10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                    

 

Commission File Number    Exact name of registrants as specified in their charters   

I.R.S. Employer

Identification Number

001-36684    DOMINION MIDSTREAM PARTNERS, LP    46-5135781
  

DELAWARE

(State or other jurisdiction of incorporation or organization)

  
  

120 TREDEGAR STREET

RICHMOND, VIRGINIA

(Address of principal executive offices)

  

23219

(Zip Code)

    

(804) 819-2000

(Registrants’ telephone number)

    

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class

 

Name of Each Exchange

on Which Registered

Common Units Representing Limited Partner Interests   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  x    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  x

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  x    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  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this 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.

 

Large accelerated filer  x   Accelerated filer  ¨   Non-accelerated filer  ¨   Smaller reporting company  ¨
    (Do not check if a smaller reporting company)  

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value of the registrant’s common units held by non-affiliates was approximately $771 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. As of January 31, 2016, Dominion Midstream Partners, LP had 45,722,371 common units and 31,972,789 subordinated units outstanding.

 

 

 


Table of Contents

Dominion Midstream Partners, LP

 

Item

Number

         

 

Page

Number

  

  

  

Glossary of Terms

     3   

Part I

  

1.

  

Business

     6   

1A.

  

Risk Factors

     14   

1B.

  

Unresolved Staff Comments

     28   

2.

  

Properties

     28   

3.

  

Legal Proceedings

     28   

4.

  

Mine Safety Disclosures

     28   

Part II

  

5.

  

Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     29   

6.

  

Selected Financial Data

     33   

7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     34   

7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     44   

8.

  

Financial Statements and Supplementary Data

     45   

9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     67   

9A.

  

Controls and Procedures

     67   

9B.

  

Other Information

     68   

Part III

  

10.

  

Directors, Executive Officers and Corporate Governance

     69   

11.

  

Executive Compensation

     71   

12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     90   

13.

  

Certain Relationships and Related Transactions, and Director Independence

     92   

14.

  

Principal Accountant Fees and Services

     94   

Part IV

  

15.

  

Exhibits and Financial Statement Schedules

     95   

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 or Dominion Carolina Gas Transmission, LLC (beginning April 1, 2015); or all of them taken as a whole.

 

         

 



Table of Contents

GLOSSARY OF TERMS

 

The following abbreviations or acronyms used in this Form 10-K are defined below:

 

Abbreviation or Acronym    Definition

2005 Agreement

  

An agreement effective March 1, 2005, which Cove Point entered into with the Sierra Club and the Maryland Conservation Council, Inc.

Additional Return Distributions

  

The additional cash distribution equal to 3.0% of Cove Point’s Modified Net Operating Income in excess of $600 million distributed each year

Adjusted EBITDA

  

EBITDA after adjustment for EBITDA attributable to the DCG Predecessor and a noncontrolling interest in Cove Point held by Dominion subsequent to the Offering, less income from equity method investee, plus distributions from equity method investee

AFUDC

  

Allowance for funds used during construction

AIP

  

Annual Incentive Plan

ARO

  

Asset retirement obligation

Atlantic Coast Pipeline

  

Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion, Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc.

Bcf

  

Billion cubic feet

Bcfe

  

Billion cubic feet equivalent

Blue Racer

  

Blue Racer Midstream, LLC, a joint venture between Dominion and Caiman

BRP

  

Retirement Benefit Restoration Plan

CAA

  

Clean Air Act

Caiman

  

Caiman Energy II, LLC

CAP

  

IRS Compliance Assurance Process

CD&A

  

Compensation Discussion and Analysis

CEO

  

Chief Executive Officer

CFO

  

Chief Financial Officer

CGN Committee

  

Compensation, Governance and Nominating Committee of Dominion’s Board of Directors

Clean Power Plan

  

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

  

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

  

Carbon dioxide

COO

  

Chief Operating Officer

Cove Point

  

Dominion Cove Point LNG, LP

Cove Point Facilities

  

Collectively, the Liquefaction Project, Cove Point LNG Facility and Cove Point Pipeline

Cove Point Holdings

  

Cove Point GP Holding Company, LLC

Cove Point LNG Facility

  

An LNG import/regasification and storage facility located on the Chesapeake Bay in Lusby, Maryland owned by Cove Point

Cove Point Pipeline

  

An approximately 136-mile natural gas pipeline owned by Cove Point that connects the Cove Point LNG Facility to interstate natural gas pipelines

CPCN

  

Certificate of Public Convenience and Necessity

CRA

  

Compliance Resolution Agreement

CWA

  

Clean Water Act

D.C.

  

District of Columbia

DCG

  

Dominion Carolina Gas Transmission, LLC (successor by statutory conversion to and formerly known as Carolina Gas Transmission Corporation)

DCG Acquisition

  

The acquisition of DCG by Dominion Midstream from Dominion on April 1, 2015

DCG Predecessor

  

Dominion as the predecessor for accounting purposes for the period from Dominion’s acquisition of DCG from SCANA on January 31, 2015 until the DCG Acquisition

DCGS

  

Dominion Carolina Gas Services, Inc.

DCPI

  

Dominion Cove Point, Inc.

DOE

  

Department of Energy

Dominion

  

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

  

Dominion Gas Holdings, LLC

Dominion Midstream

  

The legal entity, Dominion Midstream Partners, LP, one or more of its consolidated subsidiaries, Cove Point Holdings, Iroquois GP Holding Company, LLC and DCG (beginning April 1, 2015), or the entirety of Dominion Midstream Partners, LP and its consolidated subsidiaries

Dominion Midstream LTIP

  

Dominion Midstream 2014 Long-Term Incentive Plan

Dominion Payroll

  

Dominion Payroll Company, Inc.

DOT

  

U.S. Department of Transportation

DRS

  

Dominion Resources Services, Inc.

Dth

  

Dekatherm

 

        3

 



Table of Contents

 

 

Abbreviation or Acronym    Definition

DTI

  

Dominion Transmission, Inc.

EA

  

Environmental assessment

EBITDA

  

Earnings before interest and associated charges, income tax expense, depreciation and amortization

Edgemoor Project

  

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

  

Environmental Protection Agency

EPACT

  

Energy Policy Act of 2005

ERISA

  

The Employee Retirement Income Security Act of 1974

ESRP

  

Executive Supplemental Retirement Plan

Export Customers

  

ST Cove Point, LLC, a joint venture of Sumitomo Corporation and Tokyo Gas Co., Ltd., and GAIL Global (USA) LNG LLC

FERC

  

Federal Energy Regulatory Commission

FERC Order

  

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

FTA

  

Free Trade Agreement

FTA Authorization

  

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

  

U.S. generally accepted accounting principles

GHGRP

  

Greenhouse Gas Reporting Program

GHG

  

Greenhouse gas

IDR

  

Incentive distribution right

Import Shippers

  

The three LNG import shippers consisting of BP Energy Company, Shell NA LNG, Inc. and Statoil

IRC

  

Internal Revenue Code

Iroquois

  

Iroquois Gas Transmission System, L.P.

IRS

  

Internal Revenue Service

Keys Energy Project

  

Project to provide 107,000 Dths/day of firm transportation service from Cove Point’s interconnect with Transco in Fairfax County, Virginia to Keys Energy Center, LLC’s power generating facility in Prince George’s County, Maryland

Liquefaction Project

  

A natural gas export/liquefaction facility currently under construction by Cove Point

LNG

  

Liquefied natural gas

Maryland Commission

  

Public Service Commission of Maryland

MD&A

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

MLP

  

Master limited partnership, equivalent to publicly traded partnership

Modified Net Operating Income

  

Cove Point’s Net Operating Income plus any interest expense included in the computation of Net Operating Income

Mtpa

  

Million metric tons per annum

NAAQS

  

National Ambient Air Quality Standards

NEO

  

Named executive officers

Net Operating Income

  

Cove Point’s 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

  

Collectively, North East Transmission Co., Inc. and National Grid IGTS Corp.

NGA

  

Natural Gas Act of 1938, as amended

NGPSA

  

Natural Gas Pipeline Safety Act of 1968, as amended

NJNR

  

NJNR Pipeline Company

Non-FTA Authorization

  

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

  

Non-open access, proprietary non-jurisdictional services with rates, terms and conditions that are determined by arm’s length negotiations with customers

NSPS

  

New Source Performance Standards

NYSE

  

New York Stock Exchange

Offering

  

The initial public offering of common units of Dominion Midstream

Open Access Services

  

Open access jurisdictional services with cost-based rates and terms and conditions that are part of a tariff approved by FERC

OSHA

  

Federal Occupational Safety and Health Act, as amended

PHI

  

Pepco Holdings, Inc.

PHMSA

  

Pipeline and Hazardous Materials Safety Administration

ppb

  

Parts-per-billion

Preferred Equity Interest

  

A perpetual, non-convertible preferred equity interest in Cove Point entitled to the Preferred Return Distributions and the Additional Return Distributions

 

4        

 



Table of Contents
Abbreviation or Acronym    Definition

Preferred Return Distributions

  

The first $50.0 million of annual cash distributions made by Cove Point

PSD

  

Prevention of Significant Deterioration

PSIA

  

Pipeline Safety Improvement Act of 2002

RCRA

  

Resource Conservation and Recovery Act, as amended

RGGI

  

Regional Greenhouse Gas Initiative

ROFO Assets

  

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

  

Return on invested capital

SCANA

  

SCANA Corporation

SEC

  

Securities and Exchange Commission

SEIF

  

Maryland Strategic Energy Investments Fund

St. Charles Transportation Project

  

Project to provide 132,000 Dths/day of firm transportation service from Cove Point’s interconnect with Transco in Fairfax County, Virginia to Competitive Power Venture Maryland, LLC’s power generating facility in Charles County, Maryland

Statoil

  

Statoil Natural Gas, LLC

Storage Customers

  

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

  

Transcontinental Gas Pipe Line, LLC

Transco to Charleston Project

  

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

TSR

  

Total shareholder return

U.S.

  

United States of America

VIE

  

Variable interest entity

Virginia Power

  

Virginia Electric and Power Company

VOC

  

Volatile organic compounds

 

        5

 



Table of Contents

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 Midstream’s 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 NG’s 20.4% and NJNR’s 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.

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 segment’s performance. See Note 23 to the Consolidated Financial Statements for further discussions of Dominion Midstream’s operating segment, which information is incorporated herein by reference.

 

 

 

ORGANIZATIONAL STRUCTURE

The following simplified diagram depicts Dominion Midstream’s organizational and ownership structure at December 31, 2015.

 

LOGO

 

6        

 



Table of Contents

 

 

 

ASSETS AND OPERATIONS

Dominion Midstream’s 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 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 Point’s 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 Point’s cash flows and Net Operating Income from its existing import contracts and associated transportation contracts. See description of the Liquefaction Project under Assets and Operations—Cove 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). We intend to cause Cove Point to fully fund such distribution reserve by December 31, 2016, but 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 certain of its contracts in 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 inter-

ests. Cove Point’s 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 an operational 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 is currently fully contracted. 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 Point’s 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 has an additional 800,000 Dths/day of regasification capacity committed under a separate agreement with Statoil, one of the Import Shippers. In 2015, the Import Shippers comprised approximately 77% of total consolidated revenues for Dominion Midstream. Cove Point’s 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 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,

 

 

7

 



Table of Contents

 

 

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 existing compressor stations 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 Transco’s 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 Point’s 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 $30 million St. Charles Transportation Project and the approximately $40 million Keys Energy Project. Construction on each project commenced in December 2015. The St. Charles Transportation Project is anticipated to be placed into service in June 2016. The Keys Energy Project is anticipated to be placed into service in March 2017.

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 $3.4 billion to $3.8 billion, excluding financing costs. Through December 31, 2015, Cove Point incurred $2.2 billion of development and construction costs associated with the Lique-

faction 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 Facility’s 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, which will be made available upon the expiration of Cove Point’s import contracts with Statoil, with the balance of the existing storage capacity available for Cove Point’s 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 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.

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. As of December 31, 2015, DCG’s 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 34,500 installed compressor horsepower. DCG’s system transports gas to its customers from the transmission systems of Southern Natural Gas Company at Port Wentworth, Georgia and Aiken County,

 

 

8        

 



Table of Contents

 

 

South Carolina; Southern LNG, Inc. at Elba Island, near Savannah, Georgia; and Transco in Cherokee and Spartanburg counties in South Carolina. All of DCG’s operations are regulated by FERC.

DCG’s customers include South Carolina Electric & Gas Company (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.

DCG’s revenues are primarily derived from reservation charges for firm services as provided for in its FERC approved tariff. DCG’s pipeline system is substantially fully subscribed with a contracted pipeline capacity of 765,773 Dths/day. Approximately 6% of the capacity has a 2016 expiration date, and 94% of this capacity is contracted through 2017 or beyond. DCG has several growth projects to expand its system, which are expected to significantly increase its contracted capacity by the end of 2017. All expansion projects are supported by long-term contracts with terms ranging from 15 to 30 years. See a summary of these expansion projects below:

    In April 2014, DCG executed a binding precedent agreement for the approximately $35 million Columbia to Eastover Project to provide an incremental 15,800 Dths/day of firm transportation service. In May 2015, DCG filed an application to request FERC authorization to construct and operate the project facilities, which are expected to be placed into service in the third quarter of 2016.
    In 2014, DCG executed three binding precedent agreements for the approximately $120 million Transco to Charleston Project. The project will 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. In July 2015, DCG requested authorization to utilize the FERC pre-filing process. DCG expects to file the application to request FERC authorization to construct and operate the project facilities in the first quarter of 2016. The project is expected to be placed into service in the fourth quarter of 2017.

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. As of December 31, 2015, 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 Dominion’s 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 growing 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 in 2015, 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 nation’s largest producers and transporters of energy. Dominion’s strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. At December 31, 2015, Dominion served over 5 million utility and retail energy customers in 14 states and operated one of the nation’s largest underground natural gas storage systems, with approximately 933 Bcf of storage capacity. Dominion’s 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. Dominion Gas consists of (i) The East Ohio Gas Company d/b/a Dominion East Ohio, a regulated natural gas distribution operation, (ii) DTI, an interstate natural gas transmission pipeline company, and (iii) Dominion Iroquois, Inc., which holds a 24.72% noncontrolling partnership interest in Iroquois.

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 leverage Dominion’s existing presence in the Utica region with significant additional new capacity designed to meet producer needs as the development of the Utica Shale formation increases.

 

 

9

 



Table of Contents

 

 

Atlantic Coast Pipeline is a limited liability company owned by Dominion (45%), Duke Energy Corporation (40%), Piedmont Natural Gas Company, Inc. (10%) and AGL Resources Inc. (5%). In October 2015, Duke Energy Corporation entered into a merger agreement with Piedmont Natural Gas Company, Inc. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. 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 expects to be in service in late 2018. 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 shale and conventional interstate gas supplies for markets in the mid-Atlantic region of the U.S.

Dominion is our largest unitholder, holding at December 31, 2015, 17,846,672 common units (approximately 39% of all outstanding) and 31,972,789 subordinated units (100% of all outstanding), 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 Project’s 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.

DCG’s 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, DCG’s pipeline system faces competitive pressures from similar facilities that serve the South Carolina and southeastern Georgia area in terms of location, rates, terms of service, and flexibility and reliability of service.

 

 

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 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. FERC’s 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 is 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, FERC’s 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, FERC’s jurisdiction does not extend to the production or local distribution of natural gas.

In general, FERC’s authority to regulate interstate natural gas pipelines and the services that they provide includes:

    Rates and charges for natural gas transportation and related services;
    The certification and construction of new facilities;
    The extension and abandonment of services and facilities;
    The maintenance of accounts and records;
    The acquisition and disposition of facilities;
    The initiation and discontinuation of services; and
    Various other matters.

In May 2011, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective

 

 

10        

 



Table of Contents

 

 

July 2011. In July 2012, FERC issued an order approving a stipulation and agreement among Cove Point, FERC trial staff and the other active parties in the rate case resolving all issues set for hearing by FERC and establishing the mechanism for operational purchases of LNG, with settlement rates effective April 2012. Pursuant to the terms of the settlement, future operational purchases of LNG are not expected to affect Cove Point’s net results of operations. Cove Point and settling customers are subject to a rate moratorium through December 31, 2016. Cove Point is required to file its next rate case in 2016 with rates to be effective January 1, 2017.

In connection with Dominion’s 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 Point’s 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.

Three parties submitted timely requests for rehearing on the FERC Order. There is no prescribed timeframe for FERC to issue its order on rehearing. One party requested a stay, to which Cove Point filed a response asking that FERC deny the motion for stay. In May 2015, FERC denied rehearing and the request for stay.

Two parties have separately filed for a petition for review at 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 Orders until the judicial proceedings are complete, which the court denied in June 2015.

Energy Policy Act of 2005

The EPACT and FERC’s 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 FERC’s 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 agency’s 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 FERC’s 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.

DOT Regulation

The Cove Point Pipeline and DCG 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 is 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.

 

 

11

 



Table of Contents

 

 

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 Guard’s 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 Midstream’s control.

