonqualified Deferred Compensation Earnings(4) |
|
|
All Other Compensation(5) |
|
|
Total |
|
Thomas F. Farrell II
Chairman, President and CEO |
|
|
2016 |
|
|
$ |
10,940 |
|
|
$ |
37,264 |
|
|
$ |
38,465 |
|
|
$ |
8,681 |
|
|
$ |
1,393 |
|
|
$ |
96,743 |
|
|
|
2015 |
|
|
|
16,211 |
|
|
|
49,489 |
|
|
|
39,714 |
|
|
|
|
|
|
|
2,010 |
|
|
|
107,424 |
|
|
|
2014 |
|
|
|
8,530 |
|
|
|
34,441 |
|
|
|
60,656 |
|
|
|
n/a |
|
|
|
1,064 |
|
|
|
104,961 |
|
Mark F. McGettrick
Executive Vice President and CFO |
|
|
2016 |
|
|
|
13,711 |
|
|
|
21,679 |
|
|
|
28,161 |
|
|
|
14,903 |
|
|
|
1,716 |
|
|
|
80,170 |
|
|
|
2015 |
|
|
|
15,670 |
|
|
|
22,424 |
|
|
|
20,291 |
|
|
|
407 |
|
|
|
1,903 |
|
|
|
60,695 |
|
Paul E. Ruppert
Senior Vice President and President Dominion Midstream Operations |
|
|
2016 |
|
|
|
336,537 |
|
|
|
150,070 |
|
|
|
286,895 |
|
|
|
883,109 |
|
|
|
44,059 |
|
|
|
1,700,670 |
|
Note: The NEOs perform services for more than one subsidiary of Dominion. Compensation included in this table reflects only
the applicable portion related to their service for Dominion Midstream for the years presented.
(1) |
Effective March 1, 2016, Messrs. Farrell and McGettrick each received a 3% base salary increase, and Mr. Ruppert received a 17% increase in connection with his promotion to Senior Vice President and
President Dominion Midstream Operations. |
(2) |
The amounts in this column reflect the grant date fair value of stock awards for the respective year of grant in accordance with FASB guidance for share-based payments. Dominion did not grant any stock options in
2016. See also Note 19 to the Consolidated Financial Statements in Dominions 2016 Annual Report on Form 10-K for more information on the valuation of stock-based awards, the Grants of Plan-Based Awards
table for stock awards granted in 2016, and the Outstanding Equity Awards at Fiscal Year-End table for a listing of all outstanding equity awards as of December 31, 2016. |
(3) |
The 2016 amounts in this column include the payout under Dominions 2016 AIP and 2015 Performance Grant Awards. All of the NEOs received 100% funding of their 2016 AIP target awards and 100% payout scores for
accomplishment of their goals. The 2016 AIP payout amounts were as follows: Mr. Farrell: $13,741; Mr. McGettrick: $13,777; and Mr. Ruppert: $172,445. See CD&A for additional information on the 2016 AIP and the Grants of Plan-Based
Awards table for the range of each NEOs potential award under the 2016 AIP. The 2015 Performance Grant Award was issued on February 1, 2015 and the payout amount was determined based on achievement of performance goals for the performance
period ended December 31, 2016. Payouts can range from 0% to 200% of the target amount. The actual payout was 76.3% of the target amount. The 2015 Performance Grant payout amounts were as follows: Mr. Farrell: $24,723; Mr. McGettrick:
$14,383; and Mr. Ruppert: $114,450. See 2015 Performance Grant Payout section of CD&A for additional information on the 2015 Performance Grants. The 2015 amount for Mr. Farrell reflects both the 2015 AIP and the 2014 Performance Grant
payouts. |
(4) |
All amounts in this column are for the aggregate change in the actuarial present value of the NEOs accumulated benefit under Dominions qualified Pension Plan and nonqualified executive retirement plans.
There are no above-market earnings on nonqualified deferred compensation plans. These accruals are not directly in relation to final payout potential, and can vary significantly year over year based on (i) promotions and corresponding changes
in salary; (ii) other one-time adjustments to salary or incentive target for market or other reasons; (iii) actual age versus predicted age at retirement; (iv) discount rate used to determine
present value of benefit; and (v) other relevant factors. Reductions in the actuarial present value of an NEOs accumulated pension benefits are reported as $0.No amount is shown in this column for Mr. Farrell in 2014 because
consistent with reporting requirements for emerging growth companies that were previously applicable to us, we did not include this column in the Summary Compensation Table in our 2014 Annual Report on Form
10-K. |
|
A change in the discount rate can be a significant factor in the change reported in this column. A decrease in the discount rate results in an increase in the present value of the accumulated benefit without any
increase in the benefits payable to the NEO at retirement and an increase in the discount rate has the opposite effect. The discount rate used in determining the present value of the accumulated benefit decreased from 4.96% used as of
December 31, 2015 to a discount rate of 4.46% used as of December 31, 2016. The increase in present value attributed solely to the change in discount rate was as follows: Mr. Farrell: $6,938; Mr. McGettrick: $9,744; and
Mr. Ruppert: $274,817. |
(5) |
All Other Compensation amounts for 2016 are as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
Executive Perquisites(a) |
|
|
Life Insurance Premiums |
|
|
Employee 401(k) Plan Match(b) |
|
|
Company Match Above IRS Limits(c) |
|
|
Total All Other Compensation |
|
Thomas F. Farrell II |
|
$ |
741 |
|
|
$ |
215 |
|
|
$ |
77 |
|
|
$ |
360 |
|
|
$ |
1,393 |
|
Mark F. McGettrick |
|
|
520 |
|
|
|
648 |
|
|
|
171 |
|
|
|
377 |
|
|
|
1,716 |
|
Paul E. Ruppert |
|
|
24,434 |
|
|
|
6,163 |
|
|
|
10,600 |
|
|
|
2,862 |
|
|
|
44,059 |
|
Note: The NEOs perform services for more than one subsidiary of Dominion. Compensation included in this table reflects
only the applicable portion related to their service for Dominion Midstream for the year presented.
(a) |
Unless noted, the amounts in this column for all NEOs are comprised of the following: personal use of company vehicle and financial, planning and health and wellness allowance. For Mr. Farrell the amount in this
column also includes $625 for the value of his personal use of the corporate aircraft. For personal flights, all direct operating costs are included in calculating aggregate incremental cost. Direct operating costs include the following: fuel,
airport fees, catering, ground transportation and crew expenses (any food, lodging and other costs). The fixed costs of owning the aircraft and employing the crew are not taken into consideration, as 96% of the use of the corporate aircraft is for
business purposes. The CGN Committee has directed Mr. Farrell to use corporate aircraft for personal travel. |
(b) |
Employees initially hired before 2008 who contribute to the 401(k) Plan receive a matching contribution of 50 cents for each dollar contributed up to 6% of compensation (subject to IRS limits) for employees who have
less than 20 years of service, and 67 cents for each dollar contributed up to 6% of compensation (subject to IRS limits) for employees who have 20 or more years of service. All NEOs were hired prior to 2008. |
(c) |
Represents each payment of lost 401(k) Plan matching contribution due to IRS limits. |
GRANTS OF PLAN-BASED AWARDS
The following table provides information about stock awards and non-equity incentive awards granted to our NEOs during
the year ended December 31, 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name and Principal Position |
|
Grant Date(1) |
|
|
Grant Approval Date(1) |
|
|
Estimated Future Payouts Under Non-Equity Incentive Plan Awards |
|
|
All Other Stock Awards Number of Shares of Stock or Units |
|
|
Grant Date Fair Value of Stock and Options Award(1)(4)(6) |
|
|
|
|
Threshold |
|
|
Target |
|
|
Maximum |
|
|
|
Thomas F. Farrell II |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 Annual Incentive Plan(2) |
|
|
|
|
|
|
|
|
|
$ |
|
|
|
$ |
13,741 |
|
|
$ |
27,482 |
|
|
|
|
|
|
|
|
|
2016 Cash Performance Grant(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37,263 |
|
|
|
74,527 |
|
|
|
|
|
|
|
|
|
2016 Restricted Stock Grant(4) |
|
|
2/3/2016 |
|
|
|
1/21/2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
533 |
|
|
$ |
37,264 |
|
Mark F. McGettrick |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 Annual Incentive Plan(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,777 |
|
|
|
27,555 |
|
|
|
|
|
|
|
|
|
2016 Cash Performance Grant(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,678 |
|
|
|
43,357 |
|
|
|
|
|
|
|
|
|
2016 Restricted Stock Grant(4) |
|
|
2/3/2016 |
|
|
|
1/21/2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
310 |
|
|
|
21,679 |
|
Paul E. Ruppert |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 Annual Incentive Plan(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172,445 |
|
|
|
344,890 |
|
|
|
|
|
|
|
|
|
2016 Cash Performance Grant(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
150,000 |
|
|
|
300,000 |
|
|
|
|
|
|
|
|
|
2016 Restricted Stock Grant(4) |
|
|
2/3/2016 |
|
|
|
1/21/2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,146 |
|
|
|
150,070 |
|
Note: The NEOs perform services for more than one subsidiary of Dominion. Compensation included in this table reflects
only the applicable portion related to their service for Dominion Midstream for the year presented.