 

 

ENVIRONMENTAL REGULATION

General

Dominion Midstream is committed to compliance with all applicable environmental laws, regulations and rules related to its operations. Dominion Midstream’s operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing occupational health and safety and 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 Midstream’s 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 Midstream’s 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 NAAQS. 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 Midstream’s 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 EPA’s 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 July 2014, the EPA issued a memorandum specifying that it will no longer apply or enforce federal regulations or EPA-approved PSD state implementation plan provisions that require new and modified stationary sources to obtain a PSD permit when GHGs are the only pollutant that would be emitted at levels that exceed the permitting thresholds. In August 2015, the EPA published a final rule rescinding the requirement for all new and modified major sources to obtain permits based solely on their GHG emissions. In addition, the EPA stated that it will continue to use the existing thresholds to apply to sources that are otherwise subject to PSD for conventional pollutants until it completes a new rulemaking either justifying and upholding those thresholds or setting new ones. Some states have issued interim guidance that follows

 

 

12        

 



Table of Contents

 

 

the EPA guidance. Due to uncertainty regarding what additional actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the court ruling under a new rulemaking, 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 proposed 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. Until these regulations and guidelines are finalized, we are unable to predict future requirements or estimate compliance costs with certainty.

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 EPA’s 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 2015 emissions data.

Annual GHG emissions at the Cove Point LNG Facility have remained fairly constant from 2010 to 2014, ranging from 174,000 to 177,000 metric tons of CO2 equivalent. Approximately 97% of these emissions are CO2 emissions from combustion sources, such as compressor engines and heaters. Only 3% of the annual 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 2014, annual GHG emissions from Dominion Midstream’s facilities, including four compressor stations in South Carolina and two compressor stations in Virginia were approximately 270,000 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 Midstream’s 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 Midstream’s 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 facility’s 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 of Dominion, 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. As of December 31, 2015, Cove Point had approximately 109 full-time employees and was supported by 6 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 SEC’s website at http://www.sec.gov. You may also read and copy any document it files at the SEC’s 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.

 

 

        13

 



Table of Contents

 

 

 

Item 1A. Risk Factors

Dominion Midstream’s 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, DCG, 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) DCG’s 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 Point’s ability to generate Net Operating Income, DCG’s 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, DCG 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 Point’s ability to make payments on the Preferred Equity Interest, DCG’s 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 Dominion’s 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 DCG Acquisition, and we may be unable to do so for any of the following reasons, without limitation:

    We are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
    We are unable to obtain or maintain necessary governmental approvals;
    We are unable to obtain financing for the acquisitions or future organic growth opportunities on acceptable terms, or at all;
    We are unable to secure adequate customer commitments to use the future facilities;
    We are outbid by competitors; or
    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 in addition to DCG, 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.

 

 

14        

 



Table of Contents

 

 

The acquisitions we may make could adversely affect our business and cash flows. The acquisitions we may make involve potential risks, including:

    An inability to integrate successfully the businesses that we acquire with our existing operations;
    A decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the acquisition;
    The assumption of unknown liabilities;
    Limitations on rights to indemnity from the seller;
    Mistaken assumptions about the cash generated, or to be generated, by the business acquired or the overall costs of equity or debt;
    Incorrect assumptions about capital investments and required operating and maintenance expenditures;
    The diversion of management’s attention from other business concerns; and
    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, 2015, $5.9 million was outstanding against our $300 million credit facility with Dominion. We may borrow under such facility 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 Dominion’s 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 DCG Acquisition, on April 1, 2015, we incurred $300.8 million of indebtedness to Dominion evidenced by a promissory note and in the future, we may incur additional significant indebtedness pursuant to other 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, with the exception of the promissory note issued in connection with the DCG Acquisition, 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 or our prom-

issory note 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:

    A significant portion of our cash flows could be used to service our indebtedness;
    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;
    Our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
    A high level of debt would increase our vulnerability to general adverse economic and industry conditions;
    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
    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.

In addition, borrowings under our credit facility with Dominion and other credit facilities we or our subsidiaries may enter into in the future may bear interest at variable rates. If 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

 

 

15

 



Table of Contents

 

 

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 Point’s revenue is generated by contracts with a limited number of customers, and Cove Point’s 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 twenty customers, including the Storage Customers, marketers or end users and the Import Shippers. The three largest customers comprised approximately 90%, 93% and 94% of the total transportation and storage revenues for the years ended December 31, 2015, 2014 and 2013, respectively. Cove Point’s largest customer represented approximately 70%, 72% and 72% of such amounts in 2015, 2014 and 2013, respectively. Because Cove Point has a small number of customers, its contracts subject it to counterparty risk. The ability of each of Cove Point’s customers to perform its obligations to Cove Point will depend on a number of factors that are beyond our control. Cove Point’s 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 Point’s 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 Point’s import contracts, we expect these contracts will not be renewed.

Cove Point’s 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 Point’s customers becomes entitled to terminate its further contractual obligations to Cove Point and exercises such right, such termination could have a material adverse effect on Cove Point’s business, financial condition, operating results, cash flow, liquidity and prospects, which could have an adverse impact on Cove Point’s 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 Point’s 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. The termination of, and failure to replace, the export contracts could have an adverse impact on Cove Point’s 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 Point’s existing revenue streams will be insufficient to pay the full amount of Preferred Return Distributions commencing May 1, 2017. Cove Point currently has 800,000 Dths/day of regasification and firm transportation capacity under contract with Statoil. Statoil’s obligations with respect to 640,000 Dths/day of such capacity will expire as of January 1, 2017, with the remainder expiring on May 1, 2017 in order to provide capacity to be utilized in connection with the Liquefaction Project. Following the expiration of these contracts 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. We intend to cause 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) by December 31, 2016, but 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 contracts 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 Point’s ability to make payments on the Preferred Equity Interest after May 1, 2017. Commercial development of the Liquefaction Project will take a number of years. Completion of the Liquefaction Project could be delayed by factors such as:

    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;
 

 

16        

 



Table of Contents

 

 

    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;
    The ability to attract sufficient skilled and unskilled labor and the existence of any labor disputes, and Cove Point’s 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
    Dominion’s ability and willingness to provide funding for the development of the Liquefaction Project and, if necessary, Cove Point’s 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 Point’s 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 Point’s operating results and its ability to make payments on the Preferred Equity Interest. In addition, the successful completion of the Liquefaction 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 expected to take several years, will be confined within a limited geographic area and could be subject to delays, cost overruns, labor disputes and other factors that could adversely affect Cove Point’s 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 Point’s contractors pursuant to their agreements. Further, faulty construction that does not conform to Cove Point’s design and quality standards may also have a similar adverse effect. For example, improper equipment installation may lead to a shortened life of Cove Point’s equipment, increased operations and maintenance costs or a reduced availability or production capacity of the affected facility. The ability of Cove Point’s contractors to perform successfully under their agreements is dependent on a number of factors, including force majeure events and the contractors’ ability to:

    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;
    Attract, develop and retain skilled personnel and engage and retain third party subcontractors, and address any labor issues that may arise;
    Post required construction bonds and comply with the terms thereof, and maintain their own financial condition, including adequate working capital; and
    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 Point’s 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 contractor’s 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 Point’s ability to make payments on the Preferred Equity Interest.

Cove Point is dependent on Dominion to fund the costs necessary to construct the Liquefaction Project. If Dominion is unwilling or unable to supply the funding necessary to complete the Liquefaction Project, 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 $3.4 billion to $3.8 billion, excluding financing costs. To date, Dominion has funded 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, 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 Point’s existing revenue streams and cash reserves will be insufficient for it to complete the Liquefaction Project. If Dominion is unwilling to provide funding for the remaining construction costs, 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 the Liquefaction Project 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

 

 

17

 



Table of Contents

 

 

Cove Point’s ability to fund future development and acquisition activities and restrict Cove Point’s 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 has been appealed by third parties. Cove Point does not know whether any existing or potential interventions or other actions by third parties will interfere with Cove Point’s 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 Point’s 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 purchasing LNG. Each year, one or two LNG cargos are procured and are billed to Cove Point’s Import Shippers pursuant to a cost recovery mechanism set forth in Cove Point’s FERC gas tariff. This cost recovery mechanism expires by its terms on December 31, 2016, and there can be no assurance that a similar recovery mechanism will be available thereafter. 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 its 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.

Failure to attract and retain key executive officers and other appropriately qualified employees could have an adverse effect on our operations. Our business strategy is dependent on our ability to recruit, retain and motivate employees. The key executive officers of our general partner are the CEO, CFO and executive vice president and those responsible for financial, operational, legal, regulatory and accounting functions. Competition for skilled management employees in these areas of our business operations is high. In addition, certain specialized knowledge is required of our technical employees in gas transmission, storage, gathering, processing and distribution. Our inability to attract

 

 

18        

 



Table of Contents

 

 

and retain these employees could adversely affect our business and future operating results. An aging workforce in the energy industry necessitates recruiting, retaining and developing the next generation of leadership.

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 Point’s 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 Point’s 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, including pipeline safety and integrity. 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 RCRA 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.

 

 

19

 



Table of Contents

 

 

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. There are numerous regulatory approaches currently in effect or being considered to address GHGs, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, and regulation by the EPA. 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. 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.

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. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products, which in turn could affect demand for natural gas.

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 physical 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 Point’s ability to make payments on the Preferred Equity Interest or our ability to make distributions.

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 nation’s 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 Point’s ability to make payments on the Preferred Equity Interest or our ability to make distributions.

Certain of our operations are subject to FERC’s 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 Point’s 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 this 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.

 

 

20        

 



Table of Contents

 

 

Cove Point and its jurisdictional customers are subject to a rate moratorium through 2016. Cove Point is required to file its next rate case so that new jurisdictional rates are effective January 1, 2017. 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. When Cove Point or DCG, as applicable, files its next rate case, or when or if Cove Point, DCG 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. A failure to support its rates could result in a rate decrease from its current maximum rate levels, which could adversely affect its operating results, cash flows and financial position and Cove Point’s ability to make payments on the Preferred Equity Interest or our ability to make distributions.

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. Under current FERC policy, because we are a limited partnership and do not pay U.S. federal income taxes, this would require us to show that our unitholders (or their ultimate owners) are subject to U.S. federal income taxation on the portion of our subsidiary’s income allocable to us. To support such a showing, our general partner may elect to require owners of our units to recertify their status as being subject to U.S. federal income taxation on the income generated by us or we may attempt to provide other evidence. We can provide no assurance that the evidence we might provide to FERC will be sufficient to establish that our unitholders (or their ultimate owners) are subject to U.S. federal income tax liability on the income that is allocable to us. If we are unable to make such a showing, FERC could disallow a substantial portion of the income tax allowance included in the determination of the maximum rates that we may charge, which could result in a reduction of such maximum rates from current levels.

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 Point’s ability to make payments on the Preferred Equity Interest or our ability to make distributions.

 

 

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:

    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;
    Neither our partnership agreement nor any other agreement requires Dominion to pursue a business strategy that favors us;
    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 partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;
    Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
    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;
    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;
    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;
    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;
    Our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
    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;
    Our general partner intends to limit its liability regarding our contractual and other obligations;
    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;
    Our general partner controls the enforcement of obligations that it and its affiliates owe to us;
    Our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
 

 

21

 



Table of Contents

 

 

    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 partner’s 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.

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. 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. 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 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 partner’s 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 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 unitholders.

Our partnership agreement replaces our general partner’s 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:

    How to allocate business opportunities among us and its affiliates;
    Whether to exercise its limited call right;
    How to exercise its voting rights with respect to the units it owns;
    Whether to exercise its registration rights;
    Whether to elect to reset target distribution levels; and
    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:

    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;
   

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

 

 

22        

 



Table of Contents

 

 

   

decision was adverse to the interest of Dominion Midstream or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

    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:
  (1) Approved by the Conflicts Committee, although our general partner is not obligated to seek such approval; or
  (2) Approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

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.

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 management’s 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

 

 

23

 



Table of Contents

 

 

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 voting together as a single class is required to remove our general partner. At December 31, 2015, Dominion owned an aggregate of 64.1% of our common and subordinated units. 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. 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.

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 general 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, 2015, Dominion owned an aggregate of 64.1% 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:

    Our existing unitholders’ proportionate ownership interest in us will decrease;
    The amount of distributable cash flow on each unit may decrease;
    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;
    The ratio of taxable income to distributions may increase;
    The relative voting strength of each previously outstanding unit may be diminished; and
    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. 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 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) 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 in the public or private markets, including sales by Dominion or other large holders. At December 31, 2015, Dominion held 17,846,672 common units and 31,972,789 subordinated units. All of the subordinated units will convert into common units on a

 

 

24        

 



Table of Contents

 

 

one-for-one basis at the end of the subordination period. 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. 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. 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 common 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 partner’s 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 NYSE’s 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 COMMON 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 material additional amounts of 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, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash flow to you 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 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

 

 

25

 



Table of Contents

 

 

jurisdictions to which we expand could substantially reduce our distributable cash flow to you.

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. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of the U.S. Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

Additionally, on May 5, 2015, the IRS issued proposed regulations concerning which activities give rise to “qualifying income” within the meaning of section 7704 of the Internal Revenue Code of 1986, as amended. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for purposes of the qualifying income requirement. Any modifications 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 will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

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. Recently enacted legislation alters the procedures for collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce 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 conclusions of our counsel or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or 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 distributable cash flow to our unitholders and thus will be borne indirectly by our unitholders.

Recently enacted legislation, applicable to us for taxable years beginning after December 31, 2017, alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties

and interest) as a result of an audit. Under the new rules, unless we are eligible to, and do, elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed. If we are required to pay taxes, penalties, and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

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, you 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 due from them with respect to that income.

Tax gain or loss on the disposition of our common units could be more or less than expected. If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

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. Distributions to non-U.S. persons will be 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

 

 

26        

 



Table of Contents

 

 

of our taxable income. If you are a tax-exempt entity or a non- U.S. person, you should consult your 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 Internal Revenue Code 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 you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your 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, 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. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Department of the Treasury recently adopted final Treasury regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. Nonetheless, the regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, we may 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 that could result in a shift of income, gain, loss and deduction between the general partner (as the holder of our IDRs) and our unitholders. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units. When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders. 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 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, 2015, Dominion owned 64.1% of the total interests in our capital and profits. 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 unitholder’s 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 a publicly traded partnership that has constructively terminated may be permitted to provide only a single

 

 

27

 



Table of Contents

 

 

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. 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 unitholder’s 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, 2015, Dominion Midstream’s assets consisted of its preferred equity interest in Cove Point, the physical properties owned by DCG 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.

 

 

Item 4. Mine Safety Disclosures

Not applicable.

 

 

28        

 



Table of Contents

Part II

 

 

 

 

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Securities

On October 15, 2014, Dominion Midstream’s 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, 2016, 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 2015. No distributions were paid to unitholders during the year ended December 31, 2014. Quarterly information concerning unit price and distributions is disclosed in Note 24 to the Consolidated Financial Statements, which information is incorporated herein by reference.

The following table presents certain information with respect to Dominion’s purchase of Dominion Midstream’s common units during the fourth quarter of 2015:

 

 

DOMINION PURCHASES OF DOMINION MIDSTREAM COMMON UNITS

 

    
Period    Total
Number
of Units
Purchased
     Average
Price Paid
per Unit
     Total Number of Units
Purchased as Part of
Publicly Announced
Plans or Programs(1)
     Approximate Dollar
Value of Units that May
Yet Be Purchased under
the Plans or Programs(3)
 

10/1/2015-10/31/15

     478,093       $ 27.70         478,093       $ 34.6 million   

11/1/2015-11/30/15

     3,913       $ 29.83         3,913       $ 34.5 million   

12/1/2015-12/31/15

     327,342       $ 27.70         327,342       $ 25.4 million   

Total(2)

     809,348       $ 27.69         809,348            

 

(1) These shares were purchased by Dominion as part of Dominion’s program initiated on September 24, 2015 to purchase from the market up to $50.0 million of common units representing limited partner interests in Dominion Midstream by September 2016 at the discretion of Dominion’s management. The purchased units are held by Dominion or a subsidiary of Dominion other than Dominion Midstream. See Note 6 to the Consolidated Financial Statements for additional information.
(2) In addition to the information presented in the above table, in September 2015, Dominion purchased 77,396 common units of Dominion Midstream at an average price of $27.56 per unit. At September 30, 2015, approximately $47.9 million was available to be purchased under Dominion’s program to purchase from the market up to $50.0 million of common units representing limited partner interests in Dominion Midstream. See Note 6 to the Consolidated Financial Statements for additional information.

 

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 partner’s intention with respect to the distributions to be made to unitholders.

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:

  $45.0 million (as described below); plus
  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
  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
 

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

 

 

        29

 



Table of Contents

 

 

   

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 entity’s 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;
  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;
  Expansion capital expenditures;
  Investment capital expenditures;
  Payment of transaction expenses relating to interim capital transactions;
  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. Please see Note 20 to the Consolidated Financial Statements for a discussion of the provisions included in our credit facility with Dominion 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.

 

 

30        

 



Table of Contents

 

 

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:

  We have distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
  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”);
  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”);
  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
  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.

 

          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.

 

 

31

 



Table of Contents

 

 

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:

  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
  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.

 

 

32        

 



Table of Contents

 

 

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 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 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.
    The selected balance sheet data at December 31, 2014 consists of the consolidated balances 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.

 

Year Ended December 31,    2015      2014      2013
(Predecessor)
     2012
(Predecessor)
 
(millions, except per unit amounts)                            

Operating revenue

   $ 369.6       $ 313.3       $ 343.5       $ 293.0   

Net income including noncontrolling interest and DCG Predecessor

     196.5         106.9         109.4         97.2   

Net income including noncontrolling interest

     194.2         26.3         

Net income attributable to partners

     72.5         9.5                     

Net income per limited partner unit (basic and diluted):

           

Common units

     1.08         0.15         

Subordinated units

     1.00         0.15                     

Cash distribution declared per limited partner unit

     0.7760         0.1389                     

Total assets

     4,125.2         2,258.4         1,498.2         1,213.5   

Long-term debt

     300.8                           

 

        33

 



Table of Contents

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

 

 

 

MD&A discusses Dominion Midstream’s 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
  Partnership Overview
  Initial Public Offering
  Basis of Presentation
  How We Evaluate Our Operations
  Factors Impacting Comparability of Our Financial Results
  Accounting Matters
  Results of Operations
  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, high winds, severe storms, earthquakes, flooding and changes in water availability that can cause outages and property damage to facilities;
  Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;
  Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances;
  The cost of environmental compliance, including those costs related to climate change;
  Changes in enforcement practices of regulators relating to environmental and safety standards and litigation exposure for remedial activities;
  Changes in regulator implementation of 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 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;
 

 

34        

 



Table of Contents

 

 

  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. 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 Point’s 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.

Business Strategy

Dominion Midstream’s 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 growing midstream company focused on the Utica Shale formation, and its indirect ownership interest in Atlantic Coast Pipeline, which is a newly created 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 Dominion’s 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 Dominion’s 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 Dominion’s midstream experience in the Utica and Marcellus Shale formations. We intend to capitalize on Dominion’s midstream experience in the high growth areas of the Utica and Marcellus Shale formations. Dominion’s 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 Midstream’s 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 Dominion’s 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;
  All of our IDRs;
 

 

35

 



Table of Contents

 

 

  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 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 Midstream’s basis is equal to Dominion’s cost basis in the general partner interest in Cove Point and a portion of the Preferred Equity Interest. Dominion Midstream owns the general partner interest and controls Cove Point and therefore consolidates Cove Point. As such, Dominion Midstream’s investment in the Preferred Equity Interest and Cove Point’s preferred equity interest are eliminated in consolidation. Dominion’s retained common equity interest in Cove Point is reflected as noncontrolling interest.

The DCG Acquisition is considered to be a reorganization of entities under common control. As a result, Dominion Midstream’s basis in DCG is equal to Dominion’s 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 have been retrospectively adjusted to include the historical results and financial position of DCG beginning January 31, 2015, the inception date of common control.

For the periods 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 Dominion’s 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 financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DRS or Dominion Payroll to Dominion Midstream and Cove Point on the basis of direct and allocated methods in accordance with Dominion Midstream’s services agreements with DRS and Dominion Payroll and Cove Point’s 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 or Dominion Payroll 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 or Dominion Payroll department. 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 DCG Predecessor before interest and related charges, income tax and depreciation and amortization. Adjusted EBITDA represents EBITDA after adjustment for the EBITDA attributable to the DCG Predecessor and a noncontrolling interest in Cove Point held by Dominion subsequent to the Offering, less income from equity method investee, plus distributions from equity method investee. Subsequent to the DCG Acquisition in the second quarter of 2015, we define distributable cash flow as Adjusted EBITDA less maintenance capital expenditures, less interest expense and adjusted for known timing differences between cash and income. During the first quarter of 2015, the remaining net proceeds from the Offering were used to fund capital expenditures. As a result, the reconciliation of distributable cash flow no longer includes adjustments for expansion capital expenditures or the use of net proceeds from the Offering. All periods presented reflect the adjustments described above.

Although we have not quantified Adjusted EBITDA and distributable cash flow for Cove Point as our Predecessor, we use these metrics to analyze our performance. EBITDA, Adjusted EBITDA and distributable cash flow are used as supplemental financial measures 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

 

 

36        

 



Table of Contents

 

 

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:

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 NG’s 20.4% and NJNR’s 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 Midstream’s 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 Midstream’s 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 Midstream’s 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 Midstream’s basis is equal to Dominion’s 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 Point’s expected annual revenues from the import-related contracts by approximately $150 million from 2017 through 2028, partially offset by approximately $50 million of additional revenues in the years 2013 through 2017.

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 Point’s 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. If, however, 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 Midstream’s 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

 

 

37

 



Table of Contents

 

 

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, 2015, Dominion Midstream reported $295.5 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 2015, 2014 and 2013 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 Midstream’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion Midstream’s 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. With the exception of the reporting unit containing goodwill associated with the DCG Acquisition as discussed below, 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.

In connection with the DCG Acquisition, Dominion Midstream recorded $249.6 million of goodwill. As a result, a significant decrease in Dominion Midstream’s estimates of future cash flows would likely result in the fair value of the reporting unit containing DCG to fall below its carrying value and could result in an assessment that the goodwill associated with that reporting unit is impaired. No such change has occurred in 2015.

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 asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about operating the long-lived assets and the selection of an appropriate discount rate. When determining whether an asset or asset group has been impaired, management groups assets at the lowest level that has identifiable cash flows. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions.

New Accounting Standards

See Note 3 to the Consolidated Financial Statements for a discussion of new accounting standards.

 

 

38        

 



Table of Contents

 

 

RESULTS OF OPERATIONS

Presented below are selected amounts related to Dominion Midstream’s results of operations:

 

Year Ended December 31,   2015     $ Change     2014     $ Change     2013  
(millions)                              

Operating revenue

  $ 369.6      $ 56.3      $ 313.3      $ (30.2   $ 343.5   

Purchased gas

    54.6        (5.0     59.6        (32.1     91.7   

Net revenue

    315.0        61.3        253.7        1.9        251.8   

Other operations and maintenance

    56.7        21.8        34.9        7.0        27.9   

Depreciation and amortization

    40.4        2.7        37.7        6.0        31.7   

Other taxes

    26.3        3.9        22.4        1.3        21.1   

Earnings from equity method investee

    6.6        6.6                        

Other income

    1.0        1.0                        

Interest and related charges

    0.6        0.6                        

Income tax expense

    2.1        (49.7     51.8        (9.9     61.7   

Net income including noncontrolling interest and DCG Predecessor

  $ 196.5      $ 89.6      $ 106.9      $ (2.5   $ 109.4   

Less: Predecessor income prior to initial public offering on October 20, 2014

             80.6       

Less: Net income attributable to DCG Predecessor

    2.3                      

Net income including noncontrolling interest

    194.2          26.3       

Less: Net income attributable to noncontrolling interest

    121.7                16.8       

Net income attributable to partners

  $ 72.5                9.5                   

EBITDA

  $ 239.6              $ 196.4              $ 202.8   

Adjusted EBITDA(1)

  $ 75.6              $ 9.5                   

Distributable cash flow(1)

  $ 75.7              $ 9.6                   

 

(1)  For 2014, represents amounts for the period from October 20, 2014 to December 31, 2014.

The following table presents a reconciliation of EBITDA and Adjusted EBITDA to the most directly comparable GAAP financial measure for each year. The Adjusted EBITDA measure is not applicable to the year ended December 31, 2013.

 

Year Ended December 31,    2015      2014      2013  
(millions)                     

Adjustments to reconcile net income including noncontrolling interest and DCG Predecessor to EBITDA and Adjusted EBITDA:

        

Net income including noncontrolling interest and DCG Predecessor:

   $ 196.5       $ 106.9       $ 109.4   

Add:

        

Depreciation and amortization

     40.4         37.7         31.7   

Interest and related charges

     0.6                   

Income tax expense

     2.1         51.8         61.7   

EBITDA

   $ 239.6       $ 196.4       $ 202.8   

Distributions from equity method investee

     2.6              

Less:

        

Earnings from equity method investee

     6.6              

EBITDA attributable to Predecessor prior to initial public offering

             157.5      

EBITDA attributable to DCG Predecessor

     5.7              

EBITDA attributable to noncontrolling interest

     154.3         29.4            

Adjusted EBITDA(1)

   $ 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 2015. This measure is not applicable to the year ended December 31, 2013.

 

Year Ended December 31,    2015     2014  
(millions)             

Adjustments to reconcile net cash provided by operating activities to distributable cash flow:

    

Net cash provided by operating activities

   $ 243.5      $ 156.1   

Less:

    

Cash attributable to Predecessor prior to initial public offering

            119.5   

Cash attributable to noncontrolling interest(1)

     154.4        31.1   

Cash attributable to DCG Predecessor(2)

     10.4          

Other changes in working capital and noncash adjustments

     (3.1     4.0   

Adjusted EBITDA

     75.6        9.5   

Adjustments to cash:

    

Plus: Other taxes(3)

     4.1          

Plus: Deferred revenue(4)

     8.0          

Less: Amortization of regulatory liability(5)

     (2.1       

Less: Maintenance capital expenditures(6)

     (9.4       

Plus: Transition costs funded by Dominion

     0.7          

Less: Interest expense and AFUDC equity

     (1.4       

Plus: Non-cash director compensation

     0.2        0.1   

Distributable cash flow

   $ 75.7      $ 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 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.
 

 

39

 



Table of Contents

 

 

(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)  Adjustment to reflect the timing difference between cash paid for property taxes and the amount recognized into expense.
(4)  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.
(5)  Represents the monetization of a bankruptcy claim being amortized into income through February 2024.
(6)  Amounts include accruals. For the years ended December 31 2015 and 2014, amounts exclude $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, 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 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 Point’s FERC gas tariff.

An analysis of Dominion Midstream’s results of operations follows:

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 Point’s 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).

Earnings for equity method investee increased $6.6 million as a result of the acquisition of a 25.93% noncontrolling partnership interest in Iroquois.

Other taxes increased 17% primarily due to the DCG Acquisition.

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 Midstream’s 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.

2014 VS. 2013

Net revenue increased 1%, primarily reflecting a $3.2 million increase in other revenue as a result of the renegotiation of certain import-related contracts. Operating revenue and purchased gas expense decreased as Cove Point received one LNG cooling cargo in 2014 compared to the receipt of two LNG cooling cargos in 2013.

Other operations and maintenance increased 25%, primarily due to an increase in stakeholder outreach expenditures associated with the Liquefaction Project.

Depreciation and amortization increased 19%, primarily as a result of accelerated depreciation from anticipated asset retirements associated with the Liquefaction Project.

Other taxes increased 6% primarily due to an increase of $0.5 million in assessed property taxes on the Cove Point LNG Facility and the absence of a $0.5 million reduction of property taxes recognized in 2013 to reflect the actual amount billed to Cove Point.

Interest and related charges were immaterial in both 2014 and 2013 as any affiliated borrowings were used primarily to fund capital expenditures and therefore associated interest and related charges were capitalized to property, plant and equipment.

Income tax expense decreased 16% primarily reflecting a $10.0 million decrease as a result of our treatment as a pass-through entity for federal and state income tax purposes effective October 20, 2014, and a $4.8 million decrease due to a decline in net income prior to October 20, 2014 as compared to the prior year. These decreases were partially offset by the absence of a $3.6 million prior year benefit resulting from a change in the allocation of Cove Point’s income to states.

 

 

SEGMENT RESULTS OF OPERATIONS

Presented below is a summary of contributions by Dominion Midstream’s operating segments to net income including noncontrolling interest and DGG Predecessor:

 

Year Ended December 31,   2015     $ Change     2014     $ Change     2013  
(millions)                              

Dominion Energy

  $ 198.2      $ 91.3      $ 106.9      $ (2.6   $ 109.5   

Corporate and Other

    (1.7     (1.7            0.1        (0.1

Consolidated

  $ 196.5      $ 89.6      $ 106.9      $ (2.5   $ 109.4   

Dominion Energy

Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s contribution to net income including noncontrolling interest and DCG Predecessor. Subsequent to October 20, 2014, Dominion Midstream, as a pass-through entity, is generally not subject to income taxes.

 

 

40        

 



Table of Contents

 

 

2015 VS. 2014

 

      Increase
(Decrease)
 
(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   

2014 VS. 2013

 

      Increase
(Decrease)
 
(millions)       

Renegotiation of certain import-related contracts

   $ 2.0   

Stakeholder outreach expenses for the Liquefaction Project

     (4.7

Accelerated depreciation

     (3.8

State income tax benefit in 2013(1)

     (3.6

Absence of income taxes subsequent to the Offering

     10.0   

Other

     (2.5

Change in net income contribution

   $ (2.6
(1) Change in state effective tax rate applicable to current and deferred taxes.

Corporate and Other

Presented below are the Corporate and Other segment’s after-tax results.

 

Year Ended December 31,    2015     2014      2013  
(millions, except earnings per unit amounts)                    

Items attributable to operating segment

   $ (1.7   $       $ (0.1

Total net charge

   $ (1.7   $       $ (0.1

Corporate and Other includes items attributable to Dominion Midstream’s 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.

 

 

LIQUIDITY AND CAPITAL RESOURCES

Overview

Dominion Midstream’s ongoing principal sources of liquidity may include distributions received from Cove Point from our Preferred Equity Interest, cash generated from operations of DCG, 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 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 $13.6 million per quarter, or $54.4 million per year in the aggregate, based on the number of common units and subordinated units currently outstanding. However, 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, and

there is no guarantee that we will pay distributions to our unitholders in any quarter.

Outstanding Indebtedness

In connection with the Offering, Dominion Midstream entered into a $300 million credit facility with Dominion, allowing it to competitively pursue acquisitions and future organic growth opportunities or to otherwise meet its financial needs. In June 2015, we borrowed $5.9 million against the credit facility to fund expansion capital expenditures. In January 2016, we borrowed an additional $4.8 million against the credit facility to fund property tax payments, of which $1.2 million was repaid in February 2016. 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%. Interest on the note is payable quarterly, and all principal and accrued interest is due and payable at maturity on April 1, 2017, which under certain conditions can be extended at the option of Dominion Midstream to October 1, 2017.

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, 2015, Dominion Midstream paid total capital expenditures of $1.3 billion (of which $2.4 million relates to DCG Predecessor and was funded by Dominion), which included $24.4 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 $3.4 billion to $3.8 billion, excluding financing costs. Through December 31, 2015, Cove Point incurred approximately $2.2 billion of development and construction costs associated with the Liquefaction Project. 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 St. Charles Transportation Project and Keys Energy Project are estimated to be approximately $30 million

 

 

41

 



Table of Contents

 

 

   

and $40 million, respectively. Through December 31, 2015, we incurred approximately $13 million of costs associated with these projects. Service is expected to commence in June 2016 for the St. Charles Transportation Project and March 2017 for the Keys Energy Project.

  Total costs of the Edgemoor Project were approximately $35 million, of which Dominion Midstream incurred approximately $17 million subsequent to the DCG Acquisition. FERC approved the Edgemoor Project in February 2015, construction commenced in March 2015 and the project was placed into service in December 2015.
  Total costs of the Columbia to Eastover Project are estimated to be approximately $35 million. Through December 31, 2015, approximately $7 million of costs had been incurred, of which Dominion Midstream incurred approximately $4 million subsequent to the DCG Acquisition. In May 2015, DCG filed an application to request FERC authorization to construct and operate the project facilities, which are expected to be placed into service in the third quarter of 2016.
  Total costs of the Transco to Charleston Project are estimated to be approximately $120 million. Through December 31, 2015, approximately $5 million of costs had been incurred, all of which Dominion Midstream incurred subsequent to the DCG Acquisition. In July 2015, DCG requested authorization to utilize the FERC pre-filing process. DCG expects to file the application to request FERC authorization to construct and operate the project facilities in the first quarter of 2016. The project is expected to be placed into service in the fourth quarter of 2017.

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, St. Charles Transportation Project and Keys Energy 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 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, St. Charles Transportation Project and Keys Energy Project.

Distributions

Distributions are declared subsequent to quarter end. The table below summarizes the quarterly distributions declared during 2015.

 

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

 

(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.

Cash Flows

A summary of cash flows is presented below:

 

Year Ended December 31,    2015     2014     2013  
(millions)                   

Cash and cash equivalents at beginning of year

   $ 175.4      $ 11.2      $   

Cash flows provided by (used in):

      

Operating activities

     243.5        156.1        136.2   

Investing activities

     (1,282.7     (571.6     (294.8

Financing activities

     898.8        579.7        169.8   

Net increase (decrease) in cash and cash equivalents

     (140.4     164.2        11.2   

Cash and cash equivalents at end of year

   $ 35.0      $ 175.4      $ 11.2   

OPERATING CASH FLOWS

In 2015, net cash provided by Dominion Midstream’s operating activities increased by $87.4 million primarily due to the absence of federal and state income taxes subsequent to the Offering as well as net changes in working capital items and the DCG Acquisition.

INVESTING CASH FLOWS

In 2015, net cash used in Dominion Midstream’s investing activities increased by $711.1 million, primarily due to higher capital expenditures for the Liquefaction Project.

FINANCING CASH FLOWS

In 2015, net cash provided by Dominion Midstream’s financing activities increased by $319.1 million, primarily due to higher capital contributions from Dominion to fund the Liquefaction Project, partially offset by the absence of proceeds from the Offering.

CUSTOMER CONCENTRATION

Dominion Midstream provides service to approximately seventy customers, including the Storage Customers, marketers or end users, power generators, utilities and the Import Shippers. The two largest customers comprised approximately 71% of the total

 

 

42        

 



Table of Contents

 

 

transportation and storage revenues for the year ended December 31, 2015. 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 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, 2015. 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 Midstream’s current liabilities will be paid in cash in 2016.

 

      2016      2017-
2018
     2019-
2020
     2021
and
thereafter
     Total  
(millions)                                   

Affiliated long-term debt

   $       $ 300.8       $       $       $ 300.8   

Interest payments

     1.8         0.9                         2.7   

Purchase obligations(1):

              

Capital projects

     677.8         32.9                         710.7   

Other(2)

     1.0         0.6         0.6         2.5         4.7   

Other long-term liabilities(3):

              

CPCN obligation(4)

             16.4         8.8         6.8         32.0   

Total cash payments

   $ 680.6       $ 351.6       $ 9.4       $ 9.3       $ 1,050.9   
(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, 2015.

 

 

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.