(1) |
On January 21, 2016, the CGN Committee approved the 2016 long-term incentive compensation awards for Dominion officers, which consisted of a restricted stock grant and a cash performance grant. The 2016
restricted stock award was granted on February 3, 2016. Under the 2014 Incentive Compensation Plan, fair market value is defined as the closing price of Dominion common stock on the date of grant or, if that day is not a trading day, on the
most recent trading day immediately preceding the date of grant. The fair market value for the February 3, 2016 restricted stock grant was $69.93 per share, which was Dominions closing stock price on the grant date. |
(2) |
Amounts represent the range of potential payouts under the 2016 AIP. Actual amounts paid under the 2016 AIP are found in the Non-Equity Incentive Plan Compensation column of
the Summary Compensation Table. Under the AIP, officers are eligible for an annual performance-based award. The CGN Committee establishes target awards for each NEO based on his salary level and expressed as a percentage of the individual NEOs
base salary. The target award is the amount of cash that will be paid if the plan is fully funded and payout goals are achieved. For the 2016 AIP, funding was based on the achievement of consolidated operating earnings goals with the maximum funding
capped at 200%, as explained under the Annual Incentive Plan section of the CD&A. |
(3) |
Amounts represent the range of potential payouts under the 2016 performance grant of the long-term incentive program. Payouts can range from 0% to 200% of the target award. Awards will be paid by March 15, 2018
depending on the achievement of performance goals for the two-year period ending December 31, 2017. The amount earned will depend on the level of achievement of two performance metrics: TSR50% and
ROIC50%. TSR measures Dominions share performance for the two-year period ended December 31, 2017 relative to the TSR of the companies that are listed as members of the Philadelphia Stock
Exchange Utility Index as of the end of the performance period. ROIC goal achievement will be scored against 2016 and 2017 budget goals. |
The performance grant is forfeited in its entirety if an officer voluntarily terminates employment or is terminated with cause before the
vesting date. The grants have prorated vesting for retirement, termination without cause, death or disability. In the case of retirement, prorated vesting will not occur if the CEO (or, for the CEO, the CGN Committee) determines the officers
retirement is detrimental to the company. Payout for an officer who retires or whose employment is terminated without cause is made following the end of the performance period so that the officer is rewarded only to the extent the performance goals
are achieved. In the case of death or disability, payout is made as soon as possible to facilitate the administration of the officers estate or financial planning. The payout amount will be the greater of the officers target award or an
amount based on the predicted performance used for compensation cost disclosure purposes in Dominions financial statements.
In the event of a change in control, the performance grant is vested in its entirety and payout of the performance grant will occur as soon
as administratively feasible following the change in control date at an amount that is the greater of an officers target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominions
financial statements.
(4) |
The 2016 restricted stock grant fully vests at the end of three years. The restricted stock grant is forfeited in its entirety if an officer voluntarily terminates employment or is terminated with cause before the
vesting date. The restricted stock grant provides for prorated vesting if an officer retires, dies, becomes disabled, is terminated without cause, or if there is a change in control. In the case of retirement, prorated vesting will not occur if the
CEO (or for the CEO, the CGN Committee) determines the officers retirement is detrimental to the company. In the event of a change in control, prorated vesting is provided as of the change in control date, and full vesting if an officers
employment is terminated, or constructively terminated by the successor entity following the change in control date but before the scheduled vesting date. Dividends on the restricted shares are paid during the restricted period at the same rate
declared by Dominion for all shareholders. |
OUTSTANDING EQUITY AWARDS AT
FISCAL YEAR-END
The following table summarizes the equity awards made to NEOs that were outstanding at
December 31, 2016. These equity awards are restricted shares of Dominion common stock. There were no unexercised or unexercisable option awards outstanding for any of our NEOs at December 31, 2016.
|
|
|
|
|
|
|
|
|
Name |
|
Stock Awards |
|
|
Number of Shares or Units of Stock that Have Not Vested (#) |
|
|
Market Value of Shares or Units of Stock
that Have Not Vested(1) ($) |
|
Thomas F. Farrell II |
|
|
450 |
(2) |
|
$ |
34,492 |
|
|
|
421 |
(3) |
|
|
32,277 |
|
|
|
533 |
(4) |
|
|
40,813 |
|
Mark F. McGettrick |
|
|
278 |
(2) |
|
|
21,261 |
|
|
|
245 |
(3) |
|
|
18,778 |
|
|
|
310 |
(4) |
|
|
23,744 |
|
Paul E. Ruppert |
|
|
2,209 |
(2) |
|
|
169,187 |
|
|
|
1,951 |
(3) |
|
|
149,427 |
|
|
|
2,146 |
(4) |
|
|
164,362 |
|
Note: The NEOs perform services for more than one subsidiary of Dominion. Compensation included in this
table reflects only the applicable portion related to their service for Dominion Midstream for the year presented.
(1) |
The market value is based on closing stock price of $76.59 on December 30, 2016. |
(2) |
Shares vested on February 1, 2017. |
(3) |
Shares scheduled to vest on February 1, 2018. |
(4) |
Shares scheduled to vest on February 1, 2019. |
OPTION EXERCISES
AND STOCK VESTED
The following table provides information about the value realized by NEOs during the
year ended December 31, 2016, on vested restricted stock awards. There were no option exercises by NEOs in 2016.
|
|
|
|
|
|
|
|
|
Name |
|
Stock Awards |
|
|
Number of Shares Acquired on Vesting |
|
|
Value Realized on Vesting |
|
Thomas F. Farrell II |
|
|
565 |
|
|
$ |
39,621 |
|
Mark F. McGettrick |
|
|
348 |
|
|
|
24,423 |
|
Paul E. Ruppert |
|
|
2,770 |
|
|
|
194,399 |
|
Note: The NEOs perform services for more than one subsidiary of Dominion. Compensation included in this table reflects
only the applicable portion related to their service for Dominion Midstream.
PENSION
BENEFITS
The following table shows the actuarial present value of accumulated benefits payable to our NEOs, together with the number
of years of benefit service credited to each NEO, under the plans listed in the table. Values are computed at December 31, 2016, using the same interest rate and mortality assumptions used in determining the aggregate pension obligations
disclosed in the companys financial statements. The years of credited service and the present value of accumulated benefits were determined by plan actuaries, using the appropriate accrued service, pay and other assumptions similar to those
used for accounting and disclosure purposes. Please refer to Actuarial Assumptions Used to Calculate Pension Benefits for detailed information regarding these assumptions.
|
|
|
|
|
|
|
|
|
|
|
|
|
Plan Name |
|
Number of Years Credited Service(1) |
|
|
Present Value of Accumulated Benefit(2) |
|
Thomas F. Farrell II |
|
Pension Plan |
|
|
21.00 |
|
|
$ |
11,130 |
|
|
Benefit Restoration Plan |
|
|
30.00 |
|
|
|
94,415 |
|
|
Supplemental Retirement Plan |
|
|
30.00 |
|
|
|
99,516 |
|
Mark F. McGettrick |
|
Pension Plan |
|
|
30.00 |
|
|
|
35,391 |
|
|
Benefit Restoration Plan |
|
|
30.00 |
|
|
|
101,285 |
|
|
Supplemental Retirement Plan |
|
|
30.00 |
|
|
|
121,313 |
|
Paul E. Ruppert |
|
Pension Plan |
|
|
29.58 |
|
|
|
1,755,801 |
|
|
Benefit Restoration Plan |
|
|
29.58 |
|
|
|
248,764 |
|
|
Supplemental Retirement Plan |
|
|
29.58 |
|
|
|
1,417,924 |
|
Note: The NEOs perform services for more than one subsidiary of Dominion. Compensation included in this table reflects only
the applicable portion related to their service for Dominion Midstream for the year presented.
(1) |
Years of credited service shown in this column for the Pension Plan are actual years accrued by an NEO from his date of participation to December 31, 2016. Service for the Benefit Restoration Plan and the
Supplemental Retirement Plan is the NEOs actual credited service at December 31, 2016 plus any potential total credited service to the plan maximum, including any extra years of credited service granted to Messrs. Farrell and McGettrick
by the CGN Committee for the purpose of calculating benefits under these plans. Please refer to the narrative below and under Dominion Retirement Benefit Restoration Plan, Dominion Executive Supplemental Retirement Plan and Potential Payments Upon
Termination or Change In Control for information about the requirements for receiving extra years of credited service and the amount credited, if any, for each NEO. |
(2) |
The amounts in this column are based on actuarial assumptions that all of the NEOs would retire at the earliest age they become eligible for unreduced benefits, including any additional years of credited age. In
addition, for purposes of calculating the Benefit Restoration Plan benefits for Messrs. Farrell and McGettrick, the amounts reflect additional credited years of service granted to them pursuant to their agreements with the company (see Dominion
Retirement Benefit Restoration Plan). If the amounts in this column did not include the additional years of credited service, the present value of the Benefit Restoration Plan benefit would be $35,439 lower for Mr. Farrell and $17,208 lower for
Mr. McGettrick. Pension Plan and Supplemental Retirement Plan benefits amounts are not augmented by the additional service credit assumptions. |
Dominion Pension Plan
The Dominion Pension Plan is a tax-qualified defined benefit pension plan. All of the NEOs were hired before 2008 and
therefore participate in the final average earnings formula of the Pension Plan. A cash balance formula applies to non-union employees hired on or after January 1, 2008.
The final average earnings formula of the Pension Plan provides unreduced
retirement benefits at termination of employment at or after age 65 or, with three years of service, at age 60. A participant who has attained age 55 with three years of service may elect early retirement benefits at a reduced amount. If a
participant retires between ages 55 and 60, the benefit is reduced 0.25% per
month for each month after age 58 and before age 60, and reduced 0.50% per month for each month between ages 55 and 58. All of the NEOs have more than three years of service.
The basic pension benefit is calculated using a formula based on (1) age at retirement; (2) final average earnings;
(3) estimated Social Security benefits; and (4) credited service. Final average earnings are the average of the participants 60 highest consecutive months of base pay during the last 120 months worked. Final average earnings do not
include compensation payable under the AIP, the value of equity awards, gains from the exercise of stock options, long-term cash incentive awards, perquisites, or any other form of compensation other than base pay.
Credited service is measured in months, up to a maximum of 30 years of credited service. The estimated Social Security benefit taken into
account is the assumed Social Security benefit payable starting at age 65 or actual retirement date, if later, assuming that the participant has no further employment after leaving Dominion. These factors are then applied in a formula.
The formula has different percentages for credited service through December 31, 2000, and on and after January 1, 2001. The
benefit is the sum of the amounts from the following two formulas.
|
|
|
|
|
|
|
For Credited Service Through December 31, 2000 |
|
|
2.03% times Final Average
Earnings times Credited Service before 2001 |
|
Minus |
|
2.00% times estimated Social Security benefit times Credited Service before 2001 |
|
|
|
|
|
|
|
For Credited Service On or After January 1, 2001 |
1.80% times Final Average Earnings times Credited Service after 2000 |
|
Minus |
|
1.50% times estimated Social Security benefit times Credited Service after 2000 |
Credited service is limited to a total of 30 years for all parts of the formula and credited service after 2000 is limited to
30 years minus credited service before 2001.