Potential Acquisition

In February 2016, Dominion announced that it had entered into an agreement and plan of merger with Questar Corporation to acquire its outstanding common stock for approximately $4.4 billion in cash as well as the assumption of Questar Corporation’s outstanding debt. Upon closing of the transaction, Questar Corporation will become a wholly-owned subsidiary of Dominion. Subject to receipt of Questar Corporation shareholder and any required regulatory approvals and meeting closing conditions, Dominion targets closing by the end of 2016. Dominion announced its intended financing of the transaction would include an issuance of common units at Dominion Midstream in exchange for certain assets of Questar Corporation which are expected to be contributed to Dominion Midstream. We expect any future contributions to Dominion Midstream, subject to approval by the boards of Dominion and Dominion Midstream, to be submitted for approval by the Conflicts Committee.

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 $1.7 million, $1.2 million and $1.1 million during 2015, 2014, and 2013, respectively. These expenses are expected to approximate $1.1 million in both 2016 and 2017. In addition, capital expenditures related to environmental controls were $0.2 million, $3.7 million, and $5.9 million for 2015, 2014 and 2013, respectively. These expenditures are expected to approximate $0.2 million in both 2016 and 2017.

FUTURE ENVIRONMENTAL REGULATIONS

Air

The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, delegated states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Dominion Midstream’s facilities are subject to the CAA’s permitting and other requirements.

In January 2015, as part of its Climate Action Plan, the EPA announced plans to reduce methane emissions from the oil and gas sector including natural gas processing and transmission sources. In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR program, the Natural Gas STAR Methane Challenge Program. The proposed program covers the entire natural gas sector from production to distribution, with more emphasis on transparency and increased reporting for both annual emissions and reductions achieved through implementation measures. Until these regulations and guidelines are finalized, we are unable to predict future requirements or estimate compliance costs with certainty.

 

 

43

 



Table of Contents

 

 

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. The Cove Point Facilities and two compressor stations (one electric) in northern Virginia are located in areas that are designated nonattainment under the previous standard and are expected to retain nonattainment status under the new, more stringent standard. The rule is not expected to result in nonattainment status for any areas where DCG operates. 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.

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 interim plans to the EPA by summer 2016 identifying how they will comply with the rule, with final plans due 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 to regulate methane and VOC emissions from transportation and storage, gathering and boosting, production and processing facilities. All projects which commence construction after September 2015 will be required to comply with this regulation. Dominion Midstream is currently evaluating the proposed regulation and cannot predict future requirements or estimate compliance costs.

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. Dominion Midstream expects SCANA will provide funding for all material costs, if any, to satisfy the requirements imposed by the U.S. Army Corps of Engineers as required by 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.

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 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 million variable rate credit facility with Dominion. We may hedge the interest on portions of our borrowings under the credit facility from time-to-time in order to manage risks associated with floating interest rates. As of December 31, 2015, we have $5.9 million outstanding indebtedness against the credit facility. A hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at December 31, 2015.

 

 

44        

 



Table of Contents

Item 8. Financial Statements and Supplementary Data

 

 

      Page Number  

Report of Independent Registered Public Accounting Firm

     46   

Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013

     47   

Consolidated Balance Sheets at December 31, 2015 and 2014

     48   

Consolidated Statements of Equity and Partners’ Capital at December  31, 2015, 2014 and 2013 and for the years then ended

     50   

Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013

     51   

Notes to Consolidated Financial Statements

     52   

 

        45

 



Table of Contents

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”) at December 31, 2015 and 2014, and the related consolidated statements of income, equity and partners’ capital, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of Dominion Midstream’s 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 at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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 Midstream’s internal control over financial reporting at December 31, 2015, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2016 expressed an unqualified opinion on Dominion Midstream’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 26, 2016

 

46        

 



Table of Contents

Dominion Midstream Partners, LP

Consolidated Statements of Income

 

Year Ended December 31,    2015     2014      2013
(Predecessor)
 
(in millions, except per unit data)                    

Operating Revenue(1)

   $ 369.6      $ 313.3       $ 343.5   

Operating Expenses

       

Purchased gas(1)

     54.6        59.6         91.7   

Other operations and maintenance:

       

Affiliated suppliers

     22.1        9.4         7.7   

Other

     34.6        25.5         20.2   

Depreciation and amortization

     40.4        37.7         31.7   

Other taxes

     26.3        22.4         21.1   

Total operating expenses

     178.0        154.6         172.4   

Income from operations

     191.6        158.7         171.1   

Earnings from equity method investee

     6.6                  

Other income

     1.0                  

Interest and related charges(1)

     0.6                  

Income from operations including noncontrolling interest before income taxes

     198.6        158.7         171.1   

Income tax expense

     2.1        51.8         61.7   

Net income including noncontrolling interest and DCG Predecessor

   $ 196.5      $ 106.9       $ 109.4   

Less: Predecessor income prior to initial public offering on October 20, 2014

            80.6      

Less: Net income attributable to DCG Predecessor

     2.3             

Net income including noncontrolling interest

     194.2        26.3      

Less: Net income attributable to noncontrolling interest

     121.7        16.8      

Net income attributable to partners

   $ 72.5      $ 9.5      

Net income attributable to partners’ ownership interest(2)

       

General partner’s interest in net income

   $ (0.5   $      

Common unitholders’ interest in net income

     41.3        4.8      

Subordinated unitholder’s interest in net income

     31.7        4.7      

Net income per limited partner unit (basic and diluted)

       

Common units

   $ 1.08      $ 0.15      

Subordinated units

   $ 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 Midstream’s Consolidated Financial Statements.

 

        47

 



Table of Contents

Dominion Midstream Partners, LP

Consolidated Balance Sheets

 

At December 31,    2015     2014  
(millions)             
ASSETS     

Current Assets

    

Cash and cash equivalents

   $ 35.0      $ 175.4   

Customer and other receivables

     27.0        19.9   

Affiliated receivables

     6.2        6.1   

Prepayments

     10.6        9.5   

Materials and supplies

     12.5        8.7   

Regulatory assets

     1.7        1.7   

Other

     2.8        4.7   

Total current assets

     95.8        226.0   

Investment in Equity Method Affiliate

     220.5          

Property, Plant and Equipment

    

Property, plant and equipment

     3,845.7        2,203.1   

Accumulated depreciation and amortization

     (351.0     (231.2

Total property, plant and equipment, net

     3,494.7        1,971.9   

Deferred Charges and Other Assets

    

Goodwill

     295.5        45.9   

Intangible assets, net

     15.8        12.1   

Regulatory assets

     2.5        2.5   

Other

     0.4          

Total deferred charges and other assets

     314.2        60.5   

Total assets

   $ 4,125.2      $ 2,258.4   

 

48        

 



Table of Contents

 

 

At December 31,    2015     2014  
(millions)             
LIABILITIES AND EQUITY     

Current Liabilities

    

Accounts payable

   $ 8.6      $ 3.3   

Payables to affiliates

     5.2        2.5   

Accrued payroll and taxes

     6.0        1.5   

Regulatory liabilities

     6.7        3.6   

Dominion credit facility borrowings

     5.9          

Deferred revenue

     4.2        3.9   

Natural gas imbalances(1)

     1.0        2.7   

CPCN obligation

     8.0        7.9   

Other

     14.4        6.4   

Total current liabilities

     60.0        31.8   

Affiliated Long-Term Debt

     300.8          

Deferred Credits and Other Liabilities

    

Pension and other postretirement benefit liabilities(1)

     5.0        4.4   

Regulatory liabilities

     66.7        33.5   

CPCN obligation

     29.0        36.2   

Asset retirement obligation

     13.0        0.3   

Deferred revenue

     9.1          

Other

     0.6        1.4   

Total deferred credits and other liabilities

     123.4        75.8   

Total liabilities

     484.2        107.6   

Commitments and Contingencies (see Note 18)

                

Equity and Partners’ Capital

    

Common unitholders—public (27,867,938 and 20,127,322 units issued and outstanding at December 31, 2015 and 2014, respectively)

     600.8        395.4   

Common unitholder—Dominion (17,846,672 and 11,847,789 units issued and outstanding at December 31, 2015 and 2014, respectively)

     438.8        213.7   

Subordinated unitholder—Dominion (31,972,789 units issued and outstanding and December 31, 2015 and 2014)

     475.4        466.2   

General Partner interest—Dominion (non-economic interest)

     (12.4       

Total Dominion Midstream Partners, LP partners’ capital

     1,502.6        1,075.3   

Noncontrolling interest

     2,138.4        1,075.5   

Total equity and partners’ capital

     3,641.0        2,150.8   

Total liabilities and equity and partners’ capital

   $ 4,125.2      $ 2,258.4   

 

(1) See Note 20 for amounts attributable to related parties.

The accompanying notes are an integral part of Dominion Midstream’s Consolidated Financial Statements.

 

        49

 



Table of Contents

Dominion Midstream Partners, LP

Consolidated Statements of Equity and Partners’ Capital

 

 

 

     Partnership                       
     Predecessor
Members’
Equity
    DCG
Predecessor
Equity
    Common
Unitholders
Public
    Common
Unitholder
Dominion
    Subordinated
Unitholder
Dominion
    General
Partner
Dominion
(non-
economic
interest)
    Total
Dominion
Midstream
Partners, LP
Partners’
Equity and
Capital
    Noncontrolling
interest
    Total
Equity
and
Partners’
Capital
 
(millions)                                                      

December 31, 2012

  $ 698.5      $      $      $      $      $      $ 698.5      $      $ 698.5   

Net income

    109.4                                           109.4               109.4   

Equity contributions from Dominion

    464.1                                           464.1               464.1   

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 member’s 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 Dominion’s 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   

 

(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 Midstream’s Consolidated Financial Statements.

 

50        

 



Table of Contents

Dominion Midstream Partners, LP

Consolidated Statements of Cash Flows

 

Year Ended December 31,    2015     2014     2013
(Predecessor)
 
(millions)                   

Operating Activities

      

Net income including noncontrolling interest and DCG Predecessor

   $ 196.5      $ 106.9      $ 109.4   

Adjustments to reconcile net income including noncontrolling interest and DCG Predecessor to net cash provided by operating activities:

      

Depreciation and amortization

     40.4        37.7        31.7   

Deferred income taxes

     1.5        13.1        7.3   

Other adjustments

     (3.4              

Changes in:

      

Customer and other receivables

     (0.4     0.1        0.2   

Affiliated receivables

     (0.1     (1.4     (4.5

Prepayments

     (1.0     (4.6     (8.0

Accounts payable

     (1.3     0.3        (4.7

Payables to affiliates

     2.4        1.9        1.2   

Accrued payroll and taxes

     3.7        1.2        (5.9

Other operating assets and liabilities

     5.2        0.9        9.5   

Net cash provided by operating activities

     243.5        156.1        136.2   

Investing Activities

      

Plant construction and other property additions

     (1,282.1     (572.2     (294.6

Other

     (0.6     0.6        (0.2

Net cash used in investing activities

     (1,282.7     (571.6     (294.8

Financing Activities

      

Issuance of affiliated current borrowings, net

                   149.8   

Dominion credit facility borrowings

     5.9                 

Contributions from Dominion

     942.5        238.7          

Net proceeds from issuance of common units

            392.5          

Advance from affiliate

                   20.0   

Distributions to common unitholders—public

     (15.7              

Distribution to common unitholder—Dominion

     (11.3     (13.9       

Distribution to subordinated unitholder—Dominion

     (22.5     (37.6       

Other

     (0.1              

Net cash provided by financing activities

     898.8        579.7        169.8   

Increase (decrease) in cash and cash equivalents

     (140.4     164.2        11.2   

Cash and cash equivalents at beginning of period

     175.4        11.2          

Cash and cash equivalents at end of period

   $ 35.0      $ 175.4      $ 11.2   

Supplemental Cash Flow Information

      

Cash paid during the year for:

      

Interest and related charges, excluding capitalized amounts

   $ 0.4      $      $   

Income taxes

            38.6        52.6   

Significant noncash investing and financing activities:

      

Accrued capital expenditures

     16.3        6.7        8.4   

Increase in property, plant and equipment from CPCN obligation

            44.1          

Additional basis in property, plant and equipment received from Dominion

            23.2          

Settlement of net current and deferred income taxes

     13.4        147.9          

Equity contribution from Dominion to relieve payables to affiliates

     1.7        20.0        100.9   

Equity contribution from Dominion to relieve affiliated current borrowings

                   360.0   

Equity contribution from Dominion related to income taxes prior to the Offering

            1.2        3.2   

DCG Acquisition through issuance of debt and equity

     500.8                 

Acquisition of a noncontrolling partnership interest in Iroquois through issuance of equity

     216.0                 

The accompanying notes are an integral part of Dominion Midstream’s Consolidated Financial Statements.

 

        51

 



Table of Contents

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 on March 11, 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 (including 2,625,000 common units issued pursuant to the exercise of the underwriters’ over-allotment option) 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 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.

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 Midstream’s basis is equal to Dominion’s cost basis in the general partner interest in Cove Point and a portion of the Preferred Equity Interest. Dominion Midstream owns the general partner interest and controls Cove Point and therefore consolidates Cove Point. As such, Dominion Midstream’s investment in the Preferred

Equity Interest and Cove Point’s preferred equity interest are eliminated in consolidation. Dominion’s retained common equity interest in Cove Point is reflected as noncontrolling interest.

The DCG Acquisition is considered to be a reorganization of entities under common control. As a result, Dominion Midstream’s basis in DCG is equal to Dominion’s 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 have been retrospectively adjusted to include the historical results and financial position of DCG beginning January 31, 2015, the inception date of common control.

For the periods 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 Dominion’s 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 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 or Dominion Payroll to Dominion Midstream and Cove Point on the basis of direct and allocated methods in accordance with Dominion Midstream’s services agreements with DRS and Dominion Payroll and Cove Point’s 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 or Dominion Payroll 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 or Dominion Payroll department. 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.

 

 

52        

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

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 segment’s performance. See Note 23 for further discussions of Dominion Midstream’s operating segment.

 

 

NOTE 2. INITIAL PUBLIC OFFERING

On October 15, 2014, Dominion Midstream’s 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 Dominion’s 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;
  All of our IDRs;
  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:

  Dominion’s 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 Midstream’s basis is equal to Dominion’s cost basis in the general partner interest in Cove Point and a portion of the Preferred Equity Interest. Dominion’s 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 Point’s participation in Dominion’s intercompany tax sharing agreement, the settlement of Cove Point’s 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 Dominion’s 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 Dominion’s basis in Cove Point’s property, plant and equipment. Since this transaction was an exchange of ownership interest between entities under common control, Dominion Midstream’s basis equals Dominion’s historical basis.

 

 

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 Midstream’s 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 affiliated receivables, payables to affiliates and accounts payable are estimated to be substantially the same as their fair values at December 31, 2015 and 2014.

Cove Point participated in Dominion’s intercompany tax sharing agreement prior to the Offering. 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. Cove Point is currently generating significant revenue and earnings from annual reservation payments under long-term regasification, firm peaking storage and firm transportation contracts. Customer receivables at December 31, 2015 and 2014 included $19.9 million 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 will result in annual payments in the years 2013 through 2017 totaling approximately $50 million. DCG collects facility

 

 

53

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

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, 2015, DCG has collected $9.0 million in facility charges, including $8.0 million collected subsequent to the DCG Acquisition. These facility charges will be 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 storage services and transmission services; and
  Other revenue consists primarily of sales of purchased gas retained for use in routine operations and LNG cargos and the renegotiated contract payments described above.

Purchased Gas—Deferred 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 unitholder’s respective share of Dominion Midstream’s 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 Midstream’s 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, 2015, Dominion Midstream’s qualifying income exceeded the required amount. The Consolidated Financial Statements reflect management’s conclusion that Dominion Midstream’s 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 Point’s business activities were included in the consolidated U.S. federal income tax return filed by Dominion and its subsidiaries, DCPI’s Maryland state income tax returns and combined Virginia income tax returns filed by Dominion and certain subsidiaries. With Dominion Midstream’s 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 Midstream’s Consolidated Financial Statements reflect Cove Point’s income taxes for the period prior to the Offering.

DCG operated as a taxable corporation at the time of Dominion’s 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 Dominion’s acquisition of DCG through March 2015 will be included in the consolidated U.S. federal and certain state income tax returns of Dominion. Dominion Midstream’s Consolidated Financial Statements reflect income taxes for the same period.

Current income taxes for Cove Point and DCG were based on taxable income or loss, determined on a separate company basis, and, where applicable, settled in accordance with the principles of Dominion’s 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 Midstream’s reported amounts of assets and liabilities exceeded tax bases by $460.6 million at December 31, 2015.

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 Dominion’s tax sharing agreement, payments of federal and state income taxes of $38.6 million and $52.6 million were made to Dominion and DCPI for the years ended December 31, 2014 and 2013, respectively. In addition, the settlements of the federal and state net income tax payables and deferred income taxes of Cove Point and DCG are reflected as

 

 

54        

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

equity transactions in Dominion Midstream’s 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, 2015 and 2014, accounts payable included $0.8 million and $0.4 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.

Investment in Equity Method Affiliate

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 affiliate in the Consolidated Balance Sheets. Dominion Midstream records equity method adjustments in earnings from equity method affiliate 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 investment to determine whether a decline in fair value should be considered other-than-temporary. If a decline in fair value of the 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 2015, 2014 and 2013, Dominion Midstream capitalized interest costs and AFUDC of $2.0 million, $0.1 million and $0.7 million 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 property’s 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,    2015      2014      2013  
(percent)                     

Storage

     2.38         2.39         2.43   

Transmission

     3.15         2.81         2.83   

General and other

     7.01         4.09         3.71   

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 2013, Cove Point extended the useful life of existing expansion assets by nine years as a result of the Liquefaction Project, which resulted in a decrease to depreciation expense of $1.5 million ($1.0 million after tax).

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 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.

Materials and Supplies

Materials and supplies 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

 

 

55

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

price at period end, subject to the terms of its tariff for regulated entities. For Cove Point, imbalances are primarily settled in-kind. DCG settles all imbalances 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.

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. 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. At least annually, 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 are currently in the preliminary stages of evaluating the impact of this guidance on our results of operations and overall liquidity. We plan to complete our preliminary assessment, which includes a subset of representative contracts, in 2016. Once our initial evaluation is complete, we will expand the scope of our assessment to include all contracts with customers. Other than increased disclosures, the impacts of the revised accounting guidance to the results of operations and cash flows of Dominion Midstream cannot be determined until our assessment process is complete.

 

 

NOTE 4. ACQUISITIONS

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 Midstream’s common units for the 10 trading days prior to April 1, 2015, or $39.12 per unit. Subsequent to the DCG Acquisition, 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, and accordingly Dominion Midstream recognized a capital contribution by the general partner. The DCG Acquisition supports the expansion of Dominion Midstream’s 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 Midstream’s net investment in DCG is recorded at Dominion’s historical cost of $501.6 million as of April 1, 2015. Common control began on January 31, 2015, concurrent with Dominion’s acquisition of DCG from SCANA, which was accounted for using the acquisition method of accounting. Accordingly, the Consolidated Financial Statements of Dominion Midstream reflect DCG’s 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 Dominion’s 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 NG’s 20.4% and NJNR’s 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 Midstream’s 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 Midstream’s 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 Midstream’s common units at closing, including $0.5 million of external transaction costs.

 

 

56        

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

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 incentive distributions, by the weighted average number of common units 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 and IDRs.

Dominion Midstream’s net income is allocated to the limited partners in accordance with their respective partnership interests, after giving effect to priority income allocations for 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 limited partners based on their respective ownership interests. Payments made to Dominion Midstream’s 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 as of December 31, 2015 and 2014.

The calculation of earnings per limited partner unit is as follows:

 

Year Ended December 31,    2015     2014  
(millions)             

Net income attributable to partners

   $ 72.5      $ 9.5   

Less: General partner allocation(1)

     (0.7       

Distributions declared on(2):

    

IDRs(3)

     0.2          

Common unitholders(4)

     32.3        4.5   

Subordinated unitholder(4)

     24.8        4.4   

Total distributions declared

     57.3        8.9   

Undistributed earnings

   $ 15.9      $ 0.6   

 

(1) See Note 4 for further information.
(2) On January 21, 2016, the Board of Directors of our general partner declared a quarterly cash distribution of $0.2135 per unit, totaling
  $16.8 million for the three months ended December 31, 2015. This distribution was paid on February 15, 2016 to unitholders of record on February 5, 2016. The amount of distributions declared for the three months ended December 31, 2015 is based on the units outstanding at that date.
     On October 23, 2015, the Board of Directors of our general partner declared a quarterly cash distribution of $0.2000 per unit, totaling $15.5 million for the three months ended September 30, 2015. This distribution was paid on November 13, 2015 to unitholders of record on November 3, 2015.
     On July 17, 2015, the Board of Directors of our general partner declared a quarterly cash distribution of $0.1875 per unit, totaling $12.9 million, for the three months ended June 30, 2015. This distribution was paid on August 14, 2015 to unitholders of record on August 4, 2015.
     On April 22, 2015, the Board of Directors of our general partner declared a quarterly cash distribution of $0.1750 per unit, totaling $12.1 million, for the three months ended March 31, 2015. This distribution was paid on May 15, 2015 to unitholders of record on May 5, 2015.
     On January 23, 2015, the Board of Directors of our general partner declared a prorated initial quarterly cash distribution of $0.1389 per unit, totaling $8.9 million, for the period subsequent to the Offering. This distribution was paid on February 13, 2015 to unitholders of record on February 3, 2015. 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.
(3) Dominion is a non-economic general partner that holds all of the IDRs.
(4) Allocation of distributions for 2014 has been adjusted for rounding.

 

Basic and diluted net income
per limited partner unit
                           
Year Ended December 31, 2015  

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                   

 

Basic and diluted net income per

                limited partner unit

                       
Year Ended December 31, 2014(1)   

Common

Units

     Subordinated
Units
     Total  
(millions, except for weighted average units
and per unit data)
                    

Distributions declared(2)

     $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) Basic and diluted net income per limited partner unit subsequent to initial public offering.
(2) Allocation of distributions declared has been adjusted for rounding.
 

 

57

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

 

 

NOTE 6. UNIT ACTIVITY

Activity in number of units was as follows:

 

     Common                       
     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   

 

(1) These shares were purchased by Dominion as part of Dominion’s program initiated in September 2015 to purchase from the market up to $50.0 million of common units representing limited partner interests in Dominion Midstream by September 2016 at the discretion of Dominion’s management. In the first quarter of 2016, Dominion purchased 377,311 additional common units.

 

 

NOTE 7. OPERATING REVENUE

Operating revenue consists of the following:

 

Year Ended December 31,    2015      2014      2013  
(millions)                     

Gas transportation and storage

   $ 310.4       $ 257.2       $ 256.5   

Other

     59.2         56.1         87.0   

Total operating revenue

   $ 369.6       $ 313.3       $ 343.5   

 

 

NOTE 8. EQUITY METHOD INVESTMENTS

At December 31, 2015, Dominion Midstream used the equity method to account for its 25.93% noncontrolling partnership interest in Iroquois. During the year ended December 31, 2015, Dominion Midstream recognized earnings of $6.6 million and received distributions of $2.6 million. At December 31, 2015, the carrying amount of Dominion Midstream’s investment of $220.5 million exceeded its share of underlying equity in net assets by approximately $122.9 million. The difference reflects equity method goodwill and is not being amortized. See further discussion of Iroquois in Notes 1 and 14.

 

 

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,    2015      2014  
(millions)              

Storage

   $ 875.9       $ 882.0   

Transmission

     695.0         323.9   

Plant under construction

     2,236.3         972.3   

General and other

     38.5         24.9   

Total property, plant and equipment

   $ 3,845.7       $ 2,203.1   

The increase in property, plant and equipment is primarily related to the DCG Acquisition and capital expenditures for the Liquefaction Project.

 

NOTE 10. GOODWILL AND INTANGIBLE ASSETS

Goodwill

The changes in Dominion Midstream’s carrying amount and segment allocation of goodwill are presented below:

 

      Dominion
Energy
     Corporate
and
Other
     Total  
(millions)                     

Balance at December 31,
2013(1)

   $ 45.9       $       $ 45.9   

No events affecting goodwill

                       

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   

 

(1) There are no accumulated impairment losses.

Other Intangible Assets

Dominion Midstream’s other intangible assets are subject to amortization over their estimated useful lives. Dominion Midstream’s amortization expense for intangible assets was $2.1 million, $0.6 million and $0.6 million in 2015, 2014 and 2013, respectively. The increase in intangible assets in 2015 is primarily due to software acquired in the DCG Acquisition. The acquired intangible assets have an estimated weighted-average amortization period of approximately five years. In 2014, Dominion Midstream acquired $0.2 million of intangible assets, primarily representing software with an estimated weighted-average amortization period of approximately five years. The components of intangible assets are as follows:

 

At December 31,    2015      2014  
     

Gross

Carrying

Amount

    

Accumulated

Amortization

    

Gross

Carrying

Amount

    

Accumulated

Amortization

 
(millions)                            

Software and other

   $ 31.4       $ 23.3       $ 6.5       $ 2.4   

Licenses

     11.0         3.3         11.0         3.0   

Total

   $ 42.4       $ 26.6       $ 17.5       $ 5.4   
 

 

58        

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

Annual amortization expense for these intangible assets is estimated to be as follows:

 

      2016      2017      2018      2019      2020  
(millions)                                   
     $ 1.9       $ 1.1       $ 0.9       $ 0.6       $ 0.6   

 

 

NOTE 11. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities include the following:

 

At December 31,    2015      2014  
(millions)              

Regulatory assets:

     

Unrecovered gas costs(1)

   $ 1.4       $ 1.5   

Other

     0.3         0.2   

Regulatory assets-current

     1.7         1.7   

Income taxes recoverable through future rates(2)

     2.5         2.5   

Regulatory assets-non-current

     2.5         2.5   

Total regulatory assets

   $ 4.2       $ 4.2   

Regulatory liabilities:

     

Overrecovered gas costs(1)

   $ 0.1       $ 0.5   

LNG cargo obligations(3)

     3.0         3.0   

Customer bankruptcy settlement(4)

     3.1           

Other

     0.5         0.1   

Regulatory liabilities-current

     6.7         3.6   

Provision for future cost of removal(5)

     45.7         33.0   

Customer bankruptcy settlement(4)

     20.5           

Other

     0.5         0.5   

Regulatory liabilities-non-current

     66.7         33.5   

Total regulatory liabilities

   $ 73.4       $ 37.1   

 

(1) Reflects unrecovered/overrecovered gas costs, which are subject to annual filings with FERC.
(2) 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.
(3) Reflects obligations to the Import Shippers for LNG cargo received. See Note 12 for further information.
(4) 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.
(5) 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.

At December 31, 2015 and 2014, approximately $1.7 million of regulatory assets represented past expenditures on which Dominion Midstream does not currently earn a return. These expenditures are expected to be recovered within one year.

 

 

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 and DCG. FERC also has jurisdiction over siting,

construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

In May 2011, Cove Point filed a general rate case for its FERC jurisdictional services, with proposed rates to be effective July 2011. In July 2012, FERC issued an order approving a stipulation and agreement among Cove Point, FERC trial staff and the other active parties in the rate case resolving all issues set for hearing by FERC and establishing the mechanism for operational purchases of LNG, with settlement rates effective April 2012. Pursuant to the terms of the settlement, future operational purchases of LNG are not expected to affect Cove Point’s net results of operations. Cove Point and settling customers are subject to a rate moratorium through December 31, 2016. Cove Point is required to file its next rate case in 2016 with rates to be effective January 1, 2017.

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.

During the second quarter of 2013, DCG executed binding precedent agreements for the approximately $35 million Edgemoor Project. FERC approved the Edgemoor Project in February 2015, construction commenced in March 2015 and the project was placed into service in December 2015.

In April 2014, DCG executed a binding precedent agreement for the approximately $35 million Columbia to Eastover Project. In May 2015, DCG filed an application to request FERC authorization to construct and operate the project facilities, which are expected to be in service in the third quarter of 2016.

In October 2015, Cove Point received authorization to construct the approximately $30 million St. Charles Transportation Project and the approximately $40 million Keys Energy Project. The St. Charles Transportation Project is anticipated to be placed into service in June 2016. The Keys Energy Project is anticipated to be placed into service in March 2017.

 

 

59

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

 

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 Midstream’s long-lived assets. Dominion Midstream’s 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 2014 and 2015 are as follows:

 

      Amount  
(millions)       

AROs at December 31, 2013

   $ 0.4   

Obligations settled during the period

       

Revisions in estimated cash flows

       

Accretion

       

AROs at December 31, 2014(1)

   $ 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   

 

(1) Includes $0.1 million and $0.5 million reported in other current liabilities at December 31, 2014 and 2015, 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.

 

 

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 entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.

Iroquois

Dominion Midstream owns a 25.93% noncontrolling partnership interest in Iroquois. See Notes 1 and 8 for further detail regarding the nature of this entity. Dominion Midstream concluded that Iroquois is a VIE because a non-affiliated Iroquois equity holder has the ability during a limited period of time to transfer its ownership interests to another Iroquois equity holder or its affiliate. At December 31, 2015, Dominion Midstream concluded that it is not the primary beneficiary of Iroquois as it does not have the power to direct the activities of Iroquois that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. If Iroquois determines capital contributions are required, Dominion Midstream would be obligated to provide the portion of capital contributions based on its ownership percentage. Dominion

Midstream’s maximum exposure to loss is limited to its current and future investment.

DRS and Dominion Payroll

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 obtaining these services. For the years ended December 31, 2015 and 2014, these costs were $0.9 million and $0.1 million, respectively.

Additionally, in connection with Dominion’s 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 2016, DCGS will provide these services to DCG instead of Dominion Payroll.

In addition to the services purchased by our general partner, Dominion Midstream purchased shared services from DRS and Dominion Payroll of approximately $28.4 million during the year ended December 31, 2015. Cove Point purchased shared services from DRS of approximately $12.2 million and $9.3 million during the years ended December 31, 2014 and 2013, respectively. The Consolidated Balance Sheets at December 31, 2015 and 2014 include amounts due from Dominion Midstream to DRS and Dominion Payroll of approximately $2.8 million and $1.7 million, respectively.

Dominion Midstream determined that neither it nor any of its consolidated entities is the most closely associated entity with either DRS or Dominion Payroll, affiliated variable interest entities, and therefore none is the primary beneficiary. Neither Dominion Midstream nor any of its consolidated entities has any obligation to absorb more than its allocated share of DRS or Dominion Payroll costs.

 

 

NOTE 15. AFFILIATED LONG-TERM DEBT

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 fixed interest rate of 0.6%. Interest on the note is payable quarterly, and all principal and accrued interest is due and payable at maturity on April 1, 2017, which under certain conditions can be extended at the option of Dominion Midstream to October 1, 2017. Interest charges related to Dominion Midstream’s borrowing from Dominion were $1.4 million for the year ended December 31, 2015. At December 31, 2015, accrued interest payable to Dominion of $0.5 million was recorded in payables to affiliates on the Consolidated Balance Sheet.

The debt instrument described above is reported at historical cost. At December 31, 2015, the fair value of Dominion Midstream’s outstanding debt was $282.4 million. 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.

 

 

60        

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

The key terms of the note payable to Dominion include a prohibition on the incurrence of additional indebtedness (other than under the credit facility with Dominion discussed in Note 20) and a negative pledge applicable to liens on the assets of Dominion Midstream, but which does not apply to the assets of subsidiaries of Dominion Midstream. The note payable does not include any financial covenants. If Dominion Midstream fails to make payments under the note payable or becomes subject to bankruptcy or other insolvency proceedings, Dominion may accelerate Dominion Midstream’s payment obligations under the note payable.

 

 

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 employee’s compensation. As a participating employer, Cove Point is subject to Dominion’s funding policy, which is to contribute annually an amount that is in accordance with the provisions of ERISA. During 2015, Cove Point made no contributions to the Dominion Pension Plan, and no contributions to this plan are currently expected in 2016. Net periodic pension cost related to this plan was $1.4 million, $1.1 million and $1.4 million in 2015, 2014 and 2013, 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, 2015 and 2014, amounts due to Dominion associated with this plan, were $5.0 million and $3.5 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, $(0.4) million and $0.1 million for 2015, 2014 and 2013, respectively, 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, 2015 and 2014, liabilities to Dominion associated with this plan were less than $0.1 million and $0.9 million, respectively, 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 Point’s 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 $0.3 million, $0.2 million and $0.2 million of expense in other operations and maintenance expense in the Consolidated Statements of Income in 2015, 2014 and 2013, 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 Commission’s 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 Court’s Order affirming the Maryland Commission’s 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.

 

 

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

 

 

61

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

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 Midstream’s maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. Management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on Dominion Midstream’s 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, 2015, Cove Point had purchased $10.9 million of surety bonds. Under the terms of surety bonds, Cove Point 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 $2.8 million for the year ended December 31, 2015. 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 seventy customers, including the Storage Customers, marketers or end users, power generators, utilities and the Import Shippers. The two largest customers comprised approximately 71% of the total transportation and storage revenues for the year ended December 31, 2015, with Dominion Midstream’s largest customer representing approximately 57% of such amounts during the period.

For the years ended December 31, 2014 and 2013, Cove Point provided service to twenty-three customers, including the Storage Customers, sixteen marketers or end users and the Import Shippers. The three largest customers comprised approximately 93% and 94% of the total transportation and storage revenues for the years ended December 31, 2014 and 2013, respectively. Cove Point’s largest customer represented approximately 72% of such amounts in 2014 and 2013.

Dominion Midstream maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends and other information. At December 31, 2015 and 2014, the provision for credit losses was less than $0.1 million. Management believes, based on credit policies and the December 31, 2015 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 Midstream’s receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Cove Point participates in certain Dominion benefit plans as described in Note 16. Transactions related to the DCG 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 Dominion Payroll provides human resources and operations services to Dominion Midstream as a subsidiary service company. Refer to Note 14 for further information.

Dominion may seek reimbursement from DCG for costs incurred related to Dominion’s transition services agreement with SCANA to provide administrative functions related to DCG. Subsequent to the DCG Acquisition, DCG reimbursed Dominion a total of $2.9 million for such costs.

Dominion Midstream provides transportation services to affiliates and affiliates provide goods and services to Dominion Midstream.

 

 

62        

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

Affiliated transactions are presented below:

 

Year Ended December 31,    2015      2014      2013  
(millions)                     

Sales of natural gas transportation services to affiliates

   $ 2.2       $ 2.4       $ 2.3   

Purchased gas from affiliates

     0.5         0.6         0.7   

Goods and services provided by affiliates to Dominion Midstream(1)

     35.4         16.1         12.5   

 

(1) Includes $13.3 million, $6.7 million and $4.8 million of capitalized expenditures in 2015, 2014 and 2013, respectively.

Advance from Affiliate

During 2013, Cove Point received an advance from an affiliate of $20.0 million. This amount was converted to an equity contribution in March 2014. During 2013, $100.9 million of payables to affiliates were converted to an equity contribution.