Benefit payment options are (1) a single life annuity or (2) a choice of a 50%,
75% or 100% joint and survivor annuity. A Social Security leveling option is available with any of the benefit forms. The normal form of benefit is a single life annuity for unmarried participants and a 50% joint and survivor annuity for
married participants. All of the payment options are actuarially equivalent in value to the single life annuity. The Social Security leveling option pays a larger benefit equal to the estimated Social Security benefit until the participant is age 62
and then reduced payments after age 62.
Participants in the final average earnings formula also receive a special
retirement account, which is in addition to the basic pension benefit. The special retirement account is credited with 2% of base pay each month as well as interest based on the 30-year Treasury bond rate set
annually (3.26% in 2015). The special retirement account can be paid in a lump sum or paid in the form of an annuity benefit.
A
participant becomes vested in his or her benefit after completing three years of service. A vested participant who terminates employment before age 55 can start receiving benefit payments calculated using terminated vested reduction factors at any
time after attaining age 55. If payments begin before age 65, then the following reduction factors for the portion of the benefits earned after 2000 apply: age 64 9%; age 63 16%; age 62 23%; age 61 30%; age 60
35%; age 59 40%; age 58 44%; age 57 48%; age 56 52%; and age 55 55%.
The IRC limits the amount of compensation that may be included in determining pension
benefits under qualified pension plans. For 2016, the compensation limit was $265,000. The IRC also limits the total annual benefit that may be provided to a participant under a qualified defined benefit plan. For 2016, this limitation was the
lesser of (i) $210,000 or (ii) the average of the participants compensation during the three consecutive years in which the participant had the highest aggregate compensation.
Dominion Retirement Benefit Restoration Plan
The BRP is a
nonqualified defined benefit pension plan designed to make up for benefit reductions under the Dominion Pension Plan due to the limits imposed by the IRC.
A Dominion employee is eligible to participate in the BRP if (1) he or she is a member of management or a highly compensated employee,
(2) his or her Dominion Pension Plan benefit is or has been limited by the IRC compensation or benefit limits, and (3) he or she has been designated as a participant by the CGN Committee. A participant remains a participant until he or she
ceases to be eligible for any reason other than retirement or until his or her status as a participant is revoked by the CGN Committee.
Upon retirement, a participants BRP benefit is calculated using the same formula (except that the IRS salary limit is not applied)
used to determine the participants default annuity form of benefit under the Dominion Pension Plan (single life annuity for unmarried participants and 50% joint and survivor annuity for married participants), and then subtracting the benefit
the participant is entitled to receive under the Dominion Pension Plan. To accommodate the enactment of Section 409A of the IRC, the portion of a participants BRP benefit that had accrued as of December 31, 2004, is frozen, but the
calculation of the overall restoration benefit is not changed.
Participants may choose to receive the portion of the restoration
benefit that accrued before 2005 as a single lump sum cash payment or in the same annuity form elected by the participant under the Dominion Pension Plan. For the portion of the benefit that accrued in 2005 or later, benefits must be paid in a lump
sum. The lump sum calculation includes an amount approximately equivalent to the amount of taxes the participant will owe on the lump sum payment so that the participant will have sufficient funds, on an
after-tax basis, to purchase an annuity contract.
A participant who terminates employment
before he or she is eligible for benefits under the Pension Plan generally is not entitled to a restoration benefit. Messrs. Farrell and McGettrick have been granted age and service credits for purposes of calculating their BRP benefits. Per his
letter agreement, Mr. Farrell was granted 30 years of service when he reached age 60. Mr. McGettrick, having attained age 50, has earned benefits calculated based on five additional years of age and service. For each of these NEOs,
the additional years of service count toward determining both the amount of benefits and the eligibility to receive them. For additional information regarding service credits, see Dominion Executive Supplemental Retirement Plan.
If a vested participant dies when he or she is retirement eligible (on or after age 55), the participants beneficiary will receive the
restoration benefit in a single lump sum payment. If a participant dies while employed but before he or she has attained age 55 and the participant is married at the time of death, the participants spouse will receive a restoration benefit
calculated in the
same way (except that the IRS salary limit is not applied) as the 50% qualified pre-retirement survivor annuity payable under the Pension Plan and paid in
a lump sum payment.
Dominion Executive Supplemental Retirement Plan
The Dominion ESRP is a nonqualified defined benefit plan that provides for an annual retirement benefit equal to 25% of a participants final cash
compensation (base salary plus target annual incentive award) payable for a period of 10 years or, for certain participants designated by the CGN Committee, for the participants lifetime. To accommodate the enactment of Section 409A of
the IRC, the portion of a participants ESRP benefit that had accrued as of December 31, 2004, is frozen, but the calculation of the overall benefit is not changed. Effective July 1, 2013, the ESRP was closed to any new participants.
Before the plan was closed, a Dominion employee became eligible to participate in the ESRP if (1) he or she was a member of
management or a highly compensated employee, and (2) he or she had been designated as a participant by the CGN Committee. A participant remains a participant until he or she ceases to be eligible for any reason other than retirement or until
his or her status as a participant is revoked by the CGN Committee.
A participant is entitled to the full ESRP benefit if he or she
separates from service with Dominion after reaching age 55 and achieving 60 months of service. A participant who separates from service with Dominion with at least 60 months of service but who has not yet reached age 55 is entitled to a
reduced, prorated retirement benefit. A participant who separates from service with Dominion with fewer than 60 months of service is generally not entitled to an ESRP benefit unless the participant separated from service on account of disability or
death.
Under the ESRP, a participant may elect to receive the portion of his or her benefit that had accrued as of December 31,
2004, in a lump sum or in monthly installments. Any portion of the ESRP benefit that accrued after December 31, 2004, must be paid in the form of a single lump sum cash payment. The lump sum calculation includes an amount approximately
equivalent to the amount of taxes the participant will owe on the lump sum payment so that the participant will have sufficient funds, on an after-tax basis, to purchase a
10-year or lifetime annuity contract.
All of the NEOs are currently entitled to a full ESRP
retirement benefit. Based on the terms of their individual letter agreements, Messrs. Farrell and McGettrick will receive an ESRP benefit calculated as a lifetime benefit. Mr. McGettrick has earned five years of additional age and service
credit for purposes of computing his retirement benefits and eligibility for benefits under the ESRP, long-term incentive grants, and retiree medical and life insurance plans as he has met the requirement of remaining employed until he attained age
50.
Actuarial Assumptions Used to Calculate Pension Benefits
Actuarial assumptions used to calculate Pension Plan benefits are prescribed by the terms of the Pension Plan based on the IRC and Pension Benefit Guaranty
Corporation (PBGC) requirements. The present value of the accumulated benefit is calculated using actuarial and other factors as determined by the plan actuaries and approved by Dominion. Actuarial assumptions used for the December 31, 2016,
benefit calculations shown in the Pension Benefits table include a discount rate of 4.46% to determine the present value of the future benefit obligations for the Pension
Plan, BRP and ESRP and a lump sum interest rate of 3.71% to estimate the lump sum values of BRP and ESRP benefits. Each NEO is assumed to retire at the earliest age at which he is projected to
become eligible for full, unreduced pension benefits. For purposes of estimating future eligibility for unreduced Pension Plan and ESRP benefits, the effect of future service is considered. Each NEO is assumed to commence Pension Plan payments at
the same age as BRP payments. The longevity assumption used to determine the present value of benefits is the same assumption used for financial reporting of the Pension Plan liabilities, with no assumed mortality before retirement age. Mortality
rates are developed from actual and projected plan experience for postretirement benefit plans. Dominions actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion considers
both standard mortality tables and improvement factors as well as the plans actual experience when selecting a best estimate. During 2016, Dominion conducted a new experience study as scheduled and, as a result, updated its mortality
assumptions. For BRP and ESRP benefits, other actuarial assumptions include an assumed tax rate of 42%. BRP and ESRP benefits are assumed to be paid as lump sums; pension plan benefits are assumed to be paid as annuities.
The discount rate for calculating lump sum BRP and ESRP payments at the time an officer terminates employment is selected by Dominions
Administrative Benefits Committee and adjusted periodically. For 2016, a 3.16% discount rate was used to determine the lump sum payout amounts. This discount rate was selected based on a rolling average of the blended rate published by the PBGC in
October of the previous five years.
NONQUALIFIED DEFERRED COMPENSATION
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
Aggregate Earnings
in Last FY (as of 12/31/2016)* |
|
|
Aggregate Withdrawals/ Distributions
(as of 12/31/2016) |
|
|
Aggregate Balance
at Last FYE (as of 12/31/2016) |
|
Thomas F. Farrell II |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Mark F. McGettrick |
|
|
|
|
|
|
|
|
|
|
|
|
Paul E. Ruppert |
|
|
34,205 |
|
|
|
|
|
|
|
232,976 |
|
*No preferential earnings are paid and therefore no earnings from these plans are included in the Summary Compensation
Table.
Note: The NEOs perform services for more than one subsidiary of Dominion. Compensation included in this table reflects only the applicable
portion related to their service for Dominion Midstream for the year presented.
At this time, Dominion does not offer any
nonqualified elective deferred compensation plans to its officers or other employees. The Nonqualified Deferred Compensation table reflects the balance for the Dominion Resources, Inc. Executives Deferred Compensation Plan (Frozen
Deferred Compensation Plan), which was offered to Dominion officers and other highly compensated employees before it was frozen as of December 31, 2004.