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 Dominion’s 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, 2015, $5.9 million was outstanding against the credit facility. In January 2016, Dominion Midstream drew an additional $4.8 million against the credit facility, of which

$1.2 million was repaid in February 2016. No amounts were outstanding at December 31, 2014. 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. Interest charges related to Dominion Midstream’s borrowings against the facility were $0.1 million for the year ended December 31, 2015.

Subsidiary Debt Transactions

At December 31, 2013, Cove Point was no longer a participant in the Dominion money pool. Interest charges related to Cove Point’s borrowings from Dominion were $0.7 million for the year ended December 31, 2013. In 2013, Cove Point capitalized interest costs and AFUDC to property, plant and equipment of $0.7 million. During 2013, outstanding current borrowings of $360.0 million were converted to an equity contribution.

Income Taxes

As described in Note 21, prior to Dominion Midstream’s acquisition of the Preferred Equity Interest and non-economic general partner interest in Cove Point and its acquisition of DCG, Cove Point and DCG participated in Dominion’s intercompany tax sharing agreement.

In 2013, Cove Point settled $3.2 million of income taxes payable. 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 2015, DCG settled $13.4 million of income taxes payable and deferred income taxes. These settlements are reflected as equity transactions in Dominion Midstream’s Consolidated Financial Statements.

Cove Point’s participation in this tax sharing agreement was terminated in 2014 in connection with the Offering, and DCG’s participation was terminated in 2015 in connection with the DCG Acquisition.

Natural Gas Imbalances

Dominion Midstream maintains natural gas imbalances with affiliates. The imbalances with affiliates are provided below:

 

Year Ended December 31,    2015      2014  
(millions)              

Imbalances payable to affiliates

   $ 0.8       $ 2.5   

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

 

 

63

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

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 year ended December 31, 2015, Dominion contributed $941.2 million to Cove Point. In January 2016, Dominion contributed $69.1 million to Cove Point. These contributions from Dominion to Cove Point represent funding for capital expenditures related to the Liquefaction Project. 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 unitholder’s respective share of Dominion Midstream’s 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. Accordingly, Dominion Midstream’s 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.

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 Dominion’s 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 January 31, 2015 through March 31, 2015, will be included in the consolidated U.S. federal and certain state income tax returns of Dominion.

Current income taxes for Cove Point and DCG were based on taxable income or loss, determined on a separate company basis, and, where applicable, settled in accordance with the principles of Dominion’s intercompany tax sharing agreement. The settlement of DCG’s federal and state income taxes payable and net deferred income taxes is reflected as an equity transaction in Dominion Midstream’s Consolidated Financial Statements.

The income tax (benefit) provision is summarized as follows:

 

Year Ended December 31,    2015(1)      2014(2)      2013  
(millions)                     

Current:

        

Federal

   $ 0.5       $ 33.6       $ 47.4   

State

     0.1         5.1         7.0   

Total current expense

     0.6         38.7         54.4   

Deferred:

        

Federal

     1.3         9.9         11.7   

State

     0.2         3.2         (4.4

Total deferred expense

     1.5         13.1         7.3   

Total income tax expense

   $ 2.1       $ 51.8       $ 61.7   

 

(1) 2015 income taxes are attributable to the DCG Predecessor.
(2) Income taxes recognized prior to the Offering.

The statutory U.S. federal income tax rate reconciles to the effective income tax rate as follows:

 

Year Ended December 31,    2015     2014     2013  

U.S. statutory rate

     35.0     35.0     35.0

Partnership income not subject to income taxes(1)

     (34.1     (5.8       

Increases resulting from:

      

State taxes, net of federal benefit

     0.1        3.4        1.0   

Other, net

            0.1        0.1   

Effective tax rate

     1.0     32.7     36.1

 

(1) Reflects the pass-through entity status of Dominion Midstream, including the operations of DCG subsequent to the DCG Acquisition, and Cove Point.

The 2013 effective tax rate reflects a benefit resulting from a change in the allocation of Cove Point’s income to states.

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. Under a pre-CAP plan, the IRS audit of tax years 2012 and 2013 began in early 2014 and concluded in late 2015. The IRS audit of Dominion’s CAP tax year 2014 also began in 2014. The IRS issued a partial acceptance letter for tax year 2014 in late 2015 and completed its post-filing review in early 2016. The IRS audit of Dominion’s CAP tax year 2015 began in 2015. Accordingly, Dominion’s earliest tax year remaining open for federal examination is 2015. Dominion is obligated to report adjustments resulting from IRS settlements to state tax authorities.

In 2015, there were no unrecognized tax benefits, and amounts for 2014 and 2013 were immaterial.

For Cove Point, the earliest tax year remaining open for examination by Maryland tax authorities is 2012. Since DCG was included in SCANA’s 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.

Dominion will pay any additional income taxes assessed by tax authorities related to DCG’s business activities during the period January 31, 2015 through March 31, 2015, and Cove Point’s 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

 

 

64        

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

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   

For the years ended December 31, 2015 and 2014, $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 Midstream’s 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 Midstream’s operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources among the segments. In 2015, expenses of $1.7 million were recorded related to certain transition costs associated with the DCG Acquisition. In 2013, there was a net charge of $0.1 million related to severance. There were no such items in 2014.

The following table presents segment information pertaining to Dominion Midstream’s operations:

 

Year Ended December 31,    Dominion
Energy
    

Corporate and

Other

    Consolidated
Total
 
(millions)                    

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   

Total assets at December 31

     2,258.4                2,258.4   

2013

       

Operating revenue

   $ 343.5       $      $ 343.5   

Depreciation and amortization

     31.7                31.7   

Interest and related charges

                      

Income tax expense

     61.7                61.7   

Net income (loss) including noncontrolling interest

     109.5         (0.1     109.4   

Capital expenditures

     294.6                294.6   
 

 

65

 



Table of Contents

Notes to Consolidated Financial Statements, Continued

 

 

 

NOTE 24. QUARTERLY FINANCIAL AND PER UNIT DATA (UNAUDITED)

A summary of Dominion Midstream’s quarterly results of operations for the years ended December 31, 2015 and 2014 follows. The information includes the results of operations of our Predecessor prior to October 20, 2014 and of Dominion Midstream for the period beginning October 20, 2014, the date the Offering was completed, through December 31, 2014. Net income per unit is only calculated after the Offering, as no units were outstanding prior to October 20, 2014. 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
    Fourth
Quarter
    Full Year  
(millions, except per
unit data)
                             

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   

Distributions declared per unit

    0.1750        0.1875        0.2000        0.2135        0.7760   

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
  
  

2014

         

Operating revenue

  $ 68.9      $ 111.2      $ 65.7      $ 67.5      $ 313.3   

Income from operations

    39.8        39.2        42.8        36.9        158.7   

Net income including noncontrolling interest

    24.6        24.2        26.4        31.7        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   

Net income subsequent to initial public offering per unit (basic and diluted)

         

Common Units

        $ 0.15      $ 0.15   

Subordinated Units

                            0.15        0.15   

Distributions declared per unit

          0.1389 (1)      0.1389   

Unit prices (intraday high-low)

                          $
 
39.40 -
21.81
  
  
  $
 
39.40 -
21.81
  
  
(1) On January 23, 2015, the Board of Directors of our general partner declared a prorated initial quarterly cash distribution of $0.1389 per unit, totaling $8.9 million, for the period subsequent to the Offering. This distribution was paid on February 13, 2015 to unitholders of record on February 3, 2015. 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.
 

 

66        

 



Table of Contents

 

 

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

 

 

Item 9A. Controls and Procedures

Senior management of Dominion Midstream’s general partner, Dominion Midstream GP, LLC, including its CEO and CFO, evaluated the effectiveness of Dominion Midstream’s 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 Midstream’s general partner have concluded that Dominion Midstream’s disclosure controls and procedures are effective. There were no changes in Dominion Midstream’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion Midstream’s internal control over financial reporting.

MANAGEMENTS ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Dominion Midstream’s general partner understands and accepts responsibility for Dominion Midstream’s 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 Midstream’s 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 Midstream’s 2015 Annual Report to contain a management’s 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,

2015, Dominion Midstream’s 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 Midstream’s internal control over financial reporting as of December 31, 2015. 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, 2015.

Dominion Midstream’s independent registered public accounting firm is engaged to express an opinion on Dominion Midstream’s internal control over financial reporting, as stated in their report which is included herein.

In April 2015, Dominion Midstream acquired DCG. Dominion Midstream excluded all of the acquired DCG business from the scope of management’s assessment of the effectiveness of Dominion Midstream’s internal control over financial reporting as of December 31, 2015. DCG constituted 17% of Dominion Midstream’s total revenues for 2015 and 14% of Dominion Midstream’s total assets as of December 31, 2015.

February 26, 2016

 

 

67

 



Table of Contents

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”) at December 31, 2015, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Annual Report on Internal Control over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Dominion Carolina Gas Transmission, LLC (“DCG”), which was acquired April 1, 2015, and whose financial statements constitute 17% of total revenues and 14% of total assets of the consolidated financial statement amounts at and for the year ended December 31, 2015. Accordingly, our audit did not include the internal control over financial reporting at DCG. Dominion Midstream’s 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 Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion Midstream’s 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 company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Dominion Midstream maintained, in all material respects, effective internal control over financial reporting at December 31, 2015, based on the criteria established in Internal Control—Integrated 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 at and for the year ended December 31, 2015 of Dominion Midstream and our report dated February 26, 2016 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 26, 2016

 

 

Item 9B. Other Information

None.

 

68        

 



Table of Contents

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 five members and has determined that Joseph M. Rigby, 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 of Dominion, and our general partner secures the personnel necessary to conduct our operations through its services agreements. 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 and Executive Officers of Our General Partner

The following table shows information for the directors and executive officers 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. Executive officers serve at the discretion of the Board of Directors. There are no family relationships among any of our directors or executive officers. Some of our directors and all of our executive officers also serve as executive officers of Dominion.

 

Name   Age     Position With Our General Partner

Thomas F. Farrell II

    61     

Chairman, President and CEO

Mark F. McGettrick

    58     

Director, Executive Vice President and CFO

Joseph M. Rigby

    59     

Director

John W. Snow

    76     

Director

David A. Wollard

    78     

Director

David A. Christian

    61     

Executive Vice President

Michele L. Cardiff

    48     

Vice President, Controller and Chief Accounting Officer

Robert M. Blue

    48     

Senior Vice President—Law, Regulation & Policy

Paul E. Ruppert

    51     

Senior Vice President—Dominion Midstream Operations

Thomas F. Farrell II has served as the Chairman of the Board of Directors and CEO of our general partner since March 2014 and President since February 2015. Mr. Farrell has also served as the Chairman of the Board of Directors, President and CEO of Dominion from April 2007 to date. He has also served as Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date and Dominion Gas from September 2013 to date. Mr. Farrell also serves as a director of Altria Group, Inc.

Mr. Farrell’s 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.

Mark F. McGettrick has served as a director, Executive Vice President and CFO of our general partner since March 2014. Mr. McGettrick has also served as Executive Vice President and CFO of Dominion and Virginia Power from June 2009 to date and Dominion Gas from September 2013 to date. Mr. McGettrick has served as a director of Virginia Power from June 2009 to date and Dominion Gas from September 2013 to date.

Mr. McGettrick’s qualifications to serve as a director include his more than 35 years of utility management and industry experience. He recently served on the George Mason University board of visitors and is on the Board of Directors of the Dominion Foundation. Mr. McGettrick also has community and public interest involvement and serves or has served on many non-profit foundations and boards.

Joseph M. Rigby has served as a director of our general partner since October 2014. Mr. Rigby has been chairman, president and CEO since May 2009 of PHI, an energy delivery company serving the Mid-Atlantic region. Mr. Rigby received his bachelor’s degree in accounting from Rutgers University and an MBA from Monmouth University. He is also a licensed Certified Public Accountant in the state of New Jersey.

Mr. Rigby’s qualifications to serve as a director include his 37 years of experience with PHI and its subsidiaries and in the utility industry. As the CEO of PHI, he has leadership, corporate management, governance, and regulatory experience, among other business disciplines. He also has finance, human resources, and mergers and acquisitions experience through positions held with PHI and its subsidiaries. Mr. Rigby serves on the boards of the U.S. Chamber of Commerce, the Edison Electric Institute and Energy Insurance Mutual and serves or has served on other non-profit foundations and boards.

John W. Snow has served as a 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. 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 bachelor’s degree from the University of Toledo, a master’s degree from Johns Hopkins University, a doctorate in economics from the University of Virginia and a juris doctor degree from George Washington University.

Mr. Snow’s qualification to serve as a director includes 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

 

 

        69

 



Table of Contents

 

 

management, governance, finance, and regulatory experience, among other business disciplines.

David A. Wollard has served as a 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 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. Wollard’s 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.

David A. Christian has served as Executive Vice President of our general partner since January 2016. Mr. Christian has also served as the Executive Vice President and CEO-Energy Infrastructure Group of Dominion since January 2016, President and COO of Virginia Power since June 2009 and President of Dominion Gas since January 2016. Mr. Christian previously served as the Executive Vice President and CEO-Dominion Generation Group of Dominion from February 2013 to December 2015 and Executive Vice President of Dominion from April 2006 to February 2013.

Michele L. Cardiff has served as the Vice President, Controller and Chief Accounting Officer of our general partner since March 2014, Dominion and Virginia Power since April 2014 and Dominion Gas since March 2014. Ms. Cardiff previously served as the Vice President—Accounting of DRS from January 2014 to March 2014, Vice President and General Auditor of DRS from September 2012 to December 2013, and Controller of Virginia Power from June 2009 to August 2012.

Robert M. Blue has served as Senior Vice President—Law, Regulation & Policy of our general partner since February 2016. Mr. Blue has also served as Senior Vice President—Law, Regulation & Policy of Dominion and Dominion Gas since February 2016 and President of Virginia Power since January 2016. Mr. Blue previously served as Senior Vice President—Regulation, Law, Energy Solutions and Policy of Virginia Power from May 2015 to December 2015, and our general partner, Dominion, and Dominion Gas from July 2015 to January 2016. He also served as President of Virginia Power from January 2014 to May 2015, and Senior Vice President—Law, Public Policy and Environment of Dominion from January 2011 to December 2013.

Paul E. Ruppert has served as Senior Vice President—Dominion Midstream Operations of our general partner since January 2016. Mr. Ruppert previously served as Senior Vice President—Business Development & Generation Construction of Virginia Power from April 2012 to December 2015 and Senior Vice President of DTI from June 2009 to March 2012.

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, 2015, with the exception of one late Form 3 filed for Mr. Blue due to an inadvertent clerical error. Mr. Blue became a Section 16 officer of the general partner in July 2015, and his Form 3 was filed in October 2015.

Audit Committee

The members of the Audit Committee are David A. Wollard (chairman), Joseph M. Rigby 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, Rigby 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 Joseph M. Rigby (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 Midstream’s 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

 

 

70        

 



Table of Contents

 

 

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, Dominion’s 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, 2015. This report was prepared by the following independent directors who compose the CGN Committee:

David A. Wollard, Chairman

William P. Barr

John W. Harris

Mark J. Kington

Robert H. Spilman, Jr.

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 Dominion’s CEO as applicable under Dominion’s 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 2015.

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 2015 are our NEOs subject to disclosure in this Item 11. Mr. Koonce is our only other executive officer who

received at least $100,000 in Dominion Midstream compensation for 2015.

The Compensation Discussion and Analysis and Executive Compensation sections of Dominion’s 2016 Proxy Statement will include additional discussion of Dominion’s compensation policies and programs. Dominion’s 2016 Proxy Statement will be available upon its filing on the SEC’s website at http://www.sec.gov and on Dominion’s website at http://www.dom.com/investors.

Compensation Discussion and Analysis

Dominion’s 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 2015, our NEOs are:

  Thomas F. Farrell II, Chairman, President and CEO
  Mark F. McGettrick, Executive Vice President and CFO
  Paul D. Koonce, Executive Vice President and CEO – Energy Infrastructure Group (began serving as Executive Vice President and CEO – Dominion Generation Group effective January 1, 2016)

All of our NEOs are also NEOs of Dominion for 2015. 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 Dominion’s 2016 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 Dominion’s business and strategic plans and contributes to the long-term success of the company;
  Align the interests of management with those of Dominion’s 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 Dominion’s four core values of safety, ethics, excellence and One Dominion – Dominion’s term for teamwork.

To determine if the program is meeting these objectives, the CGN Committee compares the company’s actual performance to its short-term and long-term goals and to peer companies’ performance.

 

 

        71

 



Table of Contents

 

 

INDIVIDUAL FACTORS IN SETTING COMPENSATION

In addition to considering Dominion’s goals and performance, the CGN Committee also considers several individual factors for each NEO, including:

  Job performance
  Scope, complexity and significance of job responsibilities
  Internal pay equity considerations, such as relative importance of a particular position or individual officer to Dominion’s strategy and success, and comparability to other officer positions at Dominion
  Experience, background and tenure
  Retention and market competitive concerns
  The executive’s role in any succession plan for other key positions

These individual factors are important considerations in setting base pay and short- and long-term compensation opportunities.

AT RISK COMPENSATION OPPORTUNITIES IN 2015

Consistent with Dominion’s 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 at risk. Approximately 88% of Mr. Farrell’s targeted 2015 total direct compensation is performance-based, tied to pre-approved performance metrics, including relative TSR and ROIC, or tied to the performance of Dominion’s stock. For the other NEOs of Dominion, performance-based and stock-based compensation ranges from 67% to 79% of targeted 2015 total direct compensation. This compares to an average of approximately 55% of targeted compensation at risk for Dominion officers at the vice president level and an average of approximately 12% of total pay at risk for Dominion’s non-officer employees.

The charts below illustrate the elements of targeted total direct compensation opportunities in 2015 for Mr. Farrell and the average of the other Dominion NEOs as a group and the allocation of such compensation among base salary, targeted 2015 AIP award and targeted 2015 long-term incentive compensation.

 

 

 

LOGO

 

Compensation Elements

Dominion’s 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 slightly above the Compensation Peer Group median, subject to the individual and company-wide considerations discussed above under Compensation Philosophy.

The CGN Committee approved base salary increases for officers, including a 3% increase for Messrs. Farrell and Koonce in recognition of the company’s continued performance. The CGN Committee also approved a 10% increase for Mr. McGettrick in recognition of superior performance, the successful implementation of Dominion Midstream and the highly competitive market for chief financial officer talent. The base salary increases were each effective March 1, 2015.

ANNUAL INCENTIVE PLAN

The AIP is a cash-based program focused on short-term goals, and it is designed to:

  Tie interests of shareholders, customers and employees closely together
  Focus Dominion’s workforce on company, operating group, team and individual goals that ultimately influence operational and financial results
  Reward corporate and operating unit earnings performance
  Reward safety, diversity and other operating and stewardship goal successes
  Emphasize teamwork by focusing on common goals
  Provide a competitive total compensation opportunity

For the NEOs, funding of the 2015 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.

 

 

72        

 



Table of Contents

 

 

The CGN Committee calculated 2015 AIP payouts for the NEOs as follows:

 

 

LOGO

 

Target Award Percentage

Each NEO’s compensation opportunity under the AIP is a percentage of his base salary. AIP target award percentages are set to be consistent with Dominion’s 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 NEO’s AIP target award percentage from 2014 to 2015.

 

      2015 AIP Target
Award Percentage*
 

Thomas F. Farrell II

     125

Mark F. McGettrick

     100

Paul D. Koonce

     90

 

*As a percentage of base salary

Funding Level

For NEOs, the funding level is determined solely by consolidated operating earnings, which are Dominion’s reported earnings determined in accordance with GAAP, adjusted for certain items. The company believes that focus on pre-established consolidated operating earnings per share targets encourages behavior and performance that will help achieve these objectives.

For the NEOs, the CGN Committee set the consolidated operating earnings goal to provide for 100% funding of the 2015 AIP between $3.35 and $3.62 per share, inclusive of funding for all plan participants. The target for maximum funding of 200% was set at $3.85 operating earnings per share. The CGN Committee also established a funding floor, providing no funding if operating earnings were less than $3.30 per share.

Dominion’s consolidated operating earnings for the year ended December 31, 2015 were $2.0 billion or $3.44 per share*, which met the target goal for 100% funding, and consolidated reported earnings in accordance with GAAP for the year ended December 31, 2015 were $1.9 billion or $3.20 per share. However, Dominion did not meet its 2015 earnings guidance, due in part to lower wholesale power prices in New England, where its Millstone and Manchester Street power stations operate; lower prices for the natural gas liquids Dominion produces; and mild weather late in the year. Accordingly, the CGN Committee exercised its negative discretion, approving a funding percentage of 20%.

*Reconciliation of 2015 Consolidated Operating Earnings to Reported Earnings. The following items, which are net of tax, are included in Dominion’s 2015 reported earnings, but are excluded from consolidated operating earnings: $52 million charge associated with Virginia legislation enacted in February that required the write-off of Virginia Power prior-period deferred fuel costs during the first

quarter of 2015; $60 million charge associated with the AROs for ash ponds and landfills at certain utility generation facilities in connection with the enactment of EPA coal combustion residuals rules in the second quarter of 2015; $17 million net charge in connection with the State Corporation Commission of Virginia’s final ruling associated with its biennial review of Virginia Power’s base rates for 2013-2014 test years; $12 million net expense related to other items.

Payout Goal Score

In determining whether and how to exercise its negative discretion, the CGN Committee typically considers each NEO’s accomplishment of pre-determined business unit financial goals and operating and stewardship goals, weighted according to each NEO’s responsibilities. For 2015, in light of the low funding level approved for the 2015 AIP, the CGN Committee considered only accomplishment of safety goals for each NEO.

Each NEO received full credit for his safety goal. With respect to Messrs. Farrell and McGettrick, the DRS business unit met its safety goal of fewer than four OSHA recordable incidents or fewer than 19 failures in individual performance.

Mr. Koonce was part of the Dominion Virginia Power and Dominion Energy business units in 2015. His safety goal was measured by a combination of the OSHA recordable rate and lost-time/ restricted duty rate for each business unit, in addition to each business unit’s implementation of plans to evaluate and reduce safety risks. His safety goal was fully achieved, with the Dominion Virginia Power business unit attaining an OSHA recordable incident rate of 1.19 and a lost-time/restricted duty rate of 0.31, and the Dominion Energy business unit attaining an OSHA incident rate of 1.12 and a lost-time/restricted duty rate of 0.43.

Each NEO therefore received a payout goal score of 100%.

 

 

        73

 



Table of Contents

 

 

Final AIP Payout

The CGN Committee calculated final 2015 AIP payouts as shown below.

 

      Base
Salary
           Target
Award*
          Funding
Level
         

Payout

Goal Score

          Final AIP
Payout
 

Thomas F. Farrell II

   $ 16,300       X      125   X      20   X      100   =    $ 4,075   

Mark F. McGettrick

     15,911       X      100      X      20      X      100      =      3,182   

Paul D. Koonce

     31,298       X      90      X      20      X      100      =      5,634   

 

*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

Dominion’s 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 an increase in Mr. Farrell’s long-term incentive award target for 2015 in recognition of the complexity of Dominion’s operations, earnings growth over the prior three-year period and shareholder value created during his tenure as CEO, as well as his leadership experience, accomplishments and other individual performance factors. There were no changes to the long-term incentive targets for any of the other NEOs. The 2015 targets for the NEOs were approved as follows:

 

      2015
Performance
Grant
     2015 Restricted
Stock Grant
     2015 Total Target
Long-Term
Incentive Award
 

Thomas F. Farrell II

   $ 49,489       $ 49,489       $ 98,978   

Mark F. McGettrick

     22,423         22,423         44,846   

Paul D. Koonce

     34,373         34,373         68,746   

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.

2015 Restricted Stock Grants

All NEOs received a restricted stock grant on February 1, 2015, 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 Dominion’s common stock on January 30, 2015. The grants have a three-year vesting term, with cliff vesting at the end of the restricted period on February 1, 2018. Dividends are paid to officers during the restricted period.

2015 Performance Grants

In January 2015, the CGN Committee approved cash performance grants for the NEOs, effective February 1, 2015 (2015

Performance Grants). The performance period commenced on January 1, 2015, and will end on December 31, 2016. The 2015 performance grants are denominated as a target dollar value, with potential payouts ranging from 0% to 200% of the target based on Dominion’s 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 2015 performance grants may also be earned based on Dominion’s 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 company’s 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 company’s 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 company’s 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 Koonce have each met their full targeted share ownership guidelines, they each received the performance-based component of their 2015 long-term incentive award in the form of a cash performance grant.

Performance Grant Peer Group

TSR performance for the 2015 performance grant is measured against the TSR of the companies listed as members of the

 

 

74        

 



Table of Contents

 

 

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 Dominion’s Compensation Peer Group, and the index is a recognized published index whose members are determined externally and independently from the company. The companies (other than Dominion) in the Philadelphia Stock Exchange Utility Index as of the grant date of the 2015 performance grants were as follows:

 

•    The AES Corporation

•    Ameren Corporation

•    American Electric Power Company, Inc.

•    CenterPoint Energy, Inc.

•    Consolidated Edison, Inc.

•    Covanta Holding Corporation

•    DTE Energy Company

•    Duke Energy Corporation

•    Edison International

  

•    El Paso Electric Company

•    Entergy Corporation

•    Exelon Corporation

•    FirstEnergy Corp.

•    NextEra Energy Inc.

•    Northeast Utilities

•    PG&E Corporation

•    Public Service Enterprise Group Incorporated

•    The Southern Company

•    Xcel Energy, Inc.

2014 Performance Grant Payout

In February 2016, final payouts were made to officers who received cash performance grants in February 2014 (2014 performance grants), including the NEOs. The 2014 performance grants were based on two goals: TSR for the two-year period ended December 31, 2015, 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%).

  Relative TSR (50% weighting). The relative TSR targets and corresponding payout scores for the 2014 performance grant were as follows:

 

Relative TSR Performance Percentile Ranking    Goal
Achievement %*
 

85th or above

     200

50th

     100

25th

     50

Below 25th

     0

 

* TSR weighting is interpolated between the top and bottom of the percentages within a quartile. If the company’s 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 company’s relative TSR, if the company’s 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 2014-2015 period was in the 26th percentile, which produced a goal achievement percentage of 52.6%. Dominion’s TSR for the two-year period ended December 31, 2015, was 6.1%.

  ROIC (50% weighting). Dominion designed the ROIC goals for the 2014 performance grant to provide 100% payout if
   

the company achieved an ROIC between 6.86% and 7.16% over the two-year performance period. The ROIC performance targets and corresponding payout scores for the 2014 performance grant were as follows:

 

ROIC Performance    Goal
Achievement %*
 

7.68% and above

     200

7.38%

     125

6.86% – 7.16%

     100

6.78%

     50

Below 6.78%

     0

 

* ROIC percentage payout is interpolated between the top and bottom of the percentages for any range.

Actual ROIC performance for the 2014-2015 period was 7.00%, 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 2014 Performance Grants, determined as follows:

 

Measure   Goal
Weight %
             Goal
Achievement %
            Payout %  

Relative TSR

    50      X         52.6     =         26.3

ROIC

    50      X         100     =         50.0
      Combined Overall Performance Score         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 2014 performance grants are shown below.

 

      2014 Performance
Target Grant Award
             Overall
Performance
Score
            Calculated
Performance
Grant Payout
 

Thomas F. Farrell II

   $ 46,708         X         76.3     =       $ 35,638   

Mark F. McGettrick

     22,423         X         76.3     =         17,109   

Paul D. Koonce

     34,373         X         76.3     =         26,227   

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 Dominion’s 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 Dominion’s 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.

 

 

        75

 



Table of Contents

 

 

Dominion also maintains two nonqualified retirement plans for Dominion’s 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 Dominion’s 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 officer’s 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 2015.

Other Benefit Programs

Dominion’s 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 officer’s 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:

  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 Dominion’s retirement and other employee benefit programs.
  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.
  In limited circumstances, use of corporate aircraft for personal travel by executive officers. For security and other reasons, Dominion’s Board of Directors has directed Mr. Farrell to use the corporate aircraft for air travel, including personal travel. Mr. Farrell’s family and guests may accompany him on any 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 executive’s 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 2015, 95% of the use of Dominion’s 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 Dominion’s 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 company’s 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

 

 

76        

 



Table of Contents

 

 

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 nation’s 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 2015.

Dominion’s Process

The CGN Committee is responsible for reviewing and approving NEO compensation and Dominion’s overall executive compensation program. Each year, the CGN Committee reviews a comprehensive analysis of the executive compensation program, including the elements of each NEO’s compensation, with input from senior management and the CGN Committee’s 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 company’s senior officers, reviews executive officer share ownership guidelines and compliance, and establishes compensation programs designed to achieve Dominion’s objectives.

The CGN Committee evaluates each NEO’s 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 Dominion’s Compensation Peer Group. To ensure the compensation levels are appropriately competitive and consistent with the company’s 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 Dominion’s size, including market capitalization and price-to-earnings ratio, and complexity compared to the companies in Dominion’s 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. as its independent compensation consultant to advise the CGN Committee on executive and director compensation matters. The CGN Committee’s consultant:

  Attends meetings as requested by the CGN Committee, either in person or by teleconference;
  Communicates directly with the chairman of the CGN Committee outside of the CGN Committee meetings as needed;
  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;
  Reviews and comments on proposals and materials prepared by management and answers technical questions, as requested; and
  Generally reviews and offers advice as requested by or on behalf of the CGN Committee regarding other aspects of Dominion’s executive compensation program, including best practices and other matters.

In 2015, the CGN Committee reviewed and assessed the independence of Cook & Co. and concluded that Frederic W. Cook & Co.’s work did not raise any conflicts of interest. Frederic W. Cook & Co. did not provide any additional services to Dominion during 2015.

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 Dominion’s internal compensation and financial specialists, assist in the design of Dominion’s 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.

 

 

        77

 



Table of Contents

 

 

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 2015 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. Dominion also considers the geographic locations and the regulatory environment in which potential peer companies operate.

Dominion’s Compensation Peer Group is generally consistent from year to year, with merger and acquisition activity being the primary reason for changes. No changes were made to the Compensation Peer Group for 2015, except that CMS Energy Corporation was replaced with CenterPoint Energy, Inc. based on size and business model considerations. Dominion’s Compensation Peer Group for 2015 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 Dominion’s 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 Dominion’s 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 Dominion’s 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 Dominion’s 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 Dominion’s

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. Farrell’s position results in overall CEO compensation that is significantly higher than the compensation of the other NEOs. Mr. Farrell’s 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 Dominion’s 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. Farrell’s 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 2015.

Governance

Dominion’s 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:

ü  Balance short- and long-term incentives

ü  Place a substantial portion of NEO pay at risk and tied to enhanced shareholder value

ü  Use different performance measures for annual and long-term incentive programs

ü  Review the executive compensation program to ensure it does not promote excessive risk taking

ü  Measure relative TSR for its performance grant payout using the Philadelphia Stock Exchange Utility Index, an independently-determined peer group

ü  Maintain rigorous share ownership guidelines

ü  Incorporate clawback provisions in incentive compensation

ü  Include a non-compete clause in executive retirement plans

ü  Proactively engage with top shareholders on compensation and governance issues

ü  Conduct annual Say on Pay votes

ü  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 indefinite 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)

 

 

78        

 



Table of Contents

 

 

ANNUAL COMPENSATION RISK REVIEW

Dominion’s management, including Dominion’s Chief Risk Officer and other executives, annually reviews the overall structure of the company’s 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:

  Analysis of how different elements of the compensation program may increase or mitigate risk-taking;
  Analysis of performance metrics used for short- and long-term incentive programs and the relation of such incentives to the objectives of the company;
  Analysis of whether the performance measurement periods for short- and long-term incentive compensation are appropriate; and
  Analysis of the overall structure of compensation programs as related to business risks.

Among the factors considered in management’s 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 Committee’s 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 management’s review, the CGN Committee believes the company’s 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 company’s 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 officer’s 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, 2016, Messrs. Farrell, McGettrick and Koonce each exceeded their share ownership targets as shown below:

 

      Shares Owned and
Counted Toward  Target(1)
     Share Ownership Target(2)  

Thomas F. Farrell II

     780,774         145,000   

Mark F. McGettrick

     209,372         35,000   

Paul D. Koonce

     122,790         35,000   

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

Dominion’s 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 the company’s operations or the employee’s duties at the company. The company 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

 

 

        79

 



Table of Contents

 

 

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 SEC’s proposed compensation recovery rules under the Dodd-Frank Wall Street Reform and Consumer Protection Act. Currently, the company 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 Dominion’s 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

Dominion’s shareholders voted on an advisory basis on its executive compensation program (also known as Say on Pay) and approved it with an 86% vote at Dominion’s 2015 Annual Meeting of Shareholders, which followed an approval by a 97% vote in 2014. After considering feedback received from shareholders and business drivers, the CGN Committee retained the overall structure of Dominion’s compensation program and did not grant any off-cycle long-term incentive awards to NEOs in 2015.

 

 

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 NEO’s services performed for Dominion Midstream. The approximate percentage of each NEO’s overall Dominion services performed for Dominion Midstream during 2015 was as follows: 1.11% for Mr. Farrell; 1.92% for Mr. McGettrick; and 4.72% for Mr. Koonce. 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 Dominion’s 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 the company, which include the company’s 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 the company’s 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.

 

 

80        

 



Table of Contents

 

 

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 NEO’s 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, 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
    

Change in

Pension Value
and Nonqualified
Deferred
Compensation
Earnings(4)

     All Other
Compensation(5)
     Total  

Thomas F. Farrell II

Chairman, President and

CEO

     2015       $ 16,211       $ 49,489       $ 39,714       $       $ 2,010       $ 107,424   
     2014         8,530         34,441         60,656                 1,064         104,691   

Mark F. McGettrick

Executive Vice President and

CFO

     2015         15,670         22,424         20,291         407         1,903         60,695   

Paul D. Koonce*

Executive Vice President and

CEO – Energy Infrastructure Group and President – Dominion Virginia Power

     2015         31,146         34,374         31,860                 3,584         100,964   

 

* Effective January 1, 2016, Mr. Koonce began serving as Executive Vice President and CEO – Dominion Generation Group.