Frozen Deferred Compensation Plan
The Frozen Deferred Compensation
Plan includes amounts previously deferred from one of the following categories of compensation: (i) salary; (ii) bonus; (iii) vested restricted stock; and (iv) gains from stock option exercises. The plan also provided for company
contributions of lost company 401(k) Plan match
contributions and transfers from several CNG deferred compensation plans. The Frozen Deferred Compensation Plan offers 29 investment funds for the plan balances, including a Dominion Resources
Stock Fund. Participants may change investment elections on any business day. Any vested restricted stock and gains from stock option exercises that were deferred were automatically allocated to the Dominion Resources Stock Fund and this allocation
cannot be changed. Earnings are calculated based on the performance of the underlying investment fund. The Dominion Resources Stock Fund had a rate of return for 2016 of 17.7%.
The default benefit commencement date is February 28 after the year in which the participant retires, but the participant may select a
different benefit commencement date in accordance with the plan. Participants may change their benefit commencement date election; however, a new election must be made at least six months before an existing benefit commencement date. Withdrawals
less than six months prior to an existing benefit commencement date are subject to a 10% early withdrawal penalty. Account balances must be fully paid out no later than the February 28 that is 10 calendar years after a participant retires or
becomes disabled. If a participant retires from the company, he or she may continue to defer an account balance provided that the total balance is distributed by this deadline. In the event of termination of employment for reasons other than death,
disability or retirement before an elected benefit commencement date, benefit payments will be distributed in a lump sum as soon as administratively practicable. Hardship distributions, prior to an elected benefit commencement date, are available
under certain limited circumstances.
Participants may elect to have their benefit paid in a lump sum payment or equal annual
installments over a period of whole years from one to 10 years. Participants have the ability to change their distribution schedule for benefits under the plan by giving six months notice to the plan administrator. Once a participant begins
receiving annual installment payments, the participant can make a one-time election to either (1) receive the remaining account balance in the form of a lump sum distribution or (2) change the
remaining installment payment period. Any election must be approved by the company before it is effective. All distributions are made in cash with the exception of the Deferred Restricted Stock Account and the Deferred Stock Option Account, which
are distributed in the form of Dominion common stock.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN
CONTROL
Under certain circumstances, Dominion provides benefits to eligible employees upon termination of employment, including a
termination of employment involving a change in control of the company, that are in addition to termination benefits for other employees in the same situation.
Change in Control
As discussed in the Employee and Executive
Benefits section of the CD&A, Dominion has entered into an Employment Continuity Agreement with each of its officers, including the NEOs. Each agreement has a three-year term and is automatically extended annually for an additional year,
unless cancelled by Dominion.
The Employment Continuity Agreements require two triggers for the payment of most benefits:
|
|
There must be a change in control; and |
|
|
The executive must either be terminated without cause, or terminate his or her employment with the surviving company after a constructive termination. Constructive termination means the executives salary,
incentive compensation or job responsibility is reduced after a change in control or the executives work location is relocated more than 50 miles without his or her consent. |
For purposes of the Employment Continuity Agreements, a change in control will occur if (i) any person or group becomes a beneficial
owner of 20% or more of the combined voting power of Dominion voting stock or (ii) as a direct or indirect result of, or in connection with, a cash tender or exchange offer, merger or other business combination, sale of assets, or contested
election, the directors constituting the Dominion Board before any such transaction cease to represent a majority of Dominions or its successors Board within two years after the last of such transactions.
If an executives employment following a change in control is terminated without cause or due to a constructive termination, the
executive will become entitled to the following termination benefits:
|
|
Lump sum severance payment equal to three times base salary plus AIP award (determined as the greater of (i) the target annual award for the current year or (ii) the highest actual AIP payout for any one of
the three years preceding the year in which the change in control occurs). |
|
|
Full vesting of benefits under ESRP and BRP with five years of additional credited age and five years of additional credited service from the change in control date. |
|
|
Group-term life insurance. If the officer elects to convert group-term insurance to an individual policy, the company pays the premiums for 12 months. |
|
|
Executive life insurance. Premium payments will continue to be paid by the company until the earlier of: (1) the fifth anniversary of the termination date, or (2) the later of the tenth anniversary of the
policy or the date the officer attains age 64. |
|
|
Retiree medical coverage will be determined under the relevant plan with additional age and service credited as provided under an officers letter agreement (if any) and including five additional years credited to
age and five additional years credited to service. |
|
|
Outplacement services for one year (up to $25,000). |
|
|
If any payments are classified as excess parachute payments for purposes of Section 280G of the IRC and the executive incurs the excise tax, the company will pay the executive an amount equal to the 280G excise tax
plus a gross-up multiple. |
In January 2013, the CGN Committee approved the
elimination of the excise tax gross-up provision included in the Employment Continuity Agreement for any new officer elected after February 1, 2013.
The terms of awards made under the long-term incentive program, rather than the terms of Employment Continuity Agreements, will determine
the vesting of each award in the event of a change in control. These provisions are described in the Long-Term Incentive Program section of the CD&A and footnotes to the Grants of Plan-Based Awards table.
Other Post Employment Benefit for Mr. Farrell
Mr. Farrell will become entitled to a payment of one times salary upon his retirement as consideration for his agreement not to compete with the company
for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.
The following table provides the incremental payments that would be earned by each NEO if his
employment had been terminated, or constructively terminated, at December 31, 2016. These benefits are in addition to retirement benefits that would be payable on any termination of employment. Please refer to the Pension Benefits table
for information related to the present value of accumulated retirement benefits payable to the NEOs.
Incremental Payments Upon Termination or Change
in Control
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
Non-Qualified Plan Payment |
|
|
Restricted Stock(1) |
|
|
Performance Grant(1) |
|
|
Non-Compete Payments (2) |
|
|
Severance Payments |
|
|
Retire Medical and Executive Life Insurance(3) |
|
|
Out-placement Services |
|
|
Excise Tax & Tax Gross-Up |
|
|
Total |
|
Thomas F. Farrell II(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement |
|
$ |
|
|
|
$ |
66,624 |
|
|
$ |
17,822 |
|
|
$ |
10,993 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
95,439 |
|
Death/Disability |
|
|
|
|
|
|
66,624 |
|
|
|
17,822 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84,446 |
|
Change in Control(5) |
|
|
3,530 |
|
|
|
40,957 |
|
|
|
19,442 |
|
|
|
|
|
|
|
74,203 |
|
|
|
|
|
|
|
182 |
|
|
|
|
|
|
|
138,314 |
|
Mark F. McGettrick(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement |
|
|
|
|
|
|
39,921 |
|
|
|
10,368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,289 |
|
Death/Disability |
|
|
|
|
|
|
39,921 |
|
|
|
10,368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,289 |
|
Change in Control(5) |
|
|
4,182 |
|
|
|
23,863 |
|
|
|
11,310 |
|
|
|
|
|
|
|
82,665 |
|
|
|
|
|
|
|
403 |
|
|
|
|
|
|
|
122,423 |
|
Paul E. Ruppert |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Termination |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Death/Disability |
|
|
|
|
|
|
310,036 |
|
|
|
71,739 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
381,775 |
|
Change in
Control(5) |
|
|
1,772,967 |
|
|
|
482,977 |
|
|
|
150,000 |
|
|
|
|
|
|
|
1,552,001 |
|
|
|
31,400 |
|
|
|
25,000 |
|
|
|
2,020,535 |
|
|
|
6,109,880 |
|
Note: The NEOs perform services for more than one subsidiary of Dominion. Compensation included in this table reflects only
the applicable portion related to their service for Dominion Midstream for the year presented.
(1) |
Grants made in 2014, 2015 and 2016 under the long-term incentive program vest pro rata upon termination without cause, death or disability. These grants vest pro rata upon retirement provided the CEO of Dominion (or
in the case of the CEO, the CGN Committee) determines the NEOs retirement is not detrimental to the company; amounts shown assume this determination was made. The amounts shown in the restricted stock column are based on the closing stock
price of $76.59 on December 30, 2016. |
(2) |
Pursuant to a letter agreement dated February 28, 2003, Mr. Farrell will be entitled to a special payment of one times salary upon retirement in exchange for a
two-year non-compete agreement. Mr. Farrell would not be entitled to this non-compete payment in the event of his death.
|
(3) |
Amounts in this column represent the value of the annual incremental benefit the NEOs would receive for executive life insurance and retiree medical coverage. Messrs. Farrell and McGettrick are eligible for
retiree medical and executive life insurance upon any termination because they are retirement eligible and have completed 10 years of service. |
(4) |
Messrs. Farrell and McGettrick are eligible for retirement, and this table above assumes they would each retire in connection with any termination event. |
(5) |
Change in control amounts assume that a change in control and a termination or constructive termination takes place on December 31, 2016. The amounts indicated upon a change in control are the incremental
amounts attributable to five years of additional age and service credited pursuant to the Employment Continuity Agreements that each NEO would receive over the amounts payable upon a retirement. The restricted stock and performance grant amounts
represent the value of the awards upon a change in control that is above what would be received upon a retirement or termination. |
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
We are not required to have, and do not have, a compensation committee. As explained above in the introduction to this Item, the Board of Directors
of our general partner does not make any decisions regarding the compensation of our executive officers, except with respect to potential awards under the Dominion Midstream LTIP. All such decisions are made by the CGN Committee, without any input
from us or our general partner. The CGN Committee is comprised solely of independent directors, and no Dominion or Dominion Midstream officers participate in its deliberations.
No executive officer of Dominion or Dominion Midstream serves as a member of another compensation committee or on the Board of Directors of
any company of which a member of the CGN Committee, Dominions Board of Directors or the Board of Directors of our general partner serves as an executive officer.
NON-EMPLOYEE
DIRECTOR COMPENSATION TABLE
Directors of our general partner who are not officers of the general partner
or any of its affiliates or employees of Dominion or any of its affiliates receive compensation as non-employee directors, which consisted of an annual cash retainer of $70,000 and an annual equity retainer
equal to $80,000 for 2016. The chair of each standing committee of the general partners Board of Directors receives an additional annual cash retainer as follows: Audit Committee chair: $15,000; and Conflicts Committee chair: $15,000. The
equity portion of the non-employee directors compensation consists of restricted units granted under the
Dominion Midstream LTIP and is subject to a one-year restriction period. The restricted units are granted in tandem with distribution equivalent rights.
Further, each director is indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law and is reimbursed for all expenses incurred in attending to his or her duties as a director.
The following tables and footnotes reflect the compensation and fees paid to the non-employee
directors of our general partner for their services in 2016. Messrs. Farrell and McGettrick do not receive any separate compensation for their services as directors.
2016 NON-EMPLOYEE DIRECTOR COMPENSATION
|
|
|
|
|
|
|
|
|
|
|
|
|
Name |
|
Fees earned or paid in cash |
|
|
Stock Awards(1) |
|
|
Total |
|
Joseph M. Rigby |
|
$ |
85,000 |
|
|
$ |
80,000 |
|
|
$ |
165,000 |
|
John W. Snow |
|
|
70,000 |
|
|
|
80,000 |
|
|
|
150,000 |
|
Harris H. Simmons |
|
|
17,500 |
|
|
|
20,000 |
|
|
|
37,500 |
|
David A. Wollard |
|
|
85,000 |
|
|
|
80,000 |
|
|
|
165,000 |
|
All directors |
|
$ |
257,500 |
|
|
$ |
260,000 |
|
|
$ |
517,500 |
|
(1) |
Messrs. Rigby, Snow and Wollard each received an annual equity retainer valued at approximately $80,000, which was equal to 2,587 units, valued at $30.92 per unit based on the closing price of Dominion Midstream
common units on January 4, 2016. Mr. Simmons was appointed to the Board effective October 21, 2016 and therefore received a prorated annual equity retainer valued at approximately $20,000, which was equal to 818 units, valued at
$24.45 per unit based on the closing price of Dominion Midstream common units on October 24, 2016. A total of 8,579 units, in aggregate, were distributed to these directors for their annual equity retainers. |
No options have been granted to directors.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth the beneficial ownership of common units, subordinated units and Series A Preferred Units of Dominion Midstream held by
beneficial owners of five percent or more of the units, by each director and NEO of our general partner, and by the directors and executive officers of our general partner as a group at February 24, 2017. Unless otherwise noted, the address for each
beneficial owner listed below is 120 Tredegar Street, Richmond, Virginia 23219. The percentage of units is based on 67,251,952 common units, 31,972,789 subordinated units and 30,308,342 Series A Preferred Units at February 24, 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name of Beneficial Owner |
|
Common
Units Beneficially
Owned |
|
|
Percentage of
Common Units Beneficially
Owned |
|
|
Subordinated Units
Beneficially Owned |
|
|
Percentage of
Subordinated Units Beneficially Owned |
|
|
Series A Preferred Units Beneficially Owned |
|
|
Percentage of Series A Preferred Units Beneficially Owned |
|
|
Percentage of
Common,
Subordinated and Series A Preferred Units
Beneficially Owned |
|
Dominion Resources, Inc.(1) |
|
|
18,504,628 |
|
|
|
27.5 |
% |
|
|
31,972,789 |
|
|
|
100 |
% |
|
|
11,365,628 |
|
|
|
37.5 |
% |
|
|
47.7 |
% |
Stonepeak Commonwealth Holdings LLC(2) |
|
|
2,178,412 |
|
|
|
3.2 |
|
|
|
|
|
|
|
|
|
|
|
16,417,018 |
|
|
|
54.2 |
|
|
|
14.4 |
|
Tortoise Capital Advisors, L.L.C.(3) |
|
|
7,026,421 |
|
|
|
10.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.4 |
|
National Grid PLC(4) |
|
|
6,783,373 |
|
|
|
10.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.2 |
|
Chickasaw Capital Management, LLC(5) |
|
|
3,404,625 |
|
|
|
5.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.6 |
|
Thomas F. Farrell II |
|
|
69,900 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Diane Leopold(6) |
|
|
2,500 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
John A. Luke, Jr.(6) |
|
|
2,389 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Mark F. McGettrick |
|
|
64,900 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Joseph M. Rigby(6) |
|
|
12,731 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Harris H. Simmons |
|
|
3,503 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
John W. Snow |
|
|
75,231 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
David A. Wollard |
|
|
23,531 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Paul E. Ruppert |
|
|
|
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
All executive officers and directors as a group (11 persons)(7)(8) |
|
|
259,185 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
(1) |
11,847,789 common units and 31,972,789 subordinated units are directly held by Dominion MLP Holding Company, LLC. An additional 6,656,839 common units and 11,365,628 Series A Preferred Units are directly held by QPC
Holding Company. Dominion is the ultimate parent company of the general partner, Dominion MLP Holding Company, LLC, and QPC Holding Company, and may be deemed to indirectly beneficially own the common units, subordinated units and Series A Preferred
Units directly held by Dominion MLP Holding Company, LLC, and QPC Holding Company. |
(2) |
Stonepeak Commonwealth Holdings LLC is located at 717 5th Avenue, 25th Floor, New York, New York 10022.
|
(3) |
Tortoise Capital Advisors, L.L.C., 11550 Ash Street, Suite 300, Leawood, Kansas 66211, filed a Schedule 13G with the SEC on February 14, 2017, reporting that it has sole voting or dispositive power over 777,668
common units, shared voting power over 5,593,080 common units, and shared dispositive power over 6,248,753 common units. |
(4) |
National Grid PLC, 1-3 Strand, London XO WC2N 5EH, filed a Schedule 13G with the SEC on October 9, 2015 reporting that it has shared voting or dispositive power over
6,783,373 common units. |
(5) |
Chickasaw Capital Management, LLC, 6075 Poplar Ave. Suite 720, Memphis, TN 38119, filed a Schedule 13G with the SEC on January 27, 2017, reporting that it has sole voting or dispositive power over 3,404,625
common units. |
(6) |
Effective February 23, 2017, Ms. Leopold and Mr. Luke were appointed to, and Mr. Rigby resigned from, the Board of Directors of Dominion Midstream GP, LLC. |
(7) |
Effective January 1, 2017, Mr. Webb was elected Senior Vice President Corporate Affairs and Chief Legal Officer of Dominion Midstream GP, LLC. His unit holdings are included in the group total.
|
(8) |
No individual director or executive officer has the right to acquire beneficial ownership of units within 60 days of February 24, 2017. Unless otherwise noted, all units are held directly by the director or
executive officer and such person has sole voting and investment power with respect to such shares. Includes shares as to which a director or executive officer has voting and/or investment discretion or voting and/or investment power is shared with
or controlled by another person as follows: Mr. Farrell, 10,000 (units held jointly with spouse); and all directors and executive officers as a group, 10,500. |
The following table sets forth the number of shares of Dominion common stock beneficially owned at
February 24, 2017 by each director of our general partner, by each NEO of our general partner and by all directors and executive officers of our general partner as a group. Unless otherwise noted, the address for each beneficial owner listed
below is 120 Tredegar Street, Richmond, Virginia 23219.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name of Beneficial Owner |
|
Shares of Common Stock Beneficially
Owned |
|
|
Deferred
Stock
Accounts(1) |
|
|
Restricted Shares |
|
|
Total |
|
|
Percentage of Common
Stock Beneficially Owned |
|
Thomas F. Farrell II |
|
|
853,038 |
|
|
|
|
|
|
|
203,858 |
|
|
|
1,056,896 |
|
|
|
* |
|
Diane Leopold(2) |
|
|
32,597 |
|
|
|
|
|
|
|
13,802 |
|
|
|
46,399 |
|
|
|
* |
|
John A. Luke, Jr.(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Mark F. McGettrick |
|
|
258,712 |
|
|
|
|
|
|
|
53,600 |
|
|
|
312,312 |
|
|
|
* |
|
Joseph M. Rigby(2) |
|
|
|
|
|
|
656 |
|
|
|
|
|
|
|
656 |
|
|
|
* |
|
Harris H. Simmons |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
John W. Snow |
|
|
4,075 |
|
|
|
|
|
|
|
|
|
|
|
4,075 |
|
|
|
* |
|
David A. Wollard |
|
|
16,148 |
|
|
|
22,422 |
|
|
|
|
|
|
|
38,570 |
|
|
|
* |
|
Paul E. Ruppert |
|
|
31,039 |
|
|
|
|
|
|
|
6,306 |
|
|
|
37,345 |
|
|
|
* |
|
All directors and executive officers as a group (11 persons)(3)(4) |
|
|
1,216,439 |
|
|
|
23,078 |
|
|
|
290,878 |
|
|
|
1,530,395 |
|
|
|
* |
|
(1) |
Shares in trust for which a director has voting rights. Amounts include shares issued to a trust from a frozen deferred compensation plan account. |
(2) |
Effective February 23, 2017, Ms. Leopold and Mr. Luke were appointed to, and Mr. Rigby resigned from, the Board of Directors of Dominion Midstream GP, LLC. |
(3) |
Effective January 1, 2017, Mr. Webb was elected Senior Vice President Corporate Affairs and Chief Legal Officer of Dominion Midstream GP, LLC. His share holdings are included in the group total.
|
(4) |
No individual director or executive officer has the right to acquire beneficial ownership of shares within 60 days of February 24, 2017. Unless otherwise noted, all shares are held directly by the director or
executive officer and such person has sole voting and investment power with respect to such shares. Includes shares as to which the director or executive officer has voting and/or investment discretion or voting and/or investment power is shared
with or controlled by another person as follows: Mr. Farrell, 18,000 (shares held jointly with spouse) and 65,454 (shares held by family foundation); and all directors and executive officers as a group, 83,863. |
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information at December 31, 2016 with respect to common units that may be issued under the Dominion Midstream LTIP:
|
|
|
|
|
|
|
|
|
|
|
|
|
Plan Category |
|
Number of securities to be issued
upon exercise of outstanding options, warrants and
rights |
|
|
Weighted average exercise
price of outstanding options, warrants
and rights |
|
|
Number of securities remaining available for
issuance under equity compensation plans |
|
Equity compensation plans approved by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans not approved by security holders |
|
|
|
|
|
|
|
|
|
|
2,984,044 |
|
Total |
|
|
|
|
|
|
|
|
|
|
2,984,044 |
|
Dominion Midstream LTIP
Our general partner has adopted the Dominion Midstream LTIP for directors of our general partner and employees and consultants of our general partner and any
of its affiliates, including Dominion, who perform services for us.
The Dominion Midstream LTIP provides for the grant, from time to
time, at the discretion of the Board of Directors of our general partner or a committee thereof, of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards, substitute awards,
unrestricted unit awards and cash awards. The purpose of the Dominion Midstream LTIP is to promote our interests by providing equity-based incentive compensation awards to the directors of our general partner and the employees and consultants of our
general partner and its affiliates to encourage superior performance and by strengthening our general partners and its affiliates abilities to attract and retain the services of individuals who are essential for our growth and
profitability and to encourage them to devote their best efforts to advancing our business. The Dominion Midstream LTIP is administered by the Board of Directors of our general partner or a committee thereof, which we refer to herein as the plan
administrator. The plan administrator may delegate its duties as appropriate, and may consult with the CGN Committee from time to time with respect to participants that are also providing services to Dominion.
The Board of Directors of our general partner may terminate or amend the Dominion Midstream LTIP at any time with respect to any common
units for which a grant has not previously been made. The Board of Directors of our general partner also has the right to alter or amend the Dominion Midstream LTIP from time to time, including increasing the number of units available to be granted
with respect to awards under the Dominion Midstream LTIP, subject to the requirements of the securities exchange upon which the common units are listed at that time. However, no change in any outstanding award (other than in the
event of certain transactions or changes in capitalization) may be made that would materially reduce the rights or benefits of a participant without the consent of the affected participant. The
Dominion Midstream LTIP will expire on the earliest of (i) the date on which all common units available under the Dominion Midstream LTIP have been delivered to participants, (ii) termination of the Dominion Midstream LTIP by the Board of
Directors of our general partner or (iii) the date that is 10 years following the date immediately prior to the effective date of the Offering.
Subject to certain adjustments that may be required from time to time in the event of certain transactions or changes in capitalization or
to prevent dilution or enlargement of the rights of participants in the Dominion Midstream LTIP, a maximum of 3,000,000 of our common units are available for delivery with respect to awards under the Dominion Midstream LTIP. Common units withheld
from an award or surrendered by a participant to satisfy tax withholding obligations or to satisfy the payment of exercise prices will be considered delivered under the Dominion Midstream LTIP for this purpose. Common units subject to awards that
are cancelled, forfeited, exercised, settled in cash or that otherwise terminate or expire without the delivery of common units will be available for delivery pursuant to other awards under the Dominion Midstream LTIP; provided, however, that the
number of common units subject to an award of unit appreciation rights that is exercised and settled in common units will count against the common units available for delivery under the Dominion Midstream LTIP based on the gross number of unit
appreciation rights exercised. The common units to be delivered with respect to awards under the Dominion Midstream LTIP will consist, in whole or in part, of common units acquired in the open market or from any affiliate of ours or any other
person, newly issued common units or any combination of the foregoing, as determined by the plan administrator in its discretion. There will not be any limit on the number of awards that may be granted and paid in cash.
Item 13. Certain Relationships and Related Transactions, and Director Independence
At February 15, 2017, Dominion owned 18,504,628 common units, all of our 31,972,789 subordinated units and 11,365,628 Series A Preferred Units,
representing an aggregate of approximately 47.7% limited partner interest in us (excluding the IDRs, which cannot be expressed as a fixed percentage), and owns and controls our general partner. Dominion appointed all of the directors of our general
partner, which owns a non-economic general partner interest in us and owns the IDRs. In addition, Messrs. Farrell, McGettrick and Webb and Mses. Leopold and Cardiff serve as executive officers of Dominion
and Mr. Farrell is also Chairman of the Board of Directors of Dominion.
See Note 14 to the Consolidated Financial Statements for
additional information on related party transactions.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing
operation and any liquidation of Dominion Midstream. The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arms length negotiations.
These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.
|
|
|
Operational Stage |
|
|
Distributions of distributable cash flow to our general partner and
its affiliates |
|
We will generally make cash distributions 100% to our unitholders, including affiliates of our general
partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above
the highest target distribution level. Assuming we have sufficient distributable cash flow to
pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $32.5 million on their
units. |
Payments to our general partner and its affiliates |
|
Our general partner will not receive a management fee or other compensation for its management of our
partnership, but we will reimburse our general partner and its affiliates for all expenses incurred and payments made on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its
affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform various general, administrative and support services for us or on our behalf, and corporate overhead costs and
expenses allocated to us by Dominion. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. |
Withdrawal or removal of our general partner |
|
If our general partner withdraws or is removed, its non-economic
general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
|
Liquidation Stage |
|
|
Liquidation |
|
Upon our liquidation, the partners, including our general partner, will be entitled to receive
liquidating distributions according to their respective capital account balances. |
Agreements between Cove Point and Dominion
DTI provides Cove Point with operational, maintenance and repair services with respect to the Cove Point Pipeline and certain other services pursuant to a
services contract between Cove Point and DTI. Cove Point also receives certain engineering, project management, construction, technical support and other related services from Dominion Technical Solutions, Inc. In addition, Cove Point is a party to
a services agreement with DRS pursuant to which it receives administrative, management and other services from DRS as it deems necessary or appropriate for its operations. Cove Point, and not Dominion Midstream, is responsible for reimbursing DRS
for the costs Cove Point incurs under its separate services agreement with DRS.
Agreements between DCG and Dominion
Virginia Power provides DCG with operational services with respect to engineering and associated safety-related services pursuant to a services contract
between DCG and Virginia Power. DCG also receives certain legal and regulatory services, information technology, electronic transmission and computer services and related services from DTI. In addition, DCG is a party to a services agreement with
DRS pursuant to which it receives administrative, management and other services from DRS as it deems necessary or appropriate for its operations. DCG is also a party to a services agreement with DCGS pursuant to which it receives human resources and
operations services from DCGS as it deems necessary or appropriate for its operations. The services provided by DCGS had been provided under a services agreement with Dominion Payroll through December 31, 2015.
Agreements between Questar Pipeline and Dominion
Questar Pipeline provides transportation and storage services to Questar Gas Company pursuant to long-term contracts. Questar Pipeline is a party to a
services agreement with DRS pursuant to which it receives administrative, management and other services from DRS as it deems necessary or appropriate for its operations. Questar Pipeline is also a party to a services agreement with QPC Services
Company pursuant to which it receives human resources and operations services from QPC Services Company as it deems necessary or appropriate for its operations.
Other Transactions with Related Persons
Virginia Power Services
Energy Corp., Inc., a subsidiary of Dominion, is one of Cove Points current transportation customers. Cove Point receives annual reservation payments with respect to the Cove Point Pipeline from Virginia Power Services Energy Corp., Inc. in an
amount approximating $1.6 million pursuant to an agreement with a scheduled expiration date of April 30, 2025.
See
Transactions with Affiliates, Advance from Affiliate, Dominion Credit Facility, Subsidiary Debt Transactions, Income Taxes, Natural Gas Imbalances, Right of First
Offer and Contributions from Dominion sections of Note 20 to the Consolidated Financial Statements for summaries of the terms of these and other agreements with Dominion and related parties.
Procedures for Review, Approval and Ratification of Related Party Transactions
The Board of Directors of our general partner has adopted Related Party Transaction Guidelines. These guidelines were adopted for the purpose of identifying
potential conflicts of interest arising out of financial transactions, arrangements and relations between Dominion Midstream and any related persons. Under the guidelines, a related person is a director, executive officer, director nominee, a
beneficial owner of more than 5% of any class of Dominion Midstreams voting securities, or any immediate family member of one of the foregoing persons. A related party transaction is any financial transaction, arrangement or relationship
(including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships in excess of $120,000 in which Dominion Midstream (and/or any of its consolidated subsidiaries) is a party and in which
the related person has or will have a direct or indirect material interest.
In determining whether a direct or indirect interest is material, the significance of the
information to investors in light of all circumstances is considered. The importance of the interest to the person having the interest, the relationship of the parties to the transaction with each other and the amount involved are also among the
factors considered in determining the significance of the information to the investors.
The Board of Directors of our general partner
has reviewed certain categories of transactions and determined that transactions between Dominion Midstream and a related person that fall within such categories will not result in the related person receiving a direct or indirect material interest.
Under the guidelines, such transactions are not deemed related party transactions and therefore not subject to review by the Audit Committee. The categories of excluded transactions include, among other items, compensation and expense reimbursement
paid to directors and executive officers in the ordinary course of performing their duties; transactions with other companies where the related partys only relationship is as an employee, if the aggregate amount involved does not exceed the
greater of $1 million or 2% of that companys gross revenues; and charitable contributions which are less than the greater of $1 million or 2% of the charitys annual receipts.
Information is collected about potential related party transactions in annual questionnaires completed by directors and executive officers.
Management reviews the potential related party transactions and assesses whether any of the identified transactions constitute a related party transaction. Any identified related party transactions are then reported to the Audit Committee. The Audit
Committee reviews and considers relevant facts and circumstances and determines whether to ratify or approve the related party transactions identified. The Audit Committee may only approve or ratify related party transactions that are in, or are not
inconsistent with, the best interests of Dominion Midstream and its unitholders and are in compliance with Dominion Midstreams Code of Ethics.
Since January 1, 2016, there have been no related party transactions involving Dominion Midstream that were required either to be
approved under Dominion Midstreams policies or reported under the SEC related party transactions rules.
Director Independence
See Item 10. Directors, Executive Officers and Corporate Governance for information about the independence of the Board of Directors of our general
partner and its committees.
Item 14. Principal Accountant Fees and Services
The following table presents fees paid to Deloitte & Touche LLP for the fiscal years ended December 31, 2016 and 2015.
|
|
|
|
|
|
|
|
|
Type of Fees |
|
2016 |
|
|
2015 |
|
(millions) |
|
|
|
|
|
|
Audit fees |
|
$ |
1.09 |
|
|
$ |
0.73 |
|
Audit-related fees |
|
|
|
|
|
|
|
|
Tax fees |
|
|
|
|
|
|
|
|
All other fees |
|
|
|
|
|
|
|
|
|
|
$ |
1.09 |
|
|
$ |
0.73 |
|
Audit fees represent fees of Deloitte & Touche LLP for the audit of the annual consolidated financial
statements, the review of financial statements included in quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with statutory requirements,
regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC.
Audit-related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of the
consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and attest services not required by statute or regulations, due diligence related to mergers,
acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.
The Audit Committee
has adopted a pre-approval policy for its independent auditors services and fees that may be provided by Deloitte & Touche LLP to the Partnership. All of the fees in the table above were
approved in accordance with this policy. The policy (a) identifies the guiding principles that must be considered by the Audit Committee in approving services to ensure that Deloitte & Touche LLPs independence is not impaired;
(b) describes the audit, audit-related, tax and other services that may be provided and the non-audit services that are prohibited; and (c) sets forth
pre-approval requirements for all permitted services. Under the policy, all services to be provided by Deloitte & Touche LLP must be pre-approved by the Audit
Committee.
Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages
noted.
1. Financial Statements
See Index
on page 50.
2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial
statements or the related notes.
3. Exhibits (incorporated by reference unless otherwise noted.
EXHIBIT INDEX
|
|
|
Exhibit
Number |
|
Description |
|
|
2.1 |
|
Purchase, Sale and Contribution Agreement by and among Dominion Resources, Inc., Dominion MLP Holding Company II, Inc. and Dominion Midstream Partners, LP dated April 1, 2015 (Exhibit 2.1, Form
8-K filed April 1, 2015, File No. 1-36684). |
|
|
2.2 |
|
Contribution Agreement by and among North East Transmission Co., Inc., National Grid IGTS Corp., Dominion Midstream Partners, LP and Iroquois GP Holding Company, LLC, dated as of August 14, 2015 (Exhibit 2.1, Form 8-K filed August 17, 2015, File No. 1-36684). |
|
|
2.3 |
|
Contribution Agreement by and among NJNR Pipeline Company, Dominion Midstream Partners, LP and Iroquois GP Holding Company, LLC, dated as of August 14, 2015 (Exhibit 2.2, Form 8-K filed
August 17, 2015, File No. 1-36684). |
|
|
2.4 |
|
Contribution, Conveyance and Assumption Agreement, dated as of October 28, 2016, by and among Dominion Resources, Inc., QPC Holding Company and Dominion Midstream Partners, LP (Exhibit 2.1, Form
8-K filed October 31, 2016, File No. 1-36684). |
|
|
3.1 |
|
Certificate of Limited Partnership of Dominion Midstream Partners, LP (Exhibit 3.1, Form S-1 Registration Statement filed March 28, 2014, File
No. 333-194864). |
|
|
3.2 |
|
Second Amended and Restated Agreement of Limited Partnership of Dominion Midstream Partners, LP, dated as of December 1, 2016, by and between Dominion Midstream GP, LLC and Dominion MLP Holding Company, LLC (Exhibit 3.1, Form 8-K filed December 1, 2016, File No. 1-36684). |
|
|
4.1 |
|
Registration Rights Agreement by and between Dominion Midstream Partners, LP and Dominion MLP Holding Company, LLC (Exhibit 3.1, Form 8-K filed October 20, 2014, File No. 1-36684). |
|
|
4.2 |
|
Registration Rights Agreement by and between Dominion Midstream Partners, LP and Dominion MLP Holding Company II, Inc. (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2015 filed
August 6, 2015, File No. 1-36684). |
|
|
4.3 |
|
Registration Rights Agreement by and among Dominion Midstream Partners, LP, North East Transmission Co., Inc. and National Grid IGTS Corp., dated as of September 29, 2015 (Exhibit 10.1, Form
8-K filed September 29, 2015, File No. 1-36684). |
|
|
4.4 |
|
Registration Rights Agreement by and between Dominion Midstream Partners, LP and NJNR Pipeline Company, dated as of September 29, 2015 (Exhibit 10.2, Form 8-K filed September 29,
2015, File No. 1-36684). |
|
|
4.5 |
|
Registration Rights Agreement, dated as of December 1, 2016, by and between Dominion Midstream Partners, LP and the Purchasers party thereto (Exhibit 4.1, Form 8-K filed December 1,
2016, File No. 1-36684). |
|
|
10.1 |
|
Contribution Agreement, dated as of October 10, 2014, by and among Dominion Midstream Partners, LP, Dominion Midstream GP, LLC, Dominion Cove Point, Inc., Cove Point GP Holding Company, LLC, Dominion Cove Point LNG, LP,
Dominion MLP Holding Company, LLC and Dominion Gas Projects Company, LLC (Exhibit 10.1, Form 8-K filed October 17, 2014, File No. 1-36684). |
|
|
10.2 |
|
Inter-Company Credit Agreement by and between Dominion Midstream Partners, LP and Dominion Resources, Inc. (Exhibit 10.1, Form 8-K filed October 20, 2014, File No. 1-36684). |
|
|
|
Exhibit
Number |
|
Description |
|
|
10.3 |
|
Services Agreement by and between Dominion Midstream GP, LLC and Dominion Resources Services, Inc. (Exhibit 10.2, Form 8-K filed October 20, 2014, File
No. 1-36684). |
|
|
10.4 |
|
Right of First Offer Agreement by and between Dominion Midstream Partners, LP and Dominion Resources, Inc. (Exhibit 10.3, Form 8-K filed October 20, 2014, File No. 1-36684). |
|
|
10.5* |
|
Dominion Midstream Partners, LP 2014 Long-Term Incentive Plan (Exhibit 10.6, Form 8-K filed October 20, 2014, File No. 1-36684). |
|
|
10.6 |
|
Terminal Expansion Agreement Cove Point between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated September 1, 2006 (Exhibit 10.6, Amendment No. 2 to Form S-1
Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.7 |
|
Amendment to the Terminal Expansion Agreement between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated December 14, 2007 (Exhibit 10.7, Amendment No. 2 to Form S-1
Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.8 |
|
Acknowledgment and Amendment to the Precedent Agreement for Firm LNG Tanker Discharging Service (Expansion Project) and to the Terminal Expansion Agreement Cove Point between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC,
dated April 2009 (Exhibit 10.8, Amendment No. 2 to Form S-1 Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.9 |
|
Amendment to the Terminal Expansion Agreement Cove Point between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated September 22, 2009 (Exhibit 10.9, Amendment No. 2 to Form
S-1 Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.10 |
|
Agreement and Amendment to the Terminal Expansion Agreement between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated January 26, 2011 (Exhibit 10.10, Amendment No. 2 to Form
S-1 Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.11 |
|
Agreement and Amendment to the Terminal Expansion Agreement between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated April, 2012 (Exhibit 10.11, Amendment No. 2 to Form S-1
Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.12 |
|
Early Termination Letter Agreement between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated March 15, 2013 (Exhibit 10.12, Amendment No. 2 to Form S-1 Registration
Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.13 |
|
Form of Promissory Note in the initial principal amount of $295,331,972 dated April 1, 2015 (Exhibit 10.1, Form 8-K filed April 1, 2015, File
No. 1-36684). |
|
|
10.14 |
|
Fourth Amended and Restated Agreement of Limited Partnership of Dominion Cove Point LNG, LP among Cove Point GP Holding Company, LLC, Dominion Gas Projects Company, LLC and Dominion Cove Point, Inc. (Exhibit 10.2, Form 10-Q for the quarter ended March 31, 2015 filed May 5, 2015, File No. 1-36684). |
|
|
10.15* |
|
Non-employees directors annual compensation for Dominion Midstream GP, LLC (Exhibit 10.15, Form 10-K for the year ended December 31, 2015
filed February 26, 2016, File No. 1-36684). |
|
|
10.16* |
|
Form of Restricted Unit Award Agreement for Non-Employee Directors under the 2014 Long-Term Incentive Plan approved December 18, 2015 (Exhibit 10.16, Form
10-K for the year ended December 31, 2015 filed February 26, 2016, File No. 1-36684). |
|
|
10.17 |
|
Series A Preferred Unit and Common Unit Purchase Agreement, dated as of October 27, 2016, among Dominion Midstream Partners, LP and the purchasers party thereto (Exhibit 10.1, Form 8-K
filed October 31, 2016, File No. 1-36684). |
|
|
10.18 |
|
$300,000,000 Term Loan Agreement, dated as of October 28, 2016, among Dominion Midstream Partners, LP, QPC Holding Company, as Guarantor, the several lenders from time to time parties thereto, Royal Bank of Canada, as
Administrative Agent, and Mizuho Bank, Ltd., as Syndication Agent (Exhibit 10.2, Form 8-K filed October 31, 2016, File
No. 1-36684). |
|
|
|
Exhibit
Number |
|
Description |
|
|
21 |
|
Subsidiaries of Dominion Midstream Partners, LP (filed herewith). |
|
|
23 |
|
Consent of Deloitte & Touche LLP (filed herewith). |
|
|
31.a |
|
Certification by Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). |
|
|
31.b |
|
Certification by Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). |
|
|
32 |
|
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). |
|
|
101 |
|
The following financial statements from Dominion Midstreams Annual Report on Form 10-K for the year ended December 31, 2016, filed on February 28, 2017, formatted in XBRL:
(i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Equity and Partners Capital (v) Consolidated Statements of
Cash Flows, and (vi) the Notes to Consolidated Financial Statements. |
* |
Indicates management contract or compensatory plan or arrangement. |
|
Confidential treatment has been granted for certain portions of this exhibit pursuant to a confidential treatment order granted by the Securities and Exchange Commission. Such portions have been omitted and filed
separately with the Securities and Exchange Commission. |
Item 16. Form 10-K
Summary
None.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
DOMINION MIDSTREAM PARTNERS, LP
Registrant |
|
|
By: |
|
Dominion Midstream GP, LLC, its general partner |
|
|
By: |
|
/s/ Thomas F. Farrell II |
|
|
(Thomas F. Farrell II, Chairman, President and
Chief Executive Officer) |
Date: February 28, 2017
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant
and in the capacities indicated on the 28th day of February, 2017.
|
|
|
Signature |
|
Title |
|
|
/s/ Thomas F. Farrell
II Thomas F. Farrell II |
|
Chairman of the Board of Directors, President and Chief
Executive Officer of Dominion Midstream GP, LLC |
|
|
/s/ Diane Leopold
Diane Leopold |
|
Director of Dominion Midstream GP, LLC |
|
|
/s/ John A. Luke,
Jr. John A. Luke, Jr. |
|
Director of Dominion Midstream GP, LLC |
|
|
/s/ Mark F.
McGettrick Mark F. McGettrick |
|
Director, Executive Vice President and Chief Financial Officer of Dominion Midstream GP, LLC |
|
|
/s/ Harris H.
Simmons Harris H. Simmons |
|
Director of Dominion Midstream GP, LLC |
|
|
|
|
/s/ John W. Snow
John W. Snow |
|
Director of Dominion Midstream GP, LLC |
|
|
/s/ David A.
Wollard David A. Wollard |
|
Director of Dominion Midstream GP, LLC |
|
|
|
/s/ Michele L.
Cardiff Michele L. Cardiff |
|
Vice President, Controller and Chief Accounting Officer of Dominion Midstream GP, LLC |
Exhibit Index
|
|
|
Exhibit
Number |
|
Description |
|
|
2.1 |
|
Purchase, Sale and Contribution Agreement by and among Dominion Resources, Inc., Dominion MLP Holding Company II, Inc. and Dominion Midstream Partners, LP dated April 1, 2015 (Exhibit 2.1, Form
8-K filed April 1, 2015, File No. 1-36684). |
|
|
2.2 |
|
Contribution Agreement by and among North East Transmission Co., Inc., National Grid IGTS Corp., Dominion Midstream Partners, LP and Iroquois GP Holding Company, LLC, dated as of August 14, 2015 (Exhibit 2.1, Form 8-K filed August 17, 2015, File No. 1-36684). |
|
|
2.3 |
|
Contribution Agreement by and among NJNR Pipeline Company, Dominion Midstream Partners, LP and Iroquois GP Holding Company, LLC, dated as of August 14, 2015 (Exhibit 2.2, Form 8-K filed
August 17, 2015, File No. 1-36684). |
|
|
2.4 |
|
Contribution, Conveyance and Assumption Agreement, dated as of October 28, 2016, by and among Dominion Resources, Inc., QPC Holding Company and Dominion Midstream Partners, LP (Exhibit 2.1, Form
8-K filed October 31, 2016, File No. 1-36684). |
|
|
3.1 |
|
Certificate of Limited Partnership of Dominion Midstream Partners, LP (Exhibit 3.1, Form S-1 Registration Statement filed March 28, 2014, File
No. 333-194864). |
|
|
3.2 |
|
Second Amended and Restated Agreement of Limited Partnership of Dominion Midstream Partners, LP, dated as of December 1, 2016, by and between Dominion Midstream GP, LLC and Dominion MLP Holding Company, LLC (Exhibit 3.1, Form 8-K filed December 1, 2016, File No. 1-36684). |
|
|
4.1 |
|
Registration Rights Agreement by and between Dominion Midstream Partners, LP and Dominion MLP Holding Company, LLC (Exhibit 3.1, Form 8-K filed October 20, 2014, File No. 1-36684). |
|
|
4.2 |
|
Registration Rights Agreement by and between Dominion Midstream Partners, LP and Dominion MLP Holding Company II, Inc. (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2015 filed
August 6, 2015, File No. 1-36684). |
|
|
4.3 |
|
Registration Rights Agreement by and among Dominion Midstream Partners, LP, North East Transmission Co., Inc. and National Grid IGTS Corp., dated as of September 29, 2015 (Exhibit 10.1, Form
8-K filed September 29, 2015, File No. 1-36684). |
|
|
4.4 |
|
Registration Rights Agreement by and between Dominion Midstream Partners, LP and NJNR Pipeline Company, dated as of September 29, 2015 (Exhibit 10.2, Form 8-K filed September 29,
2015, File No. 1-36684). |
|
|
4.5 |
|
Registration Rights Agreement, dated as of December 1, 2016, by and between Dominion Midstream Partners, LP and the Purchasers party thereto (Exhibit 4.1, Form 8-K filed December 1,
2016, File No. 1-36684). |
|
|
10.1 |
|
Contribution Agreement, dated as of October 10, 2014, by and among Dominion Midstream Partners, LP, Dominion Midstream GP, LLC, Dominion Cove Point, Inc., Cove Point GP Holding Company, LLC, Dominion Cove Point LNG, LP,
Dominion MLP Holding Company, LLC and Dominion Gas Projects Company, LLC (Exhibit 10.1, Form 8-K filed October 17, 2014, File No. 1-36684). |
|
|
10.2 |
|
Inter-Company Credit Agreement by and between Dominion Midstream Partners, LP and Dominion Resources, Inc. (Exhibit 10.1, Form 8-K filed October 20, 2014, File No. 1-36684). |
|
|
10.3 |
|
Services Agreement by and between Dominion Midstream GP, LLC and Dominion Resources Services, Inc. (Exhibit 10.2, Form 8-K filed October 20, 2014, File
No. 1-36684). |
|
|
10.4 |
|
Right of First Offer Agreement by and between Dominion Midstream Partners, LP and Dominion Resources, Inc. (Exhibit 10.3, Form 8-K filed October 20, 2014, File No. 1-36684). |
|
|
10.5* |
|
Dominion Midstream Partners, LP 2014 Long-Term Incentive Plan (Exhibit 10.6, Form 8-K filed October 20, 2014, File No. 1-36684). |
|
|
10.6 |
|
Terminal Expansion Agreement Cove Point between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated September 1, 2006 (Exhibit 10.6, Amendment No. 2 to Form S-1
Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.7 |
|
Amendment to the Terminal Expansion Agreement between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated December 14, 2007 (Exhibit 10.7, Amendment No. 2 to Form S-1
Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.8 |
|
Acknowledgment and Amendment to the Precedent Agreement for Firm LNG Tanker Discharging Service (Expansion Project) and to the Terminal Expansion Agreement Cove Point between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC,
dated April 2009 (Exhibit 10.8, Amendment No. 2 to Form S-1 Registration Statement filed June 23, 2014, File
No. 333-194864). |
|
|
|
Exhibit
Number |
|
Description |
|
|
10.9 |
|
Amendment to the Terminal Expansion Agreement Cove Point between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated September 22, 2009 (Exhibit 10.9, Amendment No. 2 to Form
S-1 Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.10 |
|
Agreement and Amendment to the Terminal Expansion Agreement between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated January 26, 2011 (Exhibit 10.10, Amendment No. 2 to Form
S-1 Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.11 |
|
Agreement and Amendment to the Terminal Expansion Agreement between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated April, 2012 (Exhibit 10.11, Amendment No. 2 to Form S-1
Registration Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.12 |
|
Early Termination Letter Agreement between Dominion Cove Point LNG, LP and Statoil Natural Gas LLC, dated March 15, 2013 (Exhibit 10.12, Amendment No. 2 to Form S-1 Registration
Statement filed June 23, 2014, File No. 333-194864). |
|
|
10.13 |
|
Form of Promissory Note in the initial principal amount of $295,331,972 dated April 1, 2015 (Exhibit 10.1, Form 8-K filed April 1, 2015, File
No. 1-36684). |
|
|
10.14 |
|
Fourth Amended and Restated Agreement of Limited Partnership of Dominion Cove Point LNG, LP among Cove Point GP Holding Company, LLC, Dominion Gas Projects Company, LLC and Dominion Cove Point, Inc. (Exhibit 10.2, Form 10-Q for the quarter ended March 31, 2015 filed May 5, 2015, File No. 1-36684). |
|
|
10.15* |
|
Non-employees directors annual compensation for Dominion Midstream GP, LLC (Exhibit 10.15, Form 10-K for the year ended December 31, 2015
filed February 26, 2016, File No. 1-36684). |
|
|
10.16* |
|
Form of Restricted Unit Award Agreement for Non-Employee Directors under the 2014 Long-Term Incentive Plan approved December 18, 2015 (Exhibit 10.16, Form
10-K for the year ended December 31, 2015 filed February 26, 2016, File No. 1-36684). |
|
|
10.17 |
|
Series A Preferred Unit and Common Unit Purchase Agreement, dated as of October 27, 2016, among Dominion Midstream Partners, LP and the purchasers party thereto (Exhibit 10.1, Form 8-K
filed October 31, 2016, File No. 1-36684). |
|
|
10.18 |
|
$300,000,000 Term Loan Agreement, dated as of October 28, 2016, among Dominion Midstream Partners, LP, QPC Holding Company, as Guarantor, the several lenders from time to time parties thereto, Royal Bank of Canada, as
Administrative Agent, and Mizuho Bank, Ltd., as Syndication Agent (Exhibit 10.2, Form 8-K filed October 31, 2016, File No. 1-36684). |
|
|
21 |
|
Subsidiaries of Dominion Midstream Partners, LP (filed herewith). |
|
|
23 |
|
Consent of Deloitte & Touche LLP (filed herewith). |
|
|
31.a |
|
Certification by Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). |
|
|
31.b |
|
Certification by Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). |
|
|
32 |
|
Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith). |
|
|
101 |
|
The following financial statements from Dominion Midstreams Annual Report on Form 10-K for the year ended December 31, 2016, filed on February 28, 2017, formatted in XBRL:
(i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Equity and Partners Capital (v) Consolidated Statements of
Cash Flows, and (vi) the Notes to Consolidated Financial Statements. |
* |
Indicates management contract or compensatory plan or arrangement. |
|
Confidential treatment has been granted for certain portions of this exhibit pursuant to a confidential treatment order granted by the Securities and Exchange Commission. Such portions have been omitted and filed
separately with the Securities and Exchange Commission. |