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, 2015, Mr. McGettrick received a 10% base salary increase, and the remaining NEOs each received a 3% base salary increase.
(2) The amounts in this column reflect the grant date fair value of stock awards for the respective year of grant in accordance with Financial Accounting Standards Board guidance for share-based payments. Dominion did not grant any stock options in 2015. See also Note 19 to the Consolidated Financial Statements in Dominion’s 2015 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 2015, and the Outstanding Equity Awards at Fiscal Year-End table for a listing of all outstanding equity awards as of December 31, 2015.
(3) The 2015 amounts in this column include the payout under Dominion’s 2015 AIP and 2014 performance grant awards. All of the NEOs received 20% funding of their 2015 AIP target awards and Messrs. Farrell, McGettrick, and Koonce received 100% payout scores for accomplishment of their goals. The 2015 AIP payout amounts were as follows: Mr. Farrell: $4,075; Mr. McGettrick: $3,182; and Mr. Koonce: $5,634. See CD&A for additional information on the 2015 AIP and the Grants of Plan-Based Awards table for the range of each NEO’s potential award under the 2015 AIP. The 2014 performance grant award was issued on February 1, 2014 and the payout amount was determined based on achievement of performance goals for the performance period ended December 31, 2015. Payouts can range from 0% to 200% of the target amount. The actual payout was 76.3% of the target amount. The 2014 performance grant payout amounts were as follows: Mr. Farrell: $35,638; Mr. McGettrick: $17,109; and Mr. Koonce: $26,227. See 2014 Performance Grant Payout of CD&A for additional information on the 2014 performance grants. The 2014 amount for Mr. Farrell reflects both the 2014 AIP and the 2013 performance grant payouts.
(4) All amounts in this column are for the aggregate change in the actuarial present value of the NEO’s accumulated benefit under Dominion’s 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 NEO’s 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 applied to us last year, we did not include this column in the Summary Compensation Table in Dominion Midstream’s 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 increased from 4.40% used as of December 31, 2014 to a discount rate of 4.96% used as of December 31, 2015. The decrease in present value attributed solely to the change in discount rate was as follows: Mr. Farrell: $12,090; Mr. McGettrick: $12,874; and Mr. Koonce: $19,782.

 

        81

 



Table of Contents

 

 

(5) All Other Compensation amounts for 2015 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

   $ 1,064       $ 327       $ 88       $ 531       $ 2,010   

Mark F. McGettrick

     584         692         203         424         1,903   

Paul D. Koonce

     1,262         1,387         375         560         3,584   

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 $827 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 95% 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, 2015.

 

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

                    

2015 AIP(2)

         $       $ 20,376       $ 40,751         

2015 Cash Performance Grant(3)

                   49,489         98,977         

2015 Restricted Stock Grant(4)

     2/1/2015         1/22/2015                  644       $ 49,489   

Mark F. McGettrick

                    

2015 AIP(2)

                   15,911         31,882         

2015 Cash Performance Grant(3)

                   22,423         44,847         

2015 Restricted Stock Grant(4)

     2/1/2015         1/22/2015                  292         22,424   

Paul D. Koonce

                    

2015 AIP(2)

                   28,168         56,336         

2015 Cash Performance Grant(3)

                   34,373         68,746         

2015 Restricted Stock Grant(4)

     2/1/2015         1/22/2015                                    447         34,374   

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 22, 2015, the CGN Committee approved the 2015 long-term incentive compensation awards for Dominion officers, which consisted of a restricted stock grant and a cash performance grant. The 2015 restricted stock award was granted on February 1, 2015. 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 1, 2015 restricted stock grant was $76.89 per share, which was Dominion’s closing stock price on January 30, 2015.
(2) Amounts represent the range of potential payouts under the 2015 AIP. Actual amounts paid under the 2015 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 NEO’s 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 2015 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 2015 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, 2017 depending on the achievement of performance goals for the two-year period ending December 31, 2016. The amount earned will depend on the level of achievement of two performance metrics: TSR—50% and ROIC—50%. TSR measures Dominion’s share performance for the two-year period ended December 31, 2016 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 2015 and 2016 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 officer’s 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.

 

82        

 



Table of Contents

 

 

In the case of death or disability, payout is made as soon as possible to facilitate the administration of the officer’s estate or financial planning. The payout amount will be the greater of the officer’s target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominion’s 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 officer’s target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominion’s financial statements.

 

(4) The 2015 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 officer’s 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 officer’s 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 as of December 31, 2015. These equity awards are restricted shares of Dominion common stock. There were no unexercised or unexercisable option awards outstanding for any of our NEOs as of December 31, 2015.

 

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

     862 (2)    $ 58,323   
     688 (3)      46,523   
     644 (4)      43,535   

Mark F. McGettrick

     414 (2)      28,000   
     330 (3)      22,335   
     292 (4)      19,727   

Paul D. Koonce

     635 (2)      42,923   
     506 (3)      34,239   
     447 (4)      30,238   

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 $67.64 on December 31, 2015.
(2) Shares scheduled to vest on February 1, 2016.
(3) Shares scheduled to vest on February 1, 2017.
(4) Shares scheduled to vest on February 1, 2018.

OPTION EXERCISES AND STOCK VESTED

The following table provides information about the value realized by NEOs during the year ended December 31, 2015, on vested restricted stock awards. There were no option exercises by NEOs in 2015.

 

Name

   Stock Awards  
   Number of Shares Acquired
on Vesting
     Value Realized on Vesting  

Thomas F. Farrell II

     2.357       $ 166,822   

Mark F. McGettrick

     1,623         113,052   

Paul D. Koonce

     2,405         167,529   

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.

 

 

        83

 



Table of Contents

 

 

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 as of December 31, 2015, using the same interest rate and mortality assumptions used in determining the aggregate pension obligations disclosed in the company’s 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      20.00       $  14,460   
   Benefit Restoration Plan      30.00         138,255   
   Supplemental Retirement Plan      30.00         147,213   

Mark F. McGettrick

   Pension Plan      30.00         35,651   
   Benefit Restoration Plan      30.00         114,505   
   Supplemental Retirement Plan      30.00         138,998   

Paul D. Koonce

   Pension Plan      17.00         43,845   
   Benefit Restoration Plan      17.00         71,067   
   Supplemental Retirement Plan      17.00         273,397   

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, 2015. Service for the Benefit Restoration Plan and the Supplemental Retirement Plan is the NEO’s actual credited service as of December 31, 2015 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 $56,344 lower for Mr. Farrell and $29,011 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 participant’s 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

 

 

84        

 



Table of Contents

 

 

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 2015, 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 2015, this limitation was the lesser of (i) $210,000 or (ii) the average of the participant’s 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 participant’s BRP benefit is calculated using the same formula (except that the IRS salary limit is not applied) used to determine the participant’s 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 participant’s 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 participant’s 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 participant’s 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 participant’s 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 participant’s lifetime. To accommodate the enactment of Section 409A of the IRC, the portion of a participant’s 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

 

 

        85

 



Table of Contents

 

 

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, McGettrick and Koonce 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 Code and Pension Benefit Guaranty Corporation 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, 2015, benefit calculations shown in the Pension Benefits table include a discount rate of 4.96% to determine the present value of the future benefit obligations for the Pension Plan, BRP and ESRP and a lump sum interest rate of 4.21% 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. Assumed mortality after retirement is based on tables from the Society of Actuaries’ RP-2000 study, projected from 2000 to a point five years beyond the calculation date (this year, to 2020) with 100% of the Scale AA factors, and further adjusted for Dominion experience by using an age set-forward factor. 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 Dominion’s Administrative Benefits Committee and adjusted periodically. For 2015, a 3.56% 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 Pension Benefit Guaranty Corporation in October of the previous five years.

NONQUALIFIED DEFERRED COMPENSATION

 

Name   

Aggregate

Earnings

in Last
FY(as of 12/31/2015)*

   

Aggregate
Withdrawals/

Distributions

(as of
12/31/2015)

    

Aggregate
Balance

at Last FYE

(as of
12/31/2015)

 

Thomas F. Farrell II

   $      $       $   

Mark F. McGettrick

                      

Paul D. Koonce

     (4,923             85,453   

*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 Consolidated Natural Gas Company 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 following funds had rates of returns for 2015 as follows: Dominion Resources Stock Fund, (8.7)%; and Dominion Fixed Income Fund, 2.9%.

The Dominion Fixed Income Fund is an investment option that provides a fixed rate of return each year based on a formula that is tied to the adjusted federal long-term rate published by the IRS in November prior to the beginning of the year. Dominion’s Asset Management Committee determines the rate based on its estimate of the rate of return on Dominion assets in the trust for the Frozen Deferred Compensation Plan.

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

 

 

86        

 



Table of Contents

 

 

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, the company 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 executive’s salary, incentive compensation or job responsibility is reduced after a change in control or the executive’s 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 Dominion’s or its successor’s Board within two years after the last of such transactions.

If an executive’s 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 officer’s 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, as of December 31, 2015. 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.

 

 

        87

 



Table of Contents

 

 

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

   $       $ 99,729       $ 23,668       $ 16,300       $       $       $       $       $ 139,697   

Death/Disability

             99,728         23,668                                                 123,396   

Change in Control(5)

             48,653         25,820                 108,247                 278                 182,998   

Mark F. McGettrick(4)

                          

Retirement(6)

             47,516         10,724                                                 58,240   

Change in Control(5)

             22,545         11,699                 91,128                 480                 125,852   

Paul D. Koonce(4)

                          

Retirement(6)

             72,843         16,439                                                 89,282   

Change in Control(5)

     83,599         34,558         17,934                 175,427         4,277         1,179                 316,974   

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 2013, 2014 and 2015 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 NEO’s 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 $67.64 on December 31, 2015.
(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. Mr. Koonce is entitled to executive life insurance coverage upon termination because he has reached age 55 and has 10 years of service. Mr. Koonce is eligible for retiree medical upon a change in control.
(4) All the NEOs 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, 2015. 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.
(6) These amounts would also be received in the event of termination due to death or disability.

 

88        

 



Table of Contents

 

 

 

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 11, 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, Dominion’s 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 $60,000 and an annual equity retainer equal to $65,000 for 2015. The chair of each standing committee of the general partner’s 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 director’s 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 2015. Messrs. Farrell and McGettrick do not receive any separate compensation for their services as directors.

 

 

2015 NON-EMPLOYEE DIRECTOR COMPENSATION

 

Name    Fees earned or paid in cash      Stock Awards(1)      Total  

Joseph M. Rigby

   $ 75,000       $ 65,000       $ 140,000   

John W. Snow

     60,000         65,000         125,000   

David A. Wollard

     75,000         65,000         140,000   

All directors

   $ 210,000       $ 195,000       $ 405,000   

 

(1) Each of the non-employee directors received an annual equity retainer valued at approximately $65,000, which was equal to 1,685 units, valued at $38.58 per unit based on the closing price of Dominion Midstream common units on January 2, 2015. A total of 5,055 units, in aggregate, were distributed to these directors for their annual equity retainers.

No options have been granted to directors.

 

 

 

        89

 



Table of Contents

 

 

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 and subordinated units of Dominion Midstream held by beneficial owners of five percent or more of the units, by each director and named executive officer of our general partner, and by the directors and executive officers of our general partner as a group as of February 15, 2016. 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 45,722,371 common units and 31,972,789 subordinated units as of February 15, 2016.

 

Name of Beneficial Owner   

Common

Units
Beneficially
Owned

     Percentage of
Common Units
Beneficially
Owned
    Subordinated Units
Beneficially Owned
     Percentage of
Subordinated Units
Beneficially Owned
    Percentage of
Common and
Subordinated Units
Beneficially Owned
 

Dominion Resources, Inc.(1)

     18,223,983         39.9     31,972,789         100     64.6

National Grid PLC(2)

     6,783,373         14.8                       8.7   

Tortoise Capital Advisors, L.L.C.(3)

     2,788,028         6.1                       3.6   

Thomas F. Farrell II

     69,900         *                       *   

Mark F. McGettrick

     64,900         *                       *   

Paul D. Koonce(4)

     50,000         *                       *   

Joseph M. Rigby

     10,046         *                       *   

John W. Snow

     72,546         *                       *   

David A. Wollard

     20,846         *                       *   

All executive officers and directors as a group (9 persons)(4)(5)

     256,938         *                       *   

 

* Less than 1 percent.
(1) 11,847,789 common units and 31,972,789 subordinated units are directly held by Dominion MLP Holding Company, LLC. An additional 5,112,139 common units are directly held by Dominion MLP Holding Company II, Inc. and 1,264,055 common units are held directly by Dominion MLP Holding Company III, Inc. Dominion is the ultimate parent company of the general partner and Dominion MLP Holding Company, LLC, Dominion MLP Holding Company II, Inc. and Dominion MLP Holding Company III, Inc., and may be deemed to beneficially own the common units and subordinated units directly held by Dominion MLP Holding Company, LLC.
(2) 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.
(3)Tortoise Capital Advisors, L.L.C., 11550 Ash Street, Suite 300, Leawood, Kansas 66211, filed a Schedule 13G with the SEC on February 9, 2016, reporting that it has sole voting or dispositive power over 57,412 common units, shared voting power over 2,544,065 common units, and shared dispositive power over 2,730,616 common units.
(4) As of January 1, 2016, Mr. Koonce is no longer an officer of Dominion Midstream GP, LLC and is not included in the group total. Mr. Christian was appointed Executive Vice President of Dominion Midstream GP, LLC effective January 1, 2016. Mr. Christian owns 13,200 common units which are included in the group total.
(5) No individual director or executive officer has the right to acquire beneficial ownership of units within 60 days of February 15, 2016. 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.

 

90        

 



Table of Contents

 

 

The following table sets forth the number of shares of Dominion common stock beneficially owned as of February 15, 2016 by each director of our general partner, by each named executive officer 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

     820,526                 192,903         1,013,429         *   

Mark F. McGettrick

     248,802                 51,633         300,435         *   

Paul D. Koonce(2)

     112,710                 32,195         144,905         *   

David A. Wollard

     16,148         19,838                 35,986         *   

Joseph M. Rigby

                                     *   

John W. Snow

     4,075                         4,075         *   

All directors and executive officers as a group (9 persons)(3)

     1,263,135         19,838         298,151         1,581,124         *   

 

* Less than 1 percent.
(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) As of January 1, 2016, Mr. Koonce is no longer an officer of Dominion Midstream GP, LLC and is not included in the group total. Mr. Christian was appointed Executive Vice President of Dominion Midstream GP, LLC effective January 1, 2016. Mr. Christian owns 101,266 shares and 32,195 restricted shares which are included in the group total.
(3) No individual director or executive officer has the right to acquire beneficial ownership of shares within 60 days of February 15, 2016. 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, 20,000 (shares held jointly); Mr. Snow, 4,075 (shares held jointly); and all directors and executive officers as a group, 24,075.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2015 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

                     2,992,623   

Total

                     2,992,623   

 

        91

 



Table of Contents

 

 

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 partner’s 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

As of February 15, 2016, Dominion owned 18,223,983 common units and all of our 31,972,789 subordinated units, representing an aggregate of approximately 64.6% 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, Koonce and Blue and Ms. 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.

 

 

92        

 



Table of Contents

 

 

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 arm’s 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.

Other Transactions with Related Persons

Virginia Power Services Energy Corp., Inc., a subsidiary of Dominion, is one of Cove Point’s 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.

 

 

        93

 



Table of Contents

 

 

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 Midstream’s 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 party’s only relationship is as an employee, if the aggregate amount involved does not exceed the greater of $1 million or 2% of that company’s gross revenues; and charitable contributions which are less than the greater of $1 million or 2% of the charity’s 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 Midstream’s Code of Ethics.

Since January 1, 2015, there have been no related party transactions involving Dominion Midstream that were required either to be approved under Dominion Midstream’s 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, 2015 and 2014.

 

Type of Fees    2015      2014  
(millions)              

Audit fees

   $ 0.73       $ 0.10   

Audit-related fees

               

Tax fees

               

All other fees

               
     $ 0.73       $ 0.10   

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 fees presented above for the year ended December 31, 2014, were for professional services rendered during the period subsequent to the Offering. Total audit fees incurred prior to the Offering were $0.69 million and were paid by Dominion.

The Audit Committee has adopted a pre-approval policy for its independent auditor’s 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 LLP’s 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.

 

 

94        

 



Table of Contents

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 45.

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 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 August 14, 2015 (Exhibit 2.2, Form 8-K filed August 17, 2015, 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    First Amended and Restated Agreement of Limited Partnership of Dominion Midstream Partners, LP, dated October 20, 2014, by and between Dominion Midstream GP, LLC and Dominion MLP Holding Company, LLC (Exhibit 3.1, Form 8-K filed October 20, 2014, 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).
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).

 

        95

 



Table of Contents

 

 

Exhibit

Number

  

Description

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†    Acknowledgement 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 (filed herewith).
10.16*    Form of Restricted Unit Award Agreement for Non-Employee Directors under the 2014 Long-Term Incentive Plan approved December 18, 2015 (filed herewith).
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 Midstream’s Annual Report on Form 10-K for the year ended December 31, 2015, filed on February 26, 2016, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Equity and Partners’ Capital (iv) Consolidated Statements of Cash Flows, and (v) 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.

 

96        

 



Table of Contents

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 26, 2016

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 26th day of February, 2016.

 

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/    Mark F. McGettrick        

Mark F. McGettrick

   Director, Executive Vice President and Chief Financial Officer of Dominion Midstream GP, LLC

/s/    Joseph M. Rigby        

Joseph M. Rigby

   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

 

        97

 



Table of Contents

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 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 August 14, 2015 (Exhibit 2.2, Form 8-K filed August 17, 2015, 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    First Amended and Restated Agreement of Limited Partnership of Dominion Midstream Partners, LP, dated October 20, 2014, by and between Dominion Midstream GP, LLC and Dominion MLP Holding Company, LLC (Exhibit 3.1, Form 8-K filed October 20, 2014, 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).
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†    Acknowledgement 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).

 

98        

 



Table of Contents

 

 

Exhibit

Number

  

Description

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 (filed herewith).
10.16*    Form of Restricted Unit Award Agreement for Non-Employee Directors under the 2014 Long-Term Incentive Plan approved December 18, 2015 (filed herewith).
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 Midstream’s Annual Report on Form 10-K for the year ended December 31, 2015, filed on February 26, 2016, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Equity and Partners’ Capital (iv) Consolidated Statements of Cash Flows, and (v) 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.

 

        